10-K

Table of Contents f WTI

​

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

​	​
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
​
For the fiscal year ended: December 31, 2020
​	​
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
​	​
For the transition period from to

Commission file number: 001-38005

Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)

​	​	​
Delaware<br>(State or other jurisdiction of<br>incorporation or organization)	1311<br>(Primary Standard Industrial<br>Classification Code Number)	47-5505475<br>(I.R.S. Employer<br>Identification No.)

​

777 Taylor Street, Suite 810

Fort Worth , Texas **** 76102

( 817 ) 945-9700

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Securities registered pursuant to Section 12(b) of the Exchange Act:

​	​	​	​	​
Title of class	​	Trading Symbol	​	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	​	KRP	​	New York Stock Exchange

​

Securities registered pursuant to Section 12(g) of the Exchange Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒  No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒  No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	​	Accelerated filer	☒
Non-accelerated filer	☐	​	Smaller reporting company	☐
Emerging growth company	☒	​	​	​
​	​		​	​

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of the registrant’s common units held by non-affiliates of the registrant as of June 30, 2020, was $420.8 million, based on the closing price of such common units of $8.60 as reported on the New York Stock Exchange on June 30, 2020. As of February 19, 2021, the registrant had outstanding 38,918,689 common units representing limited partner interests and 20,779,781 Class B units representing limited partner units.

Documents Incorporated by Reference: None

​

​

Table of Contents Kimbell Royalty Partners, LP

​

TABLE OF CONTENTS

​
PART I
Item 1. Business	9
Item 1A. Risk Factors	32
Item 1B. Unresolved Staff Comments	71
Item 2. Properties	71
Item 3. Legal Proceedings	71
Item 4. Mine Safety Disclosures	71
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	72
Item 6. Selected Financial Data	76
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	81
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	98
Item 8. Financial Statements and Supplementary Data	99
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	99
Item 9A. Controls and Procedures	99
Item 9B. Other Information	100
PART III
Item 10. Directors, Executive Officers and Corporate Governance	100
Item 11. Executive Compensation	105
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	114
Item 13. Certain Relationships and Related Transactions, and Director Independence	118
Item 14. Principal Accounting Fees and Services	126
PART IV
Item 15. Exhibits, Financial Statement Schedules	127
Item 16. Form 10-K Summary	131
Signatures	132

​

​

​

​

​ i

Table of Contents GLOSSARY OF TERMS

The following are definitions of certain terms used in this Annual Report on Form 10-K (“Annual Report”).

Basin. A large depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil at the pressure and temperature base standard of each respective state in which the gas is produced.

Boe/d. Boe per day.

British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Electrical log. Provide information on porosity, hydraulic conductivity and fluid content of formations drilled in fluid-filled boreholes.

Exploration. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves).

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

2

Table of Contents

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.

Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

MBbl/d. MBbl per day.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.

Mcf. One thousand cubic feet of natural gas.

Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for and produce oil and natural gas on that land or to lease those exploration and development rights to a third party.

MMBtu. One million British Thermal Units.

MMcf. One million cubic feet of natural gas.

Net acres. The sum of the fractional working interest owned in gross acres.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty and other non-cost-bearing interests.

Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.

Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Nonparticipating royalty interest. A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.

Oil. Crude oil and condensate.

Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.

3

Table of Contents

Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease. Refers to the operator of record and any lessor or working interest holder for which the operator is acting.

Overriding royalty interest or ORRI. A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation or maintenance.

Pad drilling. The practice of drilling multiple wellbores from a single surface location.

PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Pooling. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.

Production costs. The production or operational costs incurred while extracting and producing, storing and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes and insurance.

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.

Proved reserves. The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

4

Table of Contents

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

SCOOP. South Central Oklahoma Oil Province.

Secondary recovery. The second stage of hydrocarbon production during which an external fluid, such as water or gas, is injected into the reservoir through injection wells located in rock that has fluid communication with production wells.

Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth’s surface and a receiver is used to collect and record these reflections.

Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

STACK. Sooner Trend, Anadarko Basin, Canadian and Kingfisher counties, Oklahoma.

Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

Tertiary recovery. Traditionally, the third stage of hydrocarbon production, comprising recovery methods that follow waterflooding or pressure maintenance. The principal tertiary recovery techniques used are thermal methods, gas injection and chemical flooding.

Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.

5

Table of Contents

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore. The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.

Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, of API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils.

​ 6

Table of Contents Cautionary Statement Regarding Forward-Looking Statements

Certain statements and information in this Annual Report may constitute forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

●	our ability to replace our reserves;
●	our ability to make, consummate and integrate acquisitions of assets or businesses and realize the benefits or effects of any acquisitions or the timing, final purchase price or consummation of any acquisitions;
---	---
●	our ability to execute our business strategies;
---	---
●	the volatility of realized prices for oil, natural gas and NGLs, including as a result of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries;
---	---
●	the level of production on our properties;
---	---
●	the level of drilling and completion activity by the operators of our properties;
---	---
●	regional supply and demand factors, delays or interruptions of production;
---	---
●	industry, economic, business or political conditions, including any energy and environmental proposals supported by the Biden administration and/or the United States Congress, weakness in the capital markets or the ongoing and potential impact to financial markets and worldwide economic activity resulting from the ongoing coronavirus (“COVID-19”) pandemic and related governmental actions;
---	---
●	revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;
---	---
●	impacts of impairment expense on our financial statements;
---	---
●	competition in the oil and natural gas industry generally and the mineral and royalty industry in particular;
---	---
●	the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;
---	---
●	title defects in the properties in which we acquire an interest;
---	---
●	uncertainties with respect to identified drilling locations and estimates of reserves on our properties and on properties we seek to acquire;
---	---
●	the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;
---	---
●	restrictions on or the availability of the use of water in the business of the operators of our properties;
---	---

7

Table of Contents

●	the availability of transportation facilities;
●	the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
---	---
●	federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry, including the Biden administration’s proposals and recent executive orders focused on addressing climate change;
---	---
●	future operating results;
---	---
●	exploration and development drilling prospects, inventories, projects and programs;
---	---
●	operating hazards faced by the operators of our properties;
---	---
●	the ability of the operators of our properties to keep pace with technological advancements;
---	---
●	uncertainties regarding United States federal income tax law, including the treatment of our future earnings and distributions;
---	---
●	our ability to maintain effective internal controls over financial reporting and disclosure controls and procedures; and
---	---
●	certain factors discussed elsewhere in this Annual Report.
---	---

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

​

​ 8

Table of Contents PART I

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “our Partnership,” “we,” “our,” “us” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to “our General Partner” refer to Kimbell Royalty GP, LLC. References to “our Sponsors” refer to affiliates of our founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to “Kimbell Holdings” refer to Kimbell GP Holdings, LLC, a jointly owned subsidiary of our Sponsors and the parent of our General Partner. References to the “Contributing Parties” refer to all entities and individuals, including affiliates of our Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to us at the closing of our initial public offering (“IPO”). References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of our General Partner, which has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties as described herein.

​

Item 1. Business

Overview

We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, we have elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest. 9

Table of Contents The diagram below depicts a simplified version of our organizational structure as of February 19, 2021:

(1)	The Sponsors are affiliates of our founders, Messrs. Fortson, R. Ravnaas, Taylor and Wynne.
(2)	Includes common units beneficially owned by the Sponsors other than those reflected as held by Kimbell GP Holdings, LLC. Also includes common units beneficially owned by our directors and officers and other of our affiliates.
---	---
(3)	Includes the Kimbell Art Foundation, Cupola Royalty Direct LLC, Rivercrest Capital Partners LP and certain affiliates of EnCap Partners, LP, Buckhorn Resources GP, LLC, Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC.
---	---
(4)	Kimbell Operating has entered into a management services agreement with us and separate management services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties for the provision of certain management, administrative and operational services.
---	---

10

Table of Contents Significant Acquisitions

On July 12, 2018, we completed the acquisition (the “Haymaker Acquisition”) of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (together, “Haymaker Sellers”) for a total of 10,000,000 common units representing limited partner interests in us (“common units”) and approximately $208.6 million in cash. The assets acquired in the Haymaker Acquisition consist of approximately 5.4 million gross acres and 43,000 net royalty acres.

On December 20, 2018, we completed the acquisition (the “Dropdown”) of certain overriding royalty, royalty and other mineral interests from Rivercrest Capital Partners LP, the Kimbell Art Foundation and Cupola Royalty Direct, LLC (collectively, the “Asset Sellers”), as well as all of the equity interests of a subsidiary of Rivercrest Royalties Holdings II, LLC (together with the Asset Sellers, the “Dropdown Sellers”) in exchange for a total of 6,500,000 common units representing limited liability interests in the Operating Company (“OpCo common units”) and an equal number of Class B units representing limited partner interests in us (“Class B units”). The assets acquired in the Dropdown consist of approximately 1.0 million gross acres and 16,700 net royalty acres.

On March 25, 2019, we completed the acquisition (the “Phillips Acquisition”) of all of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC (collectively, the “Phillips Sellers”). The aggregate consideration for the Phillips Acquisition consisted of 9,400,000 OpCo common units and an equal number of Class B units. The assets acquired in the Phillips Acquisition consist of approximately 866,528 gross acres and 12,210 net royalty acres.

On April 17, 2020, we completed the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”) from the owners of such entities (collectively, the “Springbok Sellers”). The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, (ii) the issuance of 2,224,358 common units and (iii) the issuance of 2,497,134 OpCo common units and an equal number of Class B units. At the time of the Springbok Acquisition, the acreage acquired had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other leading basins.

Our Oil and Gas Assets

We categorize our oil and gas assets into two groups: mineral interests and overriding royalty interests.

Mineral Interests

Mineral interests are real property interests that are typically perpetual and grant ownership to all the oil and natural gas lying below the surface of the property, as well as the right to explore, drill and produce oil and natural gas on that property or to lease such rights to a third party. Mineral owners typically grant oil and gas leases to operators for an initial three-year term with an upfront cash payment to the mineral owners known as a lease bonus. Under the lease, the mineral owner retains a royalty interest entitling it to a cost-free percentage (usually ranging from 20-25%) of production or revenue from production. The lease can be extended beyond the initial term with continuous drilling, production or other operating activities. When production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party. We also own royalty interests that have been carved out of mineral interests and are known as nonparticipating royalty interests. Nonparticipating royalty interests are typically perpetual and have rights similar to mineral interests, including the right to a cost-free percentage of production revenues for minerals extracted from the acreage, without the associated executive right to lease and the right to receive lease bonuses.

We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest. For example, we receive similar royalties from operators with respect to our mineral interests or nonparticipating royalty interests as long as such interests are subject to an oil and gas lease. When evaluating our business, our management team does not distinguish between mineral and nonparticipating royalty interests on leased acreage due to the similarity of the royalties received by the interests. 11

Table of Contents

Overriding Royalty Interests

In addition to mineral interests, we also own overriding royalty interests, which are royalty interests that burden the working interests of a lease and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. Overriding royalty interests typically remain in effect until the associated lease expires and, because substantially all the underlying leases are perpetual so long as production in paying quantities perpetuates the leasehold, substantially all of our overriding royalty interests are likewise perpetual.

Overview of Our Oil and Gas Assets and Operations

As of December 31, 2020, we owned mineral and royalty interests in approximately 9.1 million gross acres and overriding royalty interests in approximately 4.6 million gross acres, with approximately 60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of December 31, 2020, over 98% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 97,000 gross wells, including over 41,000 wells in the Permian Basin. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we benefit from the continued development of the properties in which we own an interest without the need for investment of additional capital by us.

As of December 31, 2020, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 42,418 MBoe 43.3% liquids, consisting of 66.9% oil and 33.1% NGLs) based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”). All of our reserves were classified as PDP reserves. The properties underlying our mineral and royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated yearly decline rate of 12.5% during the initial five-years.

Our revenues are derived from royalty payments we receive from the operators of our properties based on the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. As of December 31, 2020, there were approximately 1,300 operators actively producing on our acreage, with our top ten operators (Chevron USA, Inc., EOG Resources, Inc., Chesapeake Operating, Inc., Vine Oil & Gas, LP, EP Energy E&P Company, LP, Occidental Petroleum Corporation, GEP Haynesville, LLC, Parsley Energy Operations, LLC, Devon Energy Production Company and XTO Energy, Inc.) together accounting for approximately 35.6% of our revenues.

During the years ended December 31, 2020, 2019 and 2018, payments we received from our top purchaser accounted for approximately 7.1%, 6.0% and 10.5%, respectively, of our revenues. We do not believe that the loss of any individual purchaser would have a material adverse effect on us due to the high number of purchasers actively producing on our acreage. As of December 31, 2020, there were 39 rigs operating on our acreage compared to 81 rigs operating on our acreage as of December 31, 2019. The decrease in rig count was primarily attributable to the COVID-19 outbreak and international supply and demand imbalances. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Business Environment — COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas” for further discussion.

Our revenues and the amount of cash available for distribution on common units may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. For the year ended December 31, 2020, our revenues were generated 56% from oil sales, 34% from natural gas sales, 9% from NGL sales and 1% from other sales. 12

Table of Contents Business Strategies

Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest. We intend to accomplish this objective by executing the following strategies:

●

Acquire additional mineral and royalty interests from third parties and leverage our relationships with our Sponsors and the Contributing Parties to grow our business. We intend to make opportunistic acquisitions of mineral and royalty interests that have substantial resource and organic growth potential and meet our acquisition criteria, which include (i) mineral and royalty interests in high-quality producing acreage that enhance our asset base, (ii) significant amounts of recoverable oil and natural gas in place with geologic support for future production and reserve growth and (iii) a geographic footprint complementary to our diverse portfolio. For example, on April 17, 2020, we completed the Springbok Acquisition, through which we acquired 2,160 net royalty acres, increasing our acreage footprint.

We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties. We have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. We believe this arrangement will give us access to third-party acquisition opportunities we might not otherwise be in a position to pursue. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.”

●	Acquire additional mineral and royalty interests from our Sponsors and the Contributing Parties. The Contributing Parties, including affiliates of our Sponsors, continue to own significant mineral and royalty interests in oil and gas properties. We believe our Sponsors and the Contributing Parties view our partnership as part of their growth strategy. In addition, we believe their direct or indirect ownership in us will incentivize them to offer us additional mineral and royalty interests from their existing asset portfolios in the future. For example, we acquired some mineral and royalty interests subject to the right of first refusal granted in connection with our IPO (which has since expired) in the Dropdown. The Contributing Parties have no obligation to sell any additional assets to us or to accept any offer that we may make for any additional assets, and we may decide not to acquire such additional assets even if such Contributing Parties offer them to us. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.”
●	Benefit from reserve, production and cash flow growth through organic production growth and development of our mineral and royalty interests. Our assets consist of diversified mineral and royalty interests. As of December 31, 2020, 67% of our well count are located in the Permian Basin, Mid-Continent and DJ Basin/Rockies/Niobrara and 60% of our gross acreage are located in the Permian Basin, Mid-Continent and Bakken/Williston Basin, which are some of the most active areas in the country. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. As such, we benefit from the continued development of the properties we own a mineral or royalty interest in without the need for investment of additional capital by us.
---	---
●	Maintain a conservative capital structure and prudently manage our business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. The limited liability company agreement of our General
---	---

13

Table of Contents

Partner contains provisions that prohibit certain actions without a supermajority vote of at least 66^2^/3% of the members of the General Partner’s Board of Directors (the “Board of Directors”). Among the actions requiring a supermajority vote are the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio (as defined in our General Partner’s limited liability company agreement) for the preceding four quarters and the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units. In addition, pursuant to the terms of our partnership agreement, we are prohibited from the issuance of any partnership interests that rank equal or senior in right of distributions or liquidation to our Series A Cumulative Convertible Preferred Units (“Series A preferred units”) without the consent of the holders of 66^2^/3% of the outstanding Series A preferred units.

We have a $265.0 million secured revolving credit facility with an elected commitment amount feature permitting aggregate commitments under the secured revolving credit facility to be increased to up to $500.0 million, subject to the limitations of our borrowing base, which is currently $265.0 million, and the satisfaction of certain conditions, including the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders. During the year ended December 31, 2020, the Board of Directors approved the repayment of $25.1 million in outstanding borrowings under our secured revolving credit facility, which reduced our cash available for distribution on common units. Of the $25.1 million, $3.9 million was approved in connection with the fourth quarter distribution and will be repaid in the first quarter of 2021. With respect to future quarters, the Board of Directors may continue to allocate cash generated by our business to the repayment of outstanding borrowings under our secured revolving credit facility. We believe that this liquidity, along with internally generated cash from operations and access to capital markets, will provide us with the financial flexibility to grow our production, reserves and cash generated from operations through strategic acquisitions of mineral and royalty interests and the continued development of our existing assets.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

●	Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to undeveloped opportunities. We have a diversified, low decline asset base with exposure to high-quality conventional and unconventional plays. As of December 31, 2020, we owned mineral and royalty interests in approximately 9.1 million gross acres and overriding royalty interests in approximately 4.6 million gross acres, with approximately 60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin, and as of December 31, 2020, over 98% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. The estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 42,418 MBoe (43.3% liquids, consisting of 66.9% oil and 33.1% NGLs) based on the reserve report prepared by Ryder Scott. All of our reserves were classified as PDP reserves. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays without further required investment on our behalf. We believe that we will continue to benefit from these cost-free additions to production and reserves for the foreseeable future as a result of technological advances and continuing interest by third-party producers in development activities on our acreage.
●	Exposure to many of the leading resource plays in the United States. We expect the operators of our properties to continue to drill new wells and to complete drilled but uncompleted wells on our acreage, which we believe should substantially offset the natural production declines from our existing wells. We believe that our operators have significant drilling inventory remaining on the acreage underlying our mineral or royalty interests in multiple resource plays. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 97,000 gross wells, including over 41,000 wells in the Permian Basin.
---	---

14

Table of Contents

●	Financial flexibility to fund expansion. We believe that our conservative capital structure will permit us to maintain financial flexibility to allow us to opportunistically purchase strategic mineral and royalty interests, subject to the supermajority vote provisions of the limited liability company agreement of our General Partner and the terms of our partnership agreement, which in certain circumstances requires the affirmative vote of 66^2^/3% of our outstanding Series A preferred units, in each case as discussed above. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness” for further information. We believe that we will be able to expand our asset base through acquisitions utilizing our secured revolving credit facility, internally generated cash from operations and access to capital markets.
●	Experienced and proven management team with a track record of making acquisitions. The members of our management team and Board of Directors have an average of over 30 years of oil and gas experience. Our management team and Board of Directors, which includes our founders, have a long history of buying mineral and royalty interests in high-quality producing acreage throughout the United States. Certain members of our management team have managed a significant investment program, investing in over 160 acquisitions. We believe we have a proven competitive advantage in our ability to source, engineer, evaluate, acquire and manage mineral and royalty interests in high-quality producing acreage.
---	---

Our Properties

Material Basins and Producing Regions

The following is an overview of the United States basins and producing regions we consider most material to our current and future business.

●	Permian Basin. The Permian Basin extends from southeastern New Mexico into west Texas and is currently one of the most active drilling regions in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin in between. The Permian Basin consists of mature legacy onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years. The extensive operating history, favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the United States. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin, and the Bone Springs formation in the Delaware Basin, which are among the most active plays in the country.
●	Mid-Continent. The Mid-Continent is a broad area containing hundreds of fields in Arkansas, Kansas, Louisiana, New Mexico, Oklahoma, Nebraska and Texas and including the Granite Wash, Cleveland and the Mississippi Lime formations. The Anadarko Basin is a structural basin centered in the western part of Oklahoma and the Texas Panhandle, extending into southwestern Kansas and southeastern Colorado. A key feature of the Anadarko Basin is the stacked geologic horizons including the Cana-Woodford and Springer shale in the SCOOP and STACK.
---	---
●	Terryville/Cotton Valley/Haynesville. We own a substantial position in the core of the Terryville Field that the Contributing Parties acquired in 2007. Our mineral interests are leased and operated by Range Resources Corporation/Memorial Resource Development Corp. Producing since 1954, the Terryville Field is one of the most prolific natural gas fields in North America. Redevelopment of the field with horizontal drilling and modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, and long reserve life with multiple stacked producing zones.
---	---
●	Appalachian Basin. The Appalachian Basin covers most of Pennsylvania, eastern Ohio, West Virginia, western Maryland, eastern Kentucky, central Tennessee, western Virginia, northwestern Georgia, and northern Alabama. The basin’s most active plays in which we have acreage are the Marcellus Shale and Utica plays, which cover most of Pennsylvania, northern West Virginia, and eastern Ohio. In addition to the Marcellus Shale and Utica plays, there are a number of other conventional and unconventional plays to which
---	---

15

Table of Contents

we have material exposure in the Appalachian Basin, including the Berea, Big Injun, Devonian, Huron and Rhinestreet.
●	Eagle Ford. The Eagle Ford shale formation stretches across south Texas and includes some of the most economic and productive areas in the United States. The Eagle Ford contains significant amounts of hydrocarbons and is considered the source rock, or the original source, for much of the oil and natural gas contained in the Austin Chalk Basin. The Eagle Ford shale formation has benefitted from improvements in horizontal drilling and hydraulic fracturing.
---	---
●	Bakken/Williston Basin. The Williston Basin stretches through North Dakota, the northwest part of South Dakota, and eastern Montana and is best known for the Bakken/Three Forks shale formations. The Bakken ranks as one of the largest oil developments in the United States in the past 40 years. Development of the Bakken became commercial on a large scale over the past ten years with the advent of horizontal drilling and hydraulic fracturing.
---	---
●	DJ Basin/Rockies/Niobrara. The Denver-Julesburg Basin, also known as the DJ Basin, is a geologic basin centered in eastern Colorado stretching into southeast Wyoming, western Nebraska and western Kansas. The area includes the Wattenberg Gas Field, one of the largest natural gas deposits in the United States, and the Niobrara formation. The Niobrara includes three separate zones and stretches from the DJ Basin up into the Powder River Basin in Wyoming. Development in this area is currently focused on horizontal drilling in the Niobrara and Codell formations.
---	---

The following tables present information about our mineral and royalty interest acreage, well count and production by basin and producing region. We may own more than one type of interest in the same tract of land. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.

Mineral Interests

The following table sets forth information about our mineral and nonparticipating royalty interests. We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest.

​	​	​	​	​	​	​	​
​	​	December 31, 2020
​	​	Gross	​	Net		Percent
Basin or Producing Region	​	Acres	​	Acres	​	Leased
Permian Basin (1)	​	2,372,057	​	19,254	​	99.2	%
Mid‑Continent		1,835,607	​	23,742		99.4	%
Terryville/Cotton Valley/Haynesville		665,164	​	6,481		99.3	%
Appalachian Basin (2)	​	434,116	​	16,967	​	99.8	%
Eagle Ford		476,193	​	5,059		96.8	%
Barnett Shale/Fort Worth Basin		316,408	​	3,548		99.1	%
Bakken/Williston Basin (3)		1,146,006	​	3,047		99.9	%
San Juan Basin		85,604	​	159		99.2	%
Onshore California		67,139	​	286		95.7	%
DJ Basin/Rockies/Niobrara		46,398	​	680		96.1	%
Illinois Basin		11,163	​	97		100.0	%
Other Western (onshore) Gulf Basin		614,310	​	4,247		98.0	%
Other TX/LA/MS Salt Basin		308,850	​	3,841		95.3	%
Other		677,086	​	3,306		99.1	%
Total (4)		9,056,101		90,714		99.0	%
(1)	Includes mineral interests in approximately 1,111,043 gross (7,868 net) acres in the Wolfcamp/Bone Spring.
---	---
(2)	Includes mineral interests in approximately 209,340 gross (5,637 net) acres in the Marcellus/Utica.
---	---
(3)	Includes mineral interests in approximately 1,035,464 gross (2,929 net) acres in the Bakken/Three Forks.
---	---
(4)	Percentage leased represents the weighted average of our leased acres relative to our total acreage in the basins in which we own mineral interests.
---	---

16

Table of Contents ORRIs

The following table sets forth information about our ORRIs:

​	​	​	​	​	​	​	​
​	​	December 31, 2020
​	​	Gross	​	Net	​	Percent
Basin or Producing Region	​	Acres	​	Acres	​	Producing
Permian Basin (1)	​	290,720		3,821		100.0	%
Mid‑Continent		2,119,541		17,660		99.1	%
Terryville/Cotton Valley/Haynesville		121,560		1,184		99.5	%
Appalachian Basin (2)	​	307,238	​	6,235	​	100.0	%
Eagle Ford		147,955		1,671		100.0	%
Barnett Shale/Fort Worth Basin		76,755		593		100.0	%
Bakken/Williston Basin (3)		423,631		3,004		100.0	%
San Juan Basin		98,633		1,313		99.0	%
Onshore California		10,668		22		100.0	%
DJ Basin/Rockies/Niobrara		27,754		356		100.0	%
Illinois Basin		16,848		1,080		100.0	%
Other Western (onshore) Gulf Basin		89,209		1,215		100.0	%
Other TX/LA/MS Salt Basin		45,502		1,443		99.9	%
Other		814,386		15,544		99.9	%
Total (4)		4,590,400		55,141		99.5	%
(1)	Includes overriding royalty interests in approximately 183,702 gross (1,946 net) acres in the Wolfcamp/Bone Spring.
---	---
(2)	Includes overriding royalty interests in approximately 254,348 gross (4,852 net) acres in the Marcellus/Utica.
---	---
(3)	Includes overriding royalty interests in approximately 409,439 gross (2,907 net) acres in the Bakken/Three Forks.
---	---
(4)	Percentage producing represents the weighted average of our acres that are producing relative to our total acreage in the basins in which we own ORRIs. Virtually all acreage is producing.
---	---

Wells

The following table sets forth the well count in which we had mineral or royalty interest:

​	​	​
Basin or Producing Region	​	December 31, 2020
Permian Basin	​	41,075
Mid‑Continent		11,267
Terryville/Cotton Valley/Haynesville		8,861
Appalachian Basin		3,208
Eagle Ford		3,235
Barnett Shale/Fort Worth Basin		3,966
Bakken/Williston Basin		4,124
San Juan Basin		1,857
Onshore California		975
DJ Basin/Rockies/Niobrara		12,359
Other		6,230
Total		97,157

​ 17

Table of Contents Production

The following table summarizes our production, as well as our estimate of the percentage of such production that we believe is attributable to conventional and unconventional production and enhanced oil recovery (“EOR”) as of December 31, 2020. We designate wells as either conventional or unconventional by reviewing the basin, field, and hole direction of each well, as well as the start date of the wells. In estimating the percentage of conventional wells that are subject to EOR, we compare forecasted production decline against historical production decline, as well as publicly available information related to injection volumes, operator information, unit size, well count and location. We estimate that approximately 21% of our total production as of December 31, 2020 is attributable to conventional assets including certain EOR projects. We believe this conventional production provides a base level of production stability that helps facilitate overall organic production growth as new unconventional wells come online.

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	Average Daily	​	Percentage of	​	​	Percentage of	​	​	Conventional Production(2)				​
​	​	Production	​	Conventional	​	​	Unconventional	​	​	Enhanced Oil	​	​	Non-Enhanced	​
Basin or Producing Region	​	(Boe/d)(6:1)(1)	​	Production	​	​	Production	​	​	Oil Recovery	​	​	Oil Recovery	​
Permian Basin	​	2,641	​	27.2	%	​	72.8	%	​	18.3	%	​	8.9	%
Mid‑Continent	​	1,740	​	27.0	%	​	73.0	%	​	1.9	%	​	25.1	%
Terryville/Cotton Valley/Haynesville	​	2,948	​	5.0	%	​	95.0	%	​	1.5	%	​	3.5	%
Appalachian Basin	​	1,955	​	10.5	%	​	89.5	%	​	0.3	%	​	10.2	%
Eagle Ford	​	1,637	​	4.8	%	​	95.2	%	​	0.1	%	​	4.7	%
Bakken/Williston Basin	​	687	​	7.1	%	​	92.9	%	​	3.4	%	​	3.7	%
DJ Basin/Rockies/Niobrara	​	620	​	36.0	%	​	64.0	%	​	0.4	%	​	35.6	%
Other	​	1,632	​	61.4	%	​	38.6	%	​	20.9	%	​	40.5	%
Total	​	13,860	​	21.2	%	​	78.8	%	​	6.5	%	​	14.7	%
(1)	"Btu-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read "Item 1. Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves."
---	---

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Estimated Proved Reserves

Our historical reserve estimates as of December 31, 2020, 2019 and 2018 were prepared by Ryder Scott, an independent petroleum engineering firm. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

Within Ryder Scott, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve report incorporated herein is Mr. Scott Wilson, who has been practicing petroleum-engineering consulting at Ryder Scott since 2000. Mr. Wilson is a registered Professional Engineer in the States of Alaska, Colorado, Texas and Wyoming. He earned a Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines in 1983 and a Master of Business Administration in Finance from the University of Colorado in 1985. As technical principal, Mr. Wilson meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering evaluations as well as in applying United States Securities and Exchange Commission (“SEC”) and other industry reserves definitions and guidelines. A copy of Ryder Scott’s estimated proved reserve report as of December 31, 2020 is attached as an exhibit to this Annual Report.

Our Chief Executive Officer, Robert D. Ravnaas, has agreed to provide us with reserve engineering services. Mr. R. Ravnaas is a petroleum engineer with over 31 years of reservoir and operations experience. Mr. R. Ravnaas and certain engineers and geoscience professionals under his supervision worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our mineral and royalty interests. Mr. R. Ravnaas met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We 18

Table of Contents provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Operating and development costs are not realized to our interest but are used to calculate the economic limit life of the wells. These costs are estimated and checked by our independent reserve engineers.

Mr. R. Ravnaas is primarily responsible for the preparation of our reserves. In addition, the preparation of our proved reserve estimates is completed in accordance with internal control procedures, including the following:

●	review and verification of historical production data, which data is based on actual production as reported by the operators of our properties;
●	preparation of reserve estimates by Mr. R. Ravnaas or under his direct supervision;
---	---
●	review by Mr. R. Ravnaas of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes; and
---	---
●	verification of property ownership by our land department.
---	---

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2020, 2019 and 2018 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. All proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and production cost data.

Summary of Estimated Proved Reserves

Estimates of reserves as of December 31, 2020, 2019 and 2018 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2020, 2019 and 2018, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $39.57, $55.69 and $65.56 per Bbl for oil and $1.99, $2.58 and $3.10 per MMBtu for natural gas at December 31, 2020, 2019 and 2018, respectively. The price per Bbl for NGLs was modeled as a percentage of oil price, which was derived from historical accounting data. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. 19

Table of Contents Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

The following table presents our estimated proved oil and natural gas reserves:

​	​	​	​	​	​	​	​	​	​
​	​	December 31,							​
​	​	2020	​	​	2019	​	​	2018	​
Estimated proved developed reserves:	​	​	​	​	​	​	​	​	​
Oil (MBbls)	​	12,294	​		11,303	​		9,183	​
Natural gas (MMcf)	​	144,233	​		141,181	​		116,321	​
Natural gas liquids (MBbls)	​	6,085	​		6,079	​		5,063	​
Total (MBoe)(6:1) (1)	​	42,418	​		40,912	​		33,633	​
Estimated proved undeveloped reserves:	​	​	​	​	​	​	​	​	​
Oil (MBbls)	​	—	​		1,015	​		1,612	​
Natural gas (MMcf)	​	—	​		7,562	​		10,940	​
Natural gas liquids (MBbls)	​	—	​		376	​		583	​
Total (MBoe)(6:1) (1)	​	—	​		2,651	​		4,018	​
Estimated proved reserves:	​	​	​	​	​	​	​	​	​
Oil (MBbls)	​	12,294	​		12,318	​		10,795	​
Natural gas (MMcf)	​	144,233	​		148,743	​		127,261	​
Natural gas liquids (MBbls)	​	6,085	​		6,455	​		5,646	​
Total (MBoe)(6:1) (1)	​	42,418	​		43,563	​		37,651	​
Percent proved developed	​	100	%	​	94	%	​	89	%
(1)	Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the years ended December 31, 2020, 2019 and 2018 was used, the conversion factor would be approximately 19.9 Mcf per Bbl of oil, 21.6 Mcf per Bbl of oil and 21.1 Mcf per Bbl of oil, respectively. In this Annual Report, we supplementally provide “value-equivalent” production information or volumes presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. We are providing this measure supplementally because we believe this conversion factor represents an estimation of value equivalence over time and better correlates with the respective contribution of oil and natural gas to our revenues. We use the 20-to-1 conversion factor as we assess our business, including analysis of our financial and production performance, strategic decisions to purchase additional properties and budgeting. We do not adjust the 20-to-1 ratio to reflect current pricing, because the significant volatility in the conversion ratio makes it difficult for us to compare results across periods. By reviewing our aggregate production on a constant 20-to-1 basis, which removes the variability of price fluctuations but generally approximates price equivalence over recent periods, we are able to compare production data from period to period as well as the relative contribution of oil and natural gas to our revenues. The 20-to-1 conversion factor approximates the mean ratio of the price of WTI oil to the price of Henry Hub natural gas from January 3, 2011 to December 31, 2020, as reported by the United States Energy Information Administration (“EIA”). During this period, the ratio of the price of oil to the price of natural gas ranged from (20.78) to 56.91. The mean ratios of the price of oil to the price of natural gas were 19.57, 22.55 and 21.42 for the years ended December 31, 2020, 2019 and 2018, respectively. Due to the variability of the prices of oil and natural gas, there is no standard conversion ratio for value equivalence, and the 20-to-1 ratio presented here may not accurately reflect the ratio of oil prices to natural gas prices for a given period.
---	---

The foregoing reserves are all located within the continental United States. Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Item 1A. Risk Factors.” 20

Table of Contents Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2020, which is included as an exhibit to this Annual Report.

Estimated Proved Undeveloped Reserves

The following table summarizes our changes in PUD reserves for the year ended December 31, 2020 (in MBoe):

​	​	​
​	​	December 31,
​	​	2020
Beginning balance	​	2,651
Revisions of previous estimates	​	(2,651)
Ending balance	​	-

​

Changes in PUD reserves that occurred from December 31, 2019 through December 31, 2020 were due to negative revisions of approximately 2,651 MBoe in PUD reserves. After evaluating certain external factors in the first quarter of 2020, including the significant decline in oil and natural gas prices related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries and other supply factors, as well as longer-term commodity price outlooks, we determined that significant drilling uncertainty existed regarding our PUD reserves that were included in our total estimated proved reserves as of December 31, 2019, as well as our unevaluated oil and natural gas properties. Specifically, with respect to our PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), we determined that we did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties for the three months ended March 31, 2020.

As of year-end 2020, we have transitioned to 100% proved developed reserves. Historically, our net organic growth has held PDP rates relatively flat to increasing over time, which we believe supports our inventory of drilling locations. 21

Table of Contents Oil, Natural Gas and NGL Production and Pricing

Production and Price History

The following table sets forth information regarding our production of oil and natural gas and certain price and cost information for each of the periods indicated:

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Production Data:	​	​	​	​	​	​	​	​	​
Oil and condensate (Bbls)	​	​	1,409,163	​	​	1,113,150	​	​	591,072
Natural gas (Mcf)	​	​	17,891,384	​	​	17,045,519	​	​	7,873,694
Natural gas liquids (Bbls)	​	​	681,575	​	​	561,797	​	​	310,361
Total (Boe)(6:1) (1)	​	​	5,072,635	​	​	4,515,867	​	​	2,213,715
Average daily production (Boe/d)(6:1)	​	​	13,860	​	​	12,331	​	​	6,065
Total (Boe)(20:1) (2)	​	​	2,985,307	​	​	2,527,223	​	​	1,295,118
Average daily production (Boe/d)(20:1)	​	​	8,157	​	​	6,924	​	​	3,548
Average Realized Prices:	​	​	​	​	​	​	​	​	​
Oil and condensate (per Bbl)	​	$	36.98	​	$	54.66	​	$	60.17
Natural gas (per Mcf)	​	$	1.79	​	$	2.21	​	$	2.84
Natural gas liquids (per Bbl)	​	$	12.39	​	$	15.96	​	$	25.14
Average Unit Cost per Boe (6:1)	​	​	​	​	​	​	​	​	​
Production and ad valorem taxes	​	$	1.26	​	$	1.71	​	$	1.99
(1)	“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
---	---
(2)	“Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 1 to the Summary of Estimated Proved Reserves table under “—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves.”
---	---

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development or extension wells that are not dry wells. As of December 31, 2020, we owned mineral or royalty interests in over 97,000 gross productive wells, which consisted of over 74,000 oil wells and over 22,000 natural gas wells. 22

Table of Contents

Acreage

Mineral and Royalty Interests

The following table sets forth information relating to the acreage underlying our mineral and nonparticipating royalty interests at December 31, 2020:

​	​	​	​	​	​	​
​	​	Developed	​	Undeveloped	​	Total
State		Acreage	​	Acreage	​	Acreage
Texas		4,235,811	​	55,617	​	4,291,428
Oklahoma		1,137,765		7,534		1,145,299
North Dakota		1,029,543		1,000		1,030,543
Wyoming		301,330		771		302,101
Kansas		201,472		2,001		203,473
Louisiana		350,634		1,045		351,679
Arkansas		371,368		1,218		372,586
Montana		165,955		5,059		171,014
New Mexico		187,819		1,843		189,662
Utah	​	144,053	​	—	​	144,053
Other		836,592	​	17,671		854,263
Total		8,962,342	(1)	93,759	(2)	9,056,101
(1)	Reflects mineral interests in approximately 8,962,342 total gross (81,303 net) developed acres.
---	---
(2)	Reflects mineral interests in approximately 93,759 total gross (9,411 net) undeveloped acres.
---	---

ORRIs

The following table sets forth information relating to our acreage for our ORRIs at December 31, 2020:

​	​	​	​	​	​	​
​	​	Developed	​	Undeveloped	​	Total
State	​	Acreage	​	Acreage	​	Acreage
Texas		1,374,997		680		1,375,677
Oklahoma		1,280,362		19,000		1,299,362
North Dakota		417,177		—		417,177
Wyoming		350,846		—		350,846
Utah	​	235,432	​	—	​	235,432
Colorado		192,402		—		192,402
Pennsylvania		124,298		—		124,298
West Virginia		116,938		—		116,938
Louisiana		118,842		510		119,352
New Mexico		106,696		960		107,656
Other		250,532		728		251,260
Total		4,568,522	(1)	21,878	(2)	4,590,400
(1)	Reflects ORRIs in approximately 4,568,522 total gross (55,029 net) developed acres.
---	---
(2)	Reflects ORRIs in approximately 21,878 total gross (112 net) undeveloped acres.
---	---

Drilling Results

As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory or as developmental wells. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant period.

Competition

The oil and natural gas industry is intensely competitive; we primarily compete with companies for the acquisition of oil and natural gas properties some of whom have greater resources than we do. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Additionally, many of our 23

Table of Contents competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These companies may also have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months, while natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for the operators of our properties in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

The following disclosure describes regulation directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

Environmental Matters

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state and local governmental agencies, such as the Environmental Protection Agency (“EPA”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators of our properties regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our business and prospects. 24

Table of Contents

Non-Hazardous and Hazardous Waste

The federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with exploration and production of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Any changes in the laws and regulations in the future could have a material adverse effect on the operators of our properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.

Remediation

The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), and analogous state laws, generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Water Discharges

The federal Water Pollution Control Act of 1972 (“Clean Water Act”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The EPA issued a final rule outlining its position on the federal jurisdictional reach over waters of the United States, in September 2015, but this rule was promptly challenged in courts and was enjoined by judicial action in some states.

In October 2019, the EPA and the United States Army Corps of Engineers issued a final rule that repealed the 2015 regulations and reinstated the agencies’ narrower pre-2015 scope of federal Clean Water Act jurisdiction. In April 2020, the EPA and the United States Army Corps of Engineers issued a new final waters of the United States (“WOTUS”) definition that continues to provide a narrower scope of federal Clean Water Act jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal Clean Water Act jurisdiction. Judicial challenges to the EPA’s October 2019 and April 2020 final rules are currently before multiple federal 25

Table of Contents district courts. If the rules are vacated and the 2015 rule is ultimately implemented, the expansion of Clean Water Act jurisdiction will result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.

In addition, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.

Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the operators of the acreage underlying our mineral interests.

Air Emissions

The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, most recently in May 2016, the EPA finalized additional regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of the regulations applicable to sources in the production and processing segments and removed the transmission and storage segments from the source category, which removes them from the scope of the regulations. However, these 2020 rules are being challenged in the U.S. Circuit Court for the D.C. Circuit. In addition, on January 20, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing the EPA to consider publishing a proposed rule suspending, revising or rescinding the 2020 rules. More stringent laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In response to findings that emissions of greenhouse gases (“GHGs”), including carbon dioxide and methane, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

President Biden has issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden administration’s climate policies. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although Congress has not adopted such legislation at 26

Table of Contents this time, it may do so in the future and many states continue to pursue regulations to reduce GHG emissions. Additionally, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Climate Agreement (the “Paris Agreement”). In April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. In June 2017, President Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated. In November 2019, the State Department formally informed the United Nations of the United States’ withdrawal from the Paris Agreement, and the United States withdrew from the Paris Agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reverses this withdrawal, and the United States formally re-joined the Paris Agreement on February 19, 2021.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

Moreover, activists and members of the investment community concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for operators on our properties to secure funding for exploration and production activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or restrict more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult or costly for operators to engage in exploration and production activities.

Finally, one potential consequence of climate change could be increased severity of extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. Legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. In March 2015, the Bureau of Land Management (“BLM”) adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and would strengthen standards for wellbore integrity and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. That rule was rescinded in December 2017. This rescission was upheld in March 2020 by the United States District Court for the Northern District of California, but the decision has been appealed. If these requirements went into effect, they could result in delays in operations at well sites and increased costs to make wells productive.

On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured natural 27

Table of Contents gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In May 2016, the EPA finalized similar rules that impose VOC emissions limits on certain oil and natural gas operations that were previously unregulated, including hydraulically fractured oil wells, as well as methane emissions limits for certain new or modified oil and natural gas emissions sources. The EPA is currently reconsidering the rules and has proposed to stay their requirements. However, the rules currently remain in effect.

In addition, governments have studied the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur, including situations involving large volume spills and inadequate mechanical integrity of wells. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. This study and other ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. In addition, local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations or taken other regulatory actions to curtail injection of produced water to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities.

If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. For example, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order suspending new fossil fuel leasing and permitting on federal lands for 60 days. 28

Table of Contents In addition, on January 27, 2021, President Biden issued an Executive Order directing the Secretary of the Interior to pause entering into new oil and natural gas leases on public lands or offshore waters “to the extent possible,” and launch a review of all existing leasing and permitting practices related to fossil fuel development on public lands and waters. The Executive Order also directed federal agencies to eliminate fossil fuel subsidies. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business and potentially delays operations, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate and NGLs are not currently regulated and are made at market prices.

Drilling and Production

The operations of the operators of our properties are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

●	the location of wells;
●	the method of drilling and casing wells;
---	---
●	the timing of construction or drilling activities, including seasonal wildlife closures;
---	---
●	the rates of production or “allowables”;
---	---
●	the surface use and restoration of properties upon which wells are drilled;
---	---
●	the plugging and abandoning of wells; and
---	---
●	notice to, and consultation with, surface owners and other third parties.
---	---

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the operators of our properties can produce from our wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill. 29

Table of Contents Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of our properties operate. The United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the United States Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues the operators of our properties receive for sales of natural gas and release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third party sellers other than pipelines.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the operators of our properties produce.

Historically, the natural gas industry has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Oil Sales and Transportation

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that our access to oil pipeline transportation services will not materially differ from our competitors’ access to oil pipeline transportation services. 30

Table of Contents State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax (2.3% for enhanced recovery) on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of oil and natural gas that may be produced from our wells and the number of wells or locations the operators of our properties can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on our business.

Title to Properties

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties. Under our secured revolving credit facility, we have granted the lenders a lien on substantially all of the mineral and royalty interests of our wholly owned subsidiaries.

Human Capital Resources

The officers of our General Partner manage our operations and activities. However, neither we, our General Partner nor our subsidiaries have employees. We have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services for us, including the operation of our properties. The compensation for all our employees is indirectly paid by us pursuant to the management services agreement with Kimbell Operating. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements” for more information regarding such management services agreements.

Our success depends on our ability to continue to attract, retain and motivate qualified employees. We recognize that we are in a competitive marketplace when it comes to finding top talent. As a result, talent acquisition and the retention of employees continue to be a priority initiative for us. We strive to continue to attract, retain and motivate qualified employees by offering competitive compensation and benefits in an inclusive and safe workplace, with opportunities for our employees to grow and develop in their careers. Our employees may participate in a robust benefits program, which includes a focus on health and wellness, and we offer a variety of other employee perks.

As of December 31, 2020, Kimbell Operating had approximately 25 employees performing services for our operations and activities. Women represent approximately 32% of our workforce, and men represent approximately 68%. We believe that our employees are one of our greatest assets and that we are made up of talented and dedicated employees working together to achieve common and rewarding goals. We value integrity, hard work, dedication and teamwork. Our goal is to promote an environment where employees are encouraged to do their best work with high professional standards.

Our first priority in our response to the COVID-19 health crisis has been the health and safety of our employees. To address these concerns, we implemented safety protocols and procedures to protect our employees. We modified certain 31

Table of Contents business practices (including those related to employee travel, employee work locations, and physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention (the “CDC”), the World Health Organization (the “WHO”) and other governmental and regulatory authorities. In mid-March, we restricted access to our offices to only essential employees and directed the remainder of our employees to work from home to the extent possible. In mid-May, we opened our offices to employees on a voluntary basis, with employees having the option to work from home.

Facilities

Our principal executive offices are located at 777 Taylor Street, Suite 810, Fort Worth, Texas 76102. We believe that our leased facilities are adequate for our current operations.

Additional Information

We electronically file various reports with the SEC including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The SEC maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our website at www.kimbellrp.com. These reports are accessible at no charge through our website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this Annual Report.

​

Item 1A. Risk Factors

Summary of Risk Factors

Risks Related to Business Disruptions

●	The ongoing COVID-19 pandemic and the related impact on oil and natural gas prices have adversely affected, and could continue to adversely affect, our business, financial condition and results of operations.
●	A terrorist attack or armed conflict could harm our business.
---	---
●	Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.
---	---

Risks Related to Our Organization and Structure

●	We may not have sufficient available cash to pay any quarterly distribution on our common units.
●	The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow and not solely on profitability, which may prevent us from paying cash distributions during periods when we record net income.
---	---
●	The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and is directly dependent on the performance of our business. We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter.
---	---
●	Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
---	---
●	The limited liability company agreement of our General Partner contains restrictive covenants, governance and other provisions that may restrict our ability to pursue our business strategies.
---	---

32

Table of Contents

●	Our General Partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.
●	Our partnership agreement does not restrict our Sponsors and their respective affiliates or the Contributing Parties from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
---	---
●	Our General Partner intends to limit its liability regarding our obligations.
---	---
●	Neither we, our General Partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage and operate, or arrange for the management and operation of, our business. The management team of Kimbell Operating, which includes the individuals who will manage us, also provides substantially similar services to other entities and thus is not solely focused on our business.
---	---
●	Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to our unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
---	---
●	Our partnership agreement replaces our General Partner’s fiduciary duties to our unitholders with contractual standards governing its duties.
---	---
●	Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors, which could reduce the price at which our common units will trade.
---	---
●	Even if our unitholders are dissatisfied, they cannot initially remove our General Partner without its consent.
---	---
●	Our partnership agreement restricts the voting rights of unitholders owning 20% or more of the interests in any class of our securities, subject to certain exceptions.
---	---
●	Cost reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. Our partnership agreement and the limited liability company agreement of the Operating Company do not set a limit on the amount of expenses for which our General Partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our General Partner.
---	---
●	Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
---	---
●	Our sole cash-generating asset is our membership interest in the Operating Company and we are accordingly dependent upon distributions from the Operating Company to pay taxes and cover our expenses and to make distributions to our unitholders.
---	---
●	Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.
---	---
●	Increases in interest rates may cause the market price of our common units to decline.
---	---
●	Our General Partner has a call right that may require unitholders to sell their units at an undesirable time or price.
---	---

33

Table of Contents

●	We may issue additional common units and other equity interests ranking junior to the Series A preferred units without unitholder approval, which would dilute existing common unitholder ownership interests.
●	There are no limitations in our partnership agreement on our ability to issue units ranking senior in right of distributions or liquidation to our common units.
---	---
●	The market price of our common units could be materially adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by our Sponsors, the Contributing Parties and other selling unitholders pursuant to any registration rights agreements.
---	---
●	The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.
---	---
●	For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.
---	---
●	The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
---	---
●	Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By acquiring an interest in us, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.
---	---
●	If a unitholder is an ineligible holder, the units of such unitholder may be subject to redemption.
---	---
●	Our Series A preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.
---	---
●	The terms of our Series A preferred units contain covenants that may limit our business flexibility.
---	---

Risks Related to Economic Conditions and Our Industry

●	All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available for distribution on common units.
●	A deterioration in general economic, business or industry conditions would materially adversely affect our results of operations, financial condition and cash available for distribution on common units.
---	---
●	Conservation measures and technological advances could reduce demand for oil and natural gas.
---	---
●	Competition in the oil and natural gas industry is intense, which may adversely affect our operators’ ability to succeed.
---	---
●	The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
---	---
●	The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which neither we nor the operators of our properties control. If these facilities are unavailable, our operators’ operations could be interrupted and our results of operations and cash available for distribution on common units could be materially adversely affected.
---	---

34

Table of Contents

●	Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units.

Risks Related to Our Indebtedness and Derivatives

●	Our derivative activities could result in financial losses and reduce earnings.
●	Restrictions in our secured revolving credit facility and future debt agreements could limit our growth and our ability to engage in certain activities, including our ability to pay distributions to our unitholders.
---	---
●	Any significant reduction in our borrowing base under our secured revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
---	---
●	Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
---	---

Risks Related to Our Operations

●	Our business is difficult to evaluate because we have made several significant acquisitions.
●	We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations and cash available for distribution on common units.
---	---
●	We may not be able to terminate our leases if any of the operators of the properties in which we own mineral interests declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.
---	---
●	Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties.
---	---
●	Our failure to successfully identify, complete and integrate acquisitions of properties or businesses would slow our growth and could materially adversely affect our results of operations and cash available for distribution on common units.
---	---
●	Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.
---	---
●	If we are unable to make acquisitions on economically acceptable terms from our Sponsors, the Contributing Parties or third parties, our future growth will be limited.
---	---
●	Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
---	---
●	Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
---	---

35

Table of Contents

●	We do not intend to retain cash from our operations for replacement capital expenditures. Unless we replenish our oil and natural gas reserves, our cash generated from operations and our ability to pay distributions to our unitholders could be materially adversely affected.
●	We rely on a few key individuals whose absence or loss could materially adversely affect our business.
---	---
●	Loss of our or our operators’ information and computer systems could materially adversely affect our business.
---	---
●	Title to the properties in which we have an interest may be impaired by title defects.
---	---
●	The Haymaker Sellers, Dropdown Sellers, Phillips Sellers and Springbok Sellers have limited indemnity obligations to us for liabilities arising out of the ownership and operation of our assets prior to the Haymaker Acquisition, the Dropdown, the Phillips Acquisition and the Springbok Acquisition, respectively, including title defects.
---	---
●	The potential drilling locations identified by the operators of our properties are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
---	---
●	Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our operators’ failure to drill sufficient wells to hold acreage may result in loss of the lease and prospective drilling opportunities.
---	---
●	The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
---	---
●	Operating hazards and uninsured risks may result in substantial losses to the operators of our properties, and any losses could materially adversely affect our results of operations and cash available for distribution on common units.
---	---
●	If the operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash available for distribution on common units may be adversely affected.
---	---
●	We will be required to take write-downs of the carrying values of our properties if commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value.
---	---

Tax Risks to Common Unitholders

●	We may incur substantial income tax liabilities on our allocable share of income from the Operating Company.
●	Taxable gain or loss on the sale of our common units could be more or less than expected.
---	---
●	Our tax liability may be greater than expected if we do not generate sufficient depletion deductions to offset our taxable income and reduce our tax liability.
---	---
●	Future tax legislation could have an adverse impact on our cash tax liabilities, results of operations and financial condition, which could affect our cash available for distribution on common units and the value of our common units.
---	---
●	Certain decreases in the price of our common units could adversely affect our amount of cash available for distribution on common units.
---	---

36

Table of Contents

●	The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our units for United States federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your United States federal income tax return.
●	The portion of our distributions taxable as dividends may be greater than expected.
---	---
●	If the Operating Company were to become a publicly traded partnership taxable as a corporation for United States federal income tax purposes, we and the Operating Company might be subject to potentially significant tax inefficiencies.
---	---

Legal, Environmental and Regulatory Risks

●	Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce our cash available for distribution on common units.
●	The operators of our properties are subject to complex and evolving environmental and occupational health and safety laws and regulations. As a result, they may incur significant delays, costs and liabilities that could materially adversely affect our business and financial condition.
---	---
●	Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
---	---
●	The adoption of climate change legislation and regulations could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.
---	---

General Risk Factors

●	Increased costs of capital could materially adversely affect our business.
●	If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
---	---

There are many factors that could have a material adverse effect on our operating results, financial condition and cash flows. New risks may emerge at any time and we cannot predict those risks or estimate the extent to which they may affect financial performance. Each of the risks described below could adversely impact the value of our common units.

Risks Related to Business Disruptions

The ongoing COVID-19 pandemic and the related impact on oil and natural gas prices have adversely affected, and could continue to adversely affect, our business, financial condition and results of operations.

​

The ongoing COVID-19 pandemic has reached more than 200 countries and has continued to be a rapidly evolving economic and public health situation. The pandemic has resulted in widespread adverse impacts on the global economy and financial markets, including record economic contraction in the United States, and we and our third-party operators and other parties with whom we have business relations have experienced disrupted business operations as a result. For example, in mid-March, we had to limit access to our administrative offices and took certain other precautionary measures intended to help minimize the risk to our employees, our business and our community. Beginning in mid-May, we opened our offices to employees on a voluntary basis, with employees having the option to work from home. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. While shelter-in-place restrictions subsided in the second half of 2020, the possibility of future restrictions remains. Because our 37

Table of Contents employees have the option to work remotely, there is an increased risk of security breaches or other cyber-incidents or attacks, loss of data, fraud and other disruptions.

The impact of the pandemic, including the resulting significant reduction in global demand for oil and, to a lesser extent, natural gas, coupled with the sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, has led to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April 2020 to cut oil production and has extended such production cuts through March 2021, crude oil prices remained depressed through December 31, 2020 as a result of an increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. Oil and natural gas prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 pandemic, and as changes in oil and natural gas inventories, industry demand and economic performance are reported. The current price environment has caused some of our operators’ wells to become uneconomic, which has resulted, and may result in the future, in suspension of production from those wells or a significant reduction in, or no royalty revenues from, existing production. Some operators may also attempt to shut in producing wells and avoid lease termination or payment of shut-in royalties by claiming force majeure, if provided for in the applicable lease. The curtailment of production or the shut-in of wells as a result of the ongoing COVID-19 pandemic and any drop in commodity prices are both outside of our control, and the materialization of either circumstance could have a significant impact on our result of operations. For example, in April 2020, we received notices from two operators regarding well shut-ins and curtailments of production on properties in which we own an interest. The properties were primarily located in the Eagle Ford Shale, and the production attributable to such properties on a Boe/d basis (6:1) represented approximately one percent of our total production for the first quarter of 2020. We received subsequent notice that the curtailment on all Eagle Ford Shale production had ceased and production resumed, effective June 1, 2020. We also received notifications of well shut-ins and curtailment in the second quarter of 2020 from additional operators, and the production attributable to such properties on a Boe/d basis (6:1) accounted for less than one percent of our total production for the second quarter of 2020. We did not receive any additional notifications of well shut-ins or curtailments in the second half of 2020; however, we cannot predict whether any shut-ins and curtailments of production will be instituted by our operators in the future.

Due to the significant decline in oil and natural gas prices related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, as well as longer-term commodity price outlooks, we recorded an impairment on our oil and natural gas properties of $251.6 million for the year ended December 31, 2020. If the price of oil, natural gas and NGLs decrease further in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.

In addition, it is possible that the borrowing base of our secured revolving credit facility will be reduced in the future as a result of a decrease in the value of the assets underlying the borrowing base in connection with a sustained decrease in oil and natural gas prices.

During the Board of Director’s determination of “available cash” for the fourth quarter of 2020, the Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2020 for the repayment of $3.9 million in outstanding borrowings under our secured revolving credit facility. With respect to future quarters, the Board of Directors intends to allocate cash generated by our business to the repayment of outstanding borrowings under our secured revolving credit facility or may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time, and the Board of Directors may further change its policy with respect to cash distributions in the future. Any such allocation, whether for debt repayment or another purpose, would have the effect of reducing the amount of cash distribution to our common unitholders.

To the extent that access to the capital and other financial markets is adversely affected by the effects of COVID-19 and commodity prices generally, we may need to consider alternative sources of funding for our future acquisitions, which may increase our cost of, as well as adversely impact our access to, capital or otherwise impact our ability to complete acquisitions. We cannot predict the full impact that COVID-19 or the significant disruption and volatility in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impact will depend on future developments beyond our control, which are highly uncertain and cannot be predicted, including, among others, the ultimate severity of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development, 38

Table of Contents availability and administration of effective treatments and vaccines, the duration of the pandemic, future actions taken by members of OPEC and other foreign oil-exporting countries, actions taken by governmental authorities, third-party operators and other third parties and the timing and extent of any return to normal economic and operating conditions.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, and if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. For example, the oil and natural gas industry depends on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with customers, employees and third-party partners. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The United States government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We are dependent on our and our operators’ information systems and computer-based programs. If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. In addition to the service providers who provide substantial services to us under our services agreement with Kimbell Operating, we rely on third party service providers to perform some of our data entry, investor relations and other functions. If the programs or systems used by our third-party service providers are not adequately functioning, we could experience loss of important data.

In addition, unauthorized access to our reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption or other disruptions in our operations or planned business transactions, any of which could have a material adverse impact on our results of operations. Our systems for protecting against cyber security risks may not be sufficient, and our increased reliance on remote access to our information system as a result of the COVID-19 pandemic has increased our exposure to potential cyber security risks. Further, as cyber-attacks continue to evolve, we or our service providers, who we are generally obligated to reimburse for costs incurred in connection with the provision of their services to us, may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.

Risks Related to Our Organization and Structure

​

We may not have sufficient available cash to pay any quarterly distribution on our common units.

We may not have sufficient available cash each quarter to enable us to pay any distributions to our common unitholders. The holders of our Series A preferred units (to the extent of a distribution equal to 7.0% per annum plus accrued and unpaid distributions) and Class B units (to the extent of a distribution equal to 2.0% per quarter on such holder’s Class B Contribution (as defined below)) are entitled to receive quarterly cash distributions prior to distributions to holders of our common units. 39

Table of Contents Substantially all of the cash we have to distribute each quarter depends upon the amount of oil, natural gas and NGL revenues we generate, which is dependent upon the prices that the operators of our properties realize from the sale of oil and natural gas production. In addition, the actual amount of our available cash we will have to distribute each quarter will be reduced by replacement capital expenditures we make, payments in respect of our debt instruments and other contractual obligations, tax obligations, general and administrative expenses and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine are appropriate.

The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow and not solely on profitability, which may prevent us from paying cash distributions during periods when we record net income.

The amount of cash we have available for distribution to holders of our common units depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items such as impairment expense or unit-based compensation expense. For example, we may have significant capital expenditures in the future. While these items may not affect our profitability in a quarter, they would reduce the amount of cash available for distribution to holders of our common units with respect to such quarter. As a result, we may pay cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to pay cash distributions during periods in which we record net income.

The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and is directly dependent on the performance of our business. We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter.

Our future business performance may be volatile, and our cash flows may be unstable. Please read “—All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available for distribution on common units.” We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Please read “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy and Restrictions on Distributions.”

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash each quarter. As a result, we will have limited cash available to reinvest in our business or to fund acquisitions, and we may rely upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. To the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow. In addition, the incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our common unitholders.

We have funded a significant portion of the consideration paid in connection with our acquisitions with the issuance of equity securities, including common units and securities that are convertible or exchangeable into common units. For example, we issued 2,224,358 common units and 2,497,134 OpCo common units and an equal number of Class B units as partial consideration in connection with the Springbok Acquisition. There are no limitations in our partnership agreement on our ability to issue additional common units and, as a limited partnership, we are not required to seek unitholder approval for issuances of common units (including issuances in excess of 20% of our outstanding equity securities or issuances of equity to certain affiliates). To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. 40

Table of Contents

The limited liability company agreement of our General Partner contains restrictive covenants, governance and other provisions that may restrict our ability to pursue our business strategies.

The limited liability company agreement of our General Partner, which is controlled by our Sponsors, contains provisions that prohibit certain actions without a supermajority vote of at least 66^2^/3% of the members of the Board of Directors, including:

●	the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters;
●	the reservation of a portion of cash generated from operations to finance acquisitions;
---	---
●	modifications to the definition of “available cash” in our partnership agreement; and
---	---
●	the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units.
---	---

The Board of Directors is made up of eight members. Therefore, the vote of three directors would be sufficient to prevent us from undertaking the items discussed above. These restrictions may limit our ability to obtain future financings and acquire additional oil and gas properties. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that these restrictions impose on us. Our inability to execute financings or acquire additional properties may materially adversely affect our results of operations and cash available for distribution on common units.

Our General Partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.

As of February 19, 2021, the owners of our Sponsors own or control up to an aggregate of approximately 12.2% of our outstanding common units and Class B units (or approximately 11.0% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner. Our General Partner has sole responsibility for conducting our business and managing our operations. Although our General Partner has a duty to manage us in a manner that is in, or not adverse to, the best interests of us and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. Conflicts of interest may arise between our Sponsors and their respective affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our General Partner may favor its own interests and the interests of its affiliates, including our Sponsors and their respective affiliates, over the interests of our unitholders. These conflicts include, among others, the following situations:

●	neither our partnership agreement nor any other agreement requires our Sponsors or the Contributing Parties to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by our Sponsors to undertake acquisition opportunities for themselves or any other investment partnership that they control, and the directors and officers of our Sponsors and the Contributing Parties have a fiduciary duty to make these decisions in the best interests of our Sponsors and such Contributing Parties, which may be contrary to our interests;
●	our Sponsors may change their strategy or priorities in a way that is detrimental to our future growth and acquisition opportunities;
---	---
●	many of the officers and directors of our General Partner are also officers or directors of, and equity owners in, our Sponsors and the Contributing Parties and owe fiduciary duties to our Sponsors, or any other investment partnership that they control, and the Contributing Parties and their respective owners;
---	---

41

Table of Contents

●	our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we entered into with our Sponsors and the Contributing Parties in connection with our IPO, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us;
●	our Sponsors may be constrained by the terms of their current or future debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
---	---
●	our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties, limiting our General Partner’s liabilities, and restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty;
---	---
●	except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;
---	---
●	contracts between us, on the one hand, and our General Partner and its affiliates, on the other hand, may not be the result of arm’s length negotiations;
---	---
●	disputes may arise under agreements we have with our General Partner or its affiliates;
---	---
●	our General Partner determines the amount and timing of acquisitions and dispositions, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
---	---
●	our General Partner determines which costs incurred by it or its affiliates are reimbursable by us;
---	---
●	our partnership agreement does not restrict our General Partner from causing us to reimburse it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
---	---
●	we have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us, and such entities also provide these services to certain other entities, including certain of the Contributing Parties;
---	---
●	our General Partner intends to limit its liability regarding our contractual and other obligations;
---	---
●	our General Partner may exercise its right to call and purchase all of the common units and Class B units not owned by it and its affiliates if it and its affiliates own more than 80% of our common units and Class B units (taken as a single class);
---	---
●	our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates, including under the contribution agreement entered into in connection with our IPO and other agreements with our Sponsors and the Contributing Parties; and
---	---
●	our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
---	---

42

Table of Contents

Our partnership agreement does not restrict our Sponsors and their respective affiliates or the Contributing Parties from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Our partnership agreement provides that our General Partner is restricted from engaging in any business activities other than acting as our General Partner and those activities incidental to its ownership of interests in us. Affiliates of our General Partner are not prohibited from owning projects or engaging in businesses that compete directly or indirectly with us. Similarly, our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we entered into with our Sponsors and the Contributing Parties in connection with our IPO, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us.

Affiliates of our Sponsors currently hold interests in, and may make investments in and purchases of, entities that acquire and own mineral and royalty interests. In addition, certain of our officers and directors, including the individuals who control our Sponsors, may in the future hold similar positions with investment partnerships or other private entities that are in the business of identifying and acquiring mineral and royalty interests.  In such capacities, these individuals would likely devote significant time to such other businesses and would be compensated by such other businesses for the services rendered to them. The positions of these directors and officers may give rise to duties that are in conflict with duties owed to us. In addition, these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these potential future affiliations, they may have duties to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. Our Sponsors and their respective affiliates are under no obligation to make any acquisition opportunities available to us, except as provided for under the contribution agreement entered into in connection with our IPO.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner or any of its affiliates, including its executive officers and directors, our Sponsors and their respective affiliates or the Contributing Parties. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us does not have any duty to communicate or offer such opportunity to us. Any such person or entity is not liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and holders of our units.

Our General Partner intends to limit its liability regarding our obligations.

Our General Partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our General Partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our partnership agreement permits our General Partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Neither we, our General Partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage and operate, or arrange for the management and operation of, our business. The management team of Kimbell Operating, which includes the individuals who will manage us, also provides substantially similar services to other entities and thus is not solely focused on our business.

Neither we, our General Partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage us and operate our assets. We have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of 43

Table of Contents our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us.

Kimbell Operating also provides substantially similar services and personnel to other entities, including certain of the Contributing Parties, and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Kimbell Operating may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of other entities or other affiliates of our General Partner. There is no requirement that Kimbell Operating favor us over these other entities in providing its services. If the employees of Kimbell Operating do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to our unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that replace fiduciary duties applicable to a corporation with contractual duties and restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

●	whenever our General Partner (acting in its capacity as our General Partner), the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our General Partner, the Board of Directors and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not adverse to, our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity;
●	our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
---	---
●	our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and
---	---
●	our General Partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
---	---
●	approved by the conflicts committee of the Board of Directors, although our General Partner is not obligated to seek such approval;
---	---
●	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates;
---	---
●	determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from third parties; or
---	---
●	determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
---	---

44

Table of Contents In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our partnership agreement replaces our General Partner’s fiduciary duties to our unitholders with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include:

●	how to allocate corporate opportunities among us and its other affiliates;
●	whether to exercise its limited call right;
---	---
●	whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors or by the unitholders;
---	---
●	how to exercise its voting rights with respect to the units it owns;
---	---
●	whether to sell or otherwise dispose of any units or other partnership interests it owns; and
---	---
●	whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
---	---

By acquiring an interest in us, a limited partner agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right on an annual or ongoing basis to elect our General Partner or its Board of Directors. The Board of Directors, including the independent directors, is chosen entirely by our Sponsors, as a result of such Sponsors controlling our General Partner, and not by our unitholders. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence.” Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if our unitholders are dissatisfied, they cannot initially remove our General Partner without its consent.

If our unitholders are dissatisfied with the performance of our General Partner, they will have limited ability to remove our General Partner. Our General Partner may not be removed unless such removal is both (i) for cause and 45

Table of Contents (ii) approved by the vote of the holders of not less than 66^2^/3% of all outstanding units (including common units and Class B units held by the General Partner and its affiliates). As of February 21, 2020, the owners of our Sponsors own or control an aggregate of approximately 12.2% of our outstanding common units and Class B units (or approximately 11.0% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of the interests in any class of our securities, subject to certain exceptions.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates and their transferees, the Contributing Parties and their respective affiliates, persons who acquired such units with the prior approval of the Board of Directors, holders of Series A preferred units in connection with any vote, consent or approval of holders of the Series A preferred units, voting as a separate class or on an as-converted basis with the holders of common units, and holders who own 20% or more of any class of units as a result of any redemption or purchase of any other holder’s units or any conversion of the Series A preferred units at our option, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our unitholders to influence the manner or direction of management.

Cost reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. Our partnership agreement and the limited liability company agreement of the Operating Company do not set a limit on the amount of expenses for which our General Partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our General Partner.

Prior to paying any distribution on our common units, we will reimburse our General Partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all expenses they incur and payments they make on our behalf. Our partnership agreement and limited liability company agreement of the Operating Company do not set a limit on the amount of expenses for which our General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates. Our partnership agreement and the limited liability company agreement of the Operating Company provide that our General Partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our General Partner and its affiliates will reduce the amount of cash available for distribution to our common unitholders. Please read “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities— Cash Distribution Policy and Restrictions on Distributions.”

We have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution to our common unitholders. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence —Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Management Services Agreements.”

Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our General Partner to transfer its membership interests in our General Partner to a third party. After any such transfer, the new member or members of our General Partner would then be in a position to replace the Board of Directors and executive officers of our General Partner with its own designees and thereby exert significant control over the decisions taken by the Board of Directors and executive officers of our General Partner. This effectively permits a “change of control” without the vote or consent of the unitholders. 46

Table of Contents

Our sole cash-generating asset is our membership interest in the Operating Company and we are accordingly dependent upon distributions from the Operating Company to pay taxes and cover our expenses and to make distributions to our unitholders.

We are a holding company, and we have no material assets other than our membership interest in the Operating Company. We have no independent means of generating revenue. To the extent the Operating Company has available cash, we intend to cause the Operating Company to make distributions to its unitholders, including us, in an amount sufficient to cover all applicable taxes at assumed tax rates, to reimburse us for our expenses and to allow us to make distributions to our unitholders. To the extent that we need funds and the Operating Company is restricted from making such distributions under applicable law or regulation or under the terms of any financing arrangements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not pay a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our General Partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our General Partner if a limited partner were to lose limited liability through any fault of our General Partner.

Increases in interest rates may cause the market price of our common units to decline.

While interest rates have been at record low levels in recent years, this low interest rate environment likely will not continue indefinitely. An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline.

Our General Partner has a call right that may require unitholders to sell their units at an undesirable time or price.

If at any time our General Partner and its affiliates (including our Sponsors and their respective affiliates) own more than 80% of the sum of the number of our common units then outstanding and the number of Class B units then outstanding, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units and Class B units (being treated as a single class of units) held by unaffiliated persons at a price not less than the then-current market price of the common units, as calculated in accordance with our partnership agreement. As a result, unitholders may be required to sell their common units or Class B units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units or Class B units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our General Partner from causing us to issue additional common units or Class B units and then exercising its call right. If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As of February 19, 2021, the owners of our Sponsors own or control up to an aggregate of approximately 12.2% of our outstanding common units and Class B units (or approximately 11.0% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner. 47

Table of Contents

We may issue additional common units and other equity interests ranking junior to the Series A preferred units without unitholder approval, which would dilute existing common unitholder ownership interests.

Under our partnership agreement, we are authorized, without the vote of unitholders, to issue an unlimited number of additional partnership interests that, with respect to distributions on such partnership interests or distributions in respect of such partnership interests upon our liquidation, dissolution and winding up, rank junior to the Series A preferred units. The issuance of additional partnership interests that rank equal to or senior to the Series A preferred units requires the consent of the holders of 66^2^/3% of the outstanding Series A preferred units. The terms of our partnership agreement and the limited liability company agreement of the Operating Company also authorize us and it to issue an unlimited number of Class B units and OpCo common units, respectively, which are together exchangeable on a one-for-one basis into common units. The issuance by us of additional common units or other equity interests of equal or senior rank to the common units would have the following effects:

●	the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;
●	the amount of cash distributions on each common unit may decrease;
---	---
●	the ratio of our taxable income to distributions may increase;
---	---
●	the relative voting strength of each previously outstanding common unit may be diminished; and
---	---
●	the market price of the common units may decline.
---	---

There are no limitations in our partnership agreement on our ability to issue units ranking senior in right of distributions or liquidation to our common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that rank senior in right of distributions, liquidation or voting to our common units. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

The market price of our common units could be materially adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by our Sponsors, the Contributing Parties and other selling unitholders pursuant to any registration rights agreements.

As of December 31, 2020, we had 38,918,689 common units outstanding and 20,779,781 Class B units outstanding. Our Class B units are exchangeable on a one-for-one basis, together with an equal number of OpCo common units, for common units. In addition, our Series A preferred units may be converted into common units at the then-applicable conversion rate.

A large percentage of our equity securities, including securities that are convertible or exchangeable into common units, are held by a relatively limited number of investors. Further, we have entered into registration rights agreements with many of such investors, including the Contributing Parties, the Series A Purchasers (as defined below), the Haymaker Holders (as defined below), the Dropdown Sellers, the Phillips Sellers and the Springbok Sellers, pursuant to which we have filed registration statements with the SEC to facilitate potential future sales of such common units by them. Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities.

The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

The market price of our common units may be influenced by many factors, some of which are beyond our control, including:

●	changes in commodity prices;

48

Table of Contents

●	public reaction to our press releases, announcements and filings with the SEC;
●	fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;
---	---
●	changes in market valuations of similar companies;
---	---
●	departures of key personnel;
---	---
●	commencement of or involvement in litigation;
---	---
●	variations in our quarterly results of operations or those of other oil and natural gas companies;
---	---
●	changes in general economic conditions, financial markets or the oil and natural gas industry;
---	---
●	announcements by us or our competitors of significant acquisitions or other transactions;
---	---
●	variations in the amount of our quarterly cash distributions to our unitholders;
---	---
●	changes in accounting standards, policies, guidance, interpretations or principles;
---	---
●	the failure of securities analysts to cover our common units or changes in their recommendations and estimates of our financial performance;
---	---
●	future sales of our common units; and
---	---
●	the other factors described in these “Risk Factors.”
---	---

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.

We are an “emerging growth company” as defined in the Jumpstart Our Business Act (“JOBS Act”). For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

In addition, Section 102 of the JOBS Act also provides that an “emerging growth company” can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. An “emerging growth company” can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we choose to “opt out” of such extended transition period, and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded partnership, the NYSE does not require us to have, and we do not have, a majority of independent directors on our Board of Directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to corporations. Accordingly, unitholders 49

Table of Contents will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Item 10. Directors, Executive Officers and Corporate Governance.”

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By acquiring an interest in us, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. By acquiring an interest in us, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. These provisions may have the effect of discouraging lawsuits against us and our General Partner’s officers and directors.

If a unitholder is an ineligible holder, the units of such unitholder may be subject to redemption.

We have adopted certain requirements regarding those investors who may own our units. Ineligible holders are limited partners whose nationality, citizenship or other related status would create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our General Partner with the advice of counsel. If a unitholder is an ineligible holder, in certain circumstances as set forth in our partnership agreement, the units held by such unitholder may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.

Our Series A preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

Our Series A preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.

In addition, until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units will receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. We have the right, in any four non-consecutive quarters, to elect not to pay such quarterly distribution in cash and instead have the unpaid distribution amount added to the liquidation preference at the rate of 10.0% per annum. If we make such an election in consecutive quarters or otherwise materially breach our obligations to the holders of the Series A preferred units, the distribution rate will increase to 20.0% per annum until the accumulated distributions are paid or the breach is cured, as applicable. Each holder of the Series A preferred units has the right to share in any special distributions by us of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. Accordingly, we cannot pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions. Our obligation to pay distributions on our Series A preferred units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general partnership purposes. Our obligations to the holders of the Series A preferred units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

The terms of our Series A preferred units contain covenants that may limit our business flexibility.

The terms of our Series A preferred units contain covenants preventing us from taking certain actions without the approval of the holders of 66^2^/3% of the outstanding Series A preferred units, voting separately as a class. The need to obtain the approval of holders of the Series A preferred units before taking these actions could impede our ability to take certain actions that management or the Board of Directors of our General Partner may consider to be in the best interests of our unitholders.

The affirmative vote of 66^2^/3% of the outstanding Series A preferred units, voting separately as a class, is necessary to amend our partnership agreement in any manner that is materially adverse to any of the rights, preferences 50

Table of Contents and privileges of the Series A preferred units. The affirmative vote of 66^2^/3% of the outstanding Series A preferred units voting separately as a class, is necessary to, among other things, (i) issue, authorize or create any additional Series A preferred units or any class or series of partnership interests (or any obligation or security convertible into, exchangeable for or evidencing the right to purchase any class or series of partnership interests) that, with respect to distributions on such partnership interests or distributions in respect of such partnership interests upon our liquidation, dissolution and winding up, ranks equal to or senior to the Series A preferred units or (ii) under certain circumstances, incur certain indebtedness for borrowed money.

Risks Related to Economic Conditions and Our Industry

All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available for distribution on common units.

Our revenues, operating results, cash available for distribution on common units and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil, natural gas and NGLs. Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

●	the domestic and foreign supply of and demand for oil, natural gas and NGLs;
●	the level of prices and expectations about future prices of oil, natural gas and NGLs;
---	---
●	the level of global oil and natural gas exploration and production;
---	---
●	the cost of exploring for, developing, producing and delivering oil and natural gas;
---	---
●	the price and quantity of foreign imports;
---	---
●	the level of United States domestic production;
---	---
●	political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia;
---	---
●	the ability of members of the OPEC to agree to and maintain oil price and production controls;
---	---
●	the ability of Iran to increase the export of oil and natural gas upon the relaxation of international sanctions;
---	---
●	speculative trading in crude oil, natural gas and NGL derivative contracts;
---	---
●	the level of consumer product demand;
---	---
●	weather conditions and other natural disasters, the frequency and impact of which could be increased by the effects of climate change;
---	---
●	risks associated with operating drilling rigs;
---	---
●	technological advances affecting energy consumption;
---	---
●	domestic and foreign governmental regulations and taxes;
---	---
●	the continued threat of terrorism and the impact of military and other action;
---	---
●	the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;
---	---

51

Table of Contents

●	the price and availability of alternative fuels; and
●	overall domestic and global economic conditions.
---	---

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for WTI, has ranged from a low of $(36.98) per Bbl in April 2020 to a high of $77.41 per Bbl in June 2018, and the Henry Hub spot market price of natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $6.24 per MMBtu in January 2018. On December 31, 2020 and December 30, 2020, the WTI posted price for crude oil was $48.35 per Bbl and the Henry Hub spot market price of natural gas was $2.36 per MMBtu, respectively. Reductions in prices can be caused by many factors, including increases in oil and natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand, as well as actions by the OPEC to maintain or raise production levels. This environment could cause prices to remain at current levels or to fall to lower levels.

Any substantial decline in the price of oil, natural gas and NGLs or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units. We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that can be produced economically by our operators. This may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, full-cost efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

A deterioration in general economic, business or industry conditions would materially adversely affect our results of operations, financial condition and cash available for distribution on common units.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, and slow economic growth in the United States can contribute to economic uncertainty and diminish expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. With current global economic growth slowing, demand for oil, natural gas and NGL production has, in turn, softened. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could further diminish, which could impact the price at which oil, natural gas and NGLs from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash available for distribution on common units.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units. 52

Table of Contents

Competition in the oil and natural gas industry is intense, which may adversely affect our operators’ ability to succeed.

The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

The operators of our properties may use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. Certain of the new techniques that the operators of our properties may adopt, such as horizontal drilling, infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently the operators of our properties will be less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties because of capital constraints, lease expirations, access to gathering systems, or declines in oil and natural gas prices, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash available for distribution on common units could be materially adversely affected.

The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which neither we nor the operators of our properties control. If these facilities are unavailable, our operators’ operations could be interrupted and our results of operations and cash available for distribution on common units could be materially adversely affected.

The marketability of our operators’ oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. Neither we nor the operators of our properties control these third party transportation facilities and our operators’ access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third party transportation facilities or other production facilities could adversely impact our operators’ ability to deliver to market or produce oil and natural gas and thereby cause a significant interruption in our operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our operators’ control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available for distribution on common units. 53

Table of Contents

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units.

The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our unitholders that wells drilled by the operators of our properties will be productive. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

●	unusual or unexpected geological formations;
●	loss of drilling fluid circulation;
---	---
●	title problems;
---	---
●	facility or equipment malfunctions;
---	---
●	unexpected operational events;
---	---
●	shortages or delivery delays of equipment and services;
---	---
●	compliance with environmental and other governmental requirements; and
---	---
●	adverse weather conditions.
---	---

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our common unitholders may be materially adversely affected.

Risks Related to Our Indebtedness and Derivatives

​

Our derivative activities could result in financial losses and reduce earnings.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently have entered, and may in the future enter, into derivative contracts for a portion of our future oil and natural gas production, including fixed price swaps, collars and basis swaps. In addition, on January 27, 2021, we entered into an interest rate swap with Citi, which fixed the interest rate on $150.0 million of notional, or approximately 87% of our outstanding balance on our secured revolving credit facility, at approximately 3.9% for three years. We have not designated and do not plan to designate any of our derivative contracts as hedges for accounting purposes and, as a result, record all derivative contracts on our balance sheet at fair value with changes in fair value recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative contracts. Derivative contracts also expose us to the risk of financial loss in some circumstances, including when:

●	production is less than expected;
●	the counterparty to the derivative contract defaults on its contract obligation; or
---	---

54

Table of Contents

●	the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.

In addition, these types of derivative contracts can limit the benefit we would receive from increases in the prices for oil and natural gas.

Restrictions in our secured revolving credit facility and future debt agreements could limit our growth and our ability to engage in certain activities, including our ability to pay distributions to our unitholders.

Our secured revolving credit facility has commitments up to $265.0 million and includes an elected commitment amount feature permitting aggregate commitments under the secured revolving credit facility to be increased to up to $500.0 million, subject to the limitations of our borrowing base, which is currently $265.0 million, and to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders. Our secured revolving credit facility is secured by substantially all of our assets. Our secured revolving credit facility contains various covenants and restrictive provisions that limit our ability to, among other things:

●	incur or guarantee additional debt;
●	make distributions on, or redeem or repurchase, common units, including if an event of default or borrowing base deficiency exists;
---	---
●	make certain investments and acquisitions;
---	---
●	incur certain liens or permit them to exist;
---	---
●	enter into certain types of transactions with affiliates;
---	---
●	merge or consolidate with another company; and
---	---
●	transfer, sell or otherwise dispose of assets.
---	---

Our secured revolving credit facility also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 3.5 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. Our ability to meet those financial ratios and tests can be affected by events beyond our control. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise or paying distributions to our common unitholders or OpCo common unitholders because of the limitations that the restrictive covenants under our secured revolving credit facility impose on us. For example, our secured revolving credit facility restricts us from paying distributions to our common unitholders and OpCo common unitholders if our Debt to EBITDAX Ratio exceeds 3.0 to 1.0 on a trailing twelve-month basis.

A failure to comply with the provisions of our secured revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our secured revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, cash flows from our operations may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Our secured revolving credit facility contains events of default customary for transactions of this nature, including the occurrence of a change of control. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.” 55

Table of Contents

Any significant reduction in our borrowing base under our secured revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our secured revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The borrowing base is determined based on our oil and gas properties and the oil and gas properties of our wholly owned subsidiaries. We have non-wholly owned subsidiaries whose assets are not subject to a lien and not included in borrowing base valuations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our secured revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other oil and natural gas properties as additional collateral after applicable grace periods. We do not have substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our secured revolving credit facility.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

As of December 31, 2020, we had approximately $171.6 million in borrowings outstanding under our senior secured credit facility. Our existing and any future indebtedness could have important consequences to us, including:

●	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to us;
●	covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
---	---
●	our access to the capital markets may be limited;
---	---
●	our borrowing costs may increase;
---	---
●	we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and
---	---
●	our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
---	---

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Risks Related to Our Operations

​

Our business is difficult to evaluate because we have made several significant acquisitions.

We have grown our business primarily through four material acquisitions, including the Haymaker Acquisition, the Dropdown, the Phillips Acquisition and the Springbok Acquisition, which significantly expanded our portfolio of mineral and royalty interests. We do not have historical financial statements with respect to our mineral and royalty interests for periods prior to their acquisition by the Haymaker Sellers, the Dropdown Sellers, the Phillips Sellers or the 56

Table of Contents Springbok Sellers, respectively. As a result, with respect to many of our assets, including any assets that we may acquire in the future, there is, or may be, only limited historical financial information available upon which to base an evaluation of our performance.

We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations and cash available for distribution on common units.

Because we depend on our third-party operators for all of the exploration, development and production on our properties, we have no control over the operations related to our properties. As of December 31, 2020, we received revenue from approximately 1,300 operators and we received approximately 35.6% of revenues from the top ten purchasers of our properties. During the year ended December 31, 2020, payments we received from our top purchaser accounted for approximately 7.1% of our revenues. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop imposed by state law). The operators of our properties could determine to drill and complete fewer wells on our acreage than we currently expect. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:

●	the capital costs required for drilling activities by the operators of our properties, which could be significantly more than anticipated;
●	the ability of the operators of our properties to access capital;
---	---
●	prevailing commodity prices;
---	---
●	the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
---	---
●	the operators’ expertise, operating efficiency and financial resources;
---	---
●	approval of other participants in drilling wells;
---	---
●	the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
---	---
●	the selection of technology;
---	---
●	the selection of counterparties for the marketing and sale of production; and
---	---
●	the rate of production of the reserves.
---	---

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our oil, natural gas and NGL revenues and cash available for distribution on common units. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us. Sustained reductions in production by the operators of our properties may also materially adversely affect our results of operations and cash available for distribution on common units.

We may not be able to terminate our leases if any of the operators of the properties in which we own mineral interests declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.

A failure on the part of the operators of the properties in which we own mineral interests to make royalty payments typically gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. 57

Table of Contents If we repossessed any of the properties in which we own mineral interests, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil, natural gas or NGLs at the same price as the operator it replaced.

Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties.

Our future success depends upon our ability to acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on our properties or we acquire properties containing proved reserves, or both. Because we depend on our third-party operators for all of the exploration, development and production on our properties, we have no control over the operations related to our properties. In addition, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and gas reserves or otherwise maintain an asset base. To increase reserves and production, we would need the operators of our properties to undertake replacement activities or use third parties to accomplish these activities.

Our failure to successfully identify, complete and integrate acquisitions of properties or businesses would slow our growth and could materially adversely affect our results of operations and cash available for distribution on common units.

We depend in part on acquisitions to grow our reserves, production and cash generated from operations. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:

●	recoverable reserves;
●	future oil, natural gas and NGL prices and their applicable differentials;
---	---
●	development plans;
---	---
●	operating costs; and
---	---
●	potential environmental and other liabilities.
---	---

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are often not performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Unless our operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold assets, which could result in unforeseen operating difficulties. In addition, if we acquire interests in new states, we may be subject to additional and unfamiliar 58

Table of Contents legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing business. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, potential future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available for distribution on common units. The inability to effectively manage these acquisitions could reduce our focus on subsequent acquisitions, which, in turn, could negatively impact our growth and cash available for distribution on common units.

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit. Any acquisition involves potential risks, including, among other things:

●	the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures and production costs;
●	a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
---	---
●	a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
---	---
●	the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
---	---
●	mistaken assumptions about the overall cost of equity or debt;
---	---
●	our inability to obtain satisfactory title to the assets we acquire;
---	---
●	an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and
---	---
●	the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.
---	---

In addition, we entered into a transition services agreement in connection with the Phillips Acquisition and the Springbok Acquisition, and we may enter into transition services agreements with future sellers (or their affiliates) of any mineral and royalty interests that we may acquire. The services to be provided under such transition services agreements may not be performed timely and effectively, and any significant disruption in such transition services or unanticipated costs related to such services could adversely affect our business and results of operations.

If we are unable to make acquisitions on economically acceptable terms from our Sponsors, the Contributing Parties or third parties, our future growth will be limited.

Our ability to grow depends in part on our ability to make acquisitions that increase our cash generated from our mineral and royalty interests. The acquisition component of our strategy is based, in large part, on our expectation of ongoing acquisitions from industry participants, including our Sponsors and the Contributing Parties. Although a portion of the mineral and royalty interests acquired in connection with the Dropdown were subject to the right of first offer provided by the Contributing Parties, that right of first refusal is now expired, and there can be no assurance that, should the Contributing Parties choose to sell any additional mineral and royalty interests, any offer will be made to us, and there 59

Table of Contents can be no assurance we will reach agreement on the terms with respect to the assets or any other acquisition opportunities offered to us by any of our Sponsors and the Contributing Parties or be able to obtain financing for such acquisition opportunities. Furthermore, many factors could impair our access to future acquisitions, including a change in control of any of our Sponsors and the Contributing Parties. A material decrease in the sale of oil and natural gas properties by any of our Sponsors and the Contributing Parties or by third parties would limit our opportunities for future acquisitions and could materially adversely affect our business, results of operations, financial condition and ability to pay quarterly cash distributions to our unitholders.

Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution on common units may be materially adversely affected.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may prove to be incorrect.

Our historical estimates of proved reserves and related valuations as of December 31, 2020, 2019 and 2018 were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. In estimating our reserves, we and our reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (the “FASB”), we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

We do not intend to retain cash from our operations for replacement capital expenditures. Unless we replenish our oil and natural gas reserves, our cash generated from operations and our ability to pay distributions to our unitholders could be materially adversely affected.

Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our oil and natural gas reserves and the operators’ production thereof and our 60

Table of Contents cash generated from operations and ability to pay distributions are highly dependent on the successful development and exploitation of our current reserves. As of December 31, 2020, the average estimated yearly five-year decline rate for our existing proved developed producing reserves is 12.5%. However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to acquire additional reserves to replace the current and future production of our properties at economically acceptable terms, which could materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units.

We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution on common units. We do not intend to retain cash from our operations for replacement capital expenditures primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells.

Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain or grow our asset base, we would expect to reduce our distributions. With our reserves decreasing, if we do not reduce our distributions, then a portion of the distributions may be considered a return of part of the unitholders’ investment in us as opposed to a return on the unitholders’ investment.

We rely on a few key individuals whose absence or loss could materially adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. We have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with certain entities controlled by affiliates of certain of our Sponsors and Benny Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective services agreements, affiliates of certain of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. The loss of their services, or the services of one or more members of our executive team or those providing services to us pursuant to a contract, could materially adversely affect our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

Loss of our or our operators’ information and computer systems could materially adversely affect our business.

We are dependent on our and our operators’ information systems and computer-based programs. If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. In addition to the service providers who provide substantial services to us under our services agreement with Kimbell Operating, we rely on third party service providers to perform some of our data entry, investor relations and other functions. If the programs or systems used by our third-party service providers are not adequately functioning, we could experience loss of important data. Any of the foregoing consequences could materially adversely affect our business.

Title to the properties in which we have an interest may be impaired by title defects.

We depend in part on acquisitions to grow our reserves, production and cash generated from operations. We have in the past elected not to, and may in the future not elect to, incur the expense of retaining lawyers to examine the title to acquired mineral interests. Rather, we may rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of operations, financial condition and cash available for distribution on common units. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has 61

Table of Contents greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

The Haymaker Sellers, Dropdown Sellers, Phillips Sellers and Springbok Sellers have limited indemnity obligations to us for liabilities arising out of the ownership and operation of our assets prior to the Haymaker Acquisition, the Dropdown, the Phillips Acquisition and the Springbok Acquisition, respectively, including title defects.

In connection with the Haymaker Acquisition, the Dropdown, the Phillips Acquisition and the Springbok Acquisition, we entered into purchase agreements with the Haymaker Sellers, Dropdown Sellers, Phillips Sellers and Springbok Sellers, respectively, that govern, among other things, their obligation to indemnify us for certain liabilities associated with the entities and assets acquired. Under the purchase agreements, the Haymaker Sellers, Dropdown Sellers, Phillips Sellers and Springbok Sellers are required, severally but not jointly, to indemnify us for any federal, state and local income tax liabilities attributable to the ownership and operation of the mineral and royalty interests and the associated entities prior to the closing of each respective acquisition until 30 days after the applicable statute of limitations. In addition, pursuant to the purchase agreements, the Haymaker Sellers, Dropdown Sellers, Phillips Sellers and Springbok Sellers, severally but not jointly, indemnified us indefinitely for losses arising from certain liens and title defects created during their ownership of the entities and assets acquired in connection with the Haymaker Acquisition, the Dropdown, the Phillips Acquisition and the Springbok Acquisition, respectively.

Except as otherwise described above, the indemnification obligations of the Haymaker Sellers, Dropdown Sellers and Phillips Sellers have expired pursuant to the terms of contribution or purchase agreement. Moreover, the Haymaker Sellers’, Dropdown Sellers’ and the Phillips Sellers’ ongoing indemnification obligations are subject to limitations, including indemnity caps, and may not protect us against all liabilities or other problems associated with the entities and assets contributed to us or acquired. For example, the existence of a material title deficiency covering a material amount of our assets can render a lease worthless and could materially adversely affect our financial condition, results of operations and cash available for distribution on common units. We do not obtain title insurance covering mineral leaseholds, and our failure to cure any title defects may delay or prevent us from realizing the benefits of ownership of the mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has a greater risk of title defects than developed acreage. If there are any title defects, or defects in the assignment of leasehold rights in properties in which we hold an interest, our business, results of operations and cash available for distribution on common unit may be adversely affected.

The indemnities that the Haymaker Sellers, Dropdown Sellers, Phillips Sellers and Springbok Sellers agreed to provide under purchase agreements may be inadequate to fully compensate us for losses we may suffer or incur as a result of liabilities arising out of the ownership and operation of our assets prior to the closing of the Haymaker Acquisition, the Dropdown, the Phillips Acquisition or the Springbok Acquisition. Even if we are insured or indemnified against such risks, we may be responsible for costs or penalties to the extent our insurers or indemnitors do not fulfill their obligations to us, and the payment of any such costs or penalties could be significant. The occurrence of any losses that are not covered under our insurance plans could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.

The potential drilling locations identified by the operators of our properties are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of the operators of our properties to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, the potential drilling locations identified by the operators of our properties are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable the operators of our properties to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, the operators of our properties may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or 62

Table of Contents abandonment of the well. If the operators of our properties drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

We cannot assure our unitholders that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potential drilling locations. As such, the actual drilling activities of the operators of our properties may materially differ from those presently identified, which could materially adversely affect our business, results of operation and cash available for distribution on common units.

Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our operators’ failure to drill sufficient wells to hold acreage may result in loss of the lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. Any reduction in our operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations which may terminate our overriding royalty interests derived from such leases. If our royalties are derived from mineral interests and production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests. Any such losses of our operators or lessees could materially and adversely affect the growth of our financial condition, results of operations and cash available for distribution on common units.

The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, the operators of our properties rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If the operators of our properties are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. In addition, they may not have long-term contracts securing the use of their rigs, and the operator of those rigs may choose to cease providing services to them. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.

Operating hazards and uninsured risks may result in substantial losses to the operators of our properties, and any losses could materially adversely affect our results of operations and cash available for distribution on common units.

The operators of our properties will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to the operators of our properties due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. 63

Table of Contents

If the operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash available for distribution on common units may be adversely affected.

We depend in part on acquisitions to grow our reserves, production and cash generated from operations. In connection with these acquisitions, and in subsequent acquisitions, record title to a significant amount of the acquired mineral and royalty interests was conveyed to us or our subsidiaries by asset assignment, and we or our subsidiaries became the record owner of these interests. Upon such a change in ownership, and at regular intervals pursuant to routine audit procedures at each of our operators otherwise at its discretion, the operator of the underlying property has the right to investigate and verify the title and ownership of mineral and royalty interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the operator may suspend payment of the related royalty. If an operator of our properties is not satisfied with the documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full payments that would have been made during the suspense period, without interest. Certain of our operators impose significant documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time. During the time that an operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest. If a significant amount of our royalty interests are placed in suspense, our quarterly distribution may be reduced significantly. With each acquisition, we expect the risk of payment suspense to be greatest during the immediately succeeding fiscal quarters due to the number of title transfers that will take place.

We will be required to take write-downs of the carrying values of our properties if commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.

After evaluating certain external factors in the first quarter of 2020, including the significant decline in oil and natural gas prices related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries and other supply factors, as well as longer-term commodity price outlooks, we determined that significant drilling uncertainty existed regarding our PUD reserves that were included in our total estimated proved reserves as of December 31, 2019, as well as our unevaluated oil and natural gas properties. Specifically, with respect to our PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), we determined that we did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties for the three months ended March 31, 2020. We similarly recorded an impairment on the value of our unevaluated oil and natural gas properties for the three months ended March 31, 2020, which primarily were acquired in various acquisitions since our IPO. There were no additional impairments to unevaluated properties in the remainder of 2020.

As a result of our full cost ceiling analysis, we recorded an impairment on our oil and natural gas properties of $251.6 million during the year ended December 31, 2020. The impairment can primarily be attributed to the decline in the 12-month average price of oil and natural gas as a result of the continued impact of the external factors mentioned above. As of December 31, 2020, the 12-month average prices of oil and natural gas were $39.57 per Bbl of oil and $1.99 per Mcf of natural gas. These prices represent a 28.9% and 22.9% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2019, which were $55.69 per Bbl of oil and $2.58 per Mcf of natural gas. We 64

Table of Contents recorded an impairment on our oil and natural gas properties of $169.2 million during the year ended December 31, 2019 as a result of our quarterly full cost ceiling analysis and a decline in the 12-month average price of oil and natural gas. As of December 31, 2019, the 12-month average prices of oil and natural gas were $55.69 per Bbl of oil and $2.58 per Mcf of natural gas. These prices represent a 15.1% and 16.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2018, which were $65.56 per Bbl of oil and $3.10 per Mcf of natural gas. We also recorded an impairment expense on our oil and natural gas properties of $67.3 million during the year ended December 31, 2018. Of this amount, an impairment expense of $54.8 million was recorded as a result of our quarterly full-cost ceiling analysis for the three months ended March 31, 2018 and an impairment expense of $12.6 million was recorded for the three months ended December 31, 2018 as a result of the Dropdown purchase price exceeding the value of the proved developed reserves added to the full-cost ceiling. Because we do not intend to book PUD reserves going forward additional impairment charges could be recorded in connection with future acquisitions. Moreover, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are recorded.

Tax Risks to Common Unitholders

We may incur substantial income tax liabilities on our allocable share of income from the Operating Company.

We are classified as a corporation for United States federal income tax purposes and for state income tax purposes in most states in which we do business. Current law provides that we are subject to federal income tax on our taxable income at the United States corporate tax rate, which is currently 21.0%, and to state income tax at rates that vary from state to state. The amount of cash available for distribution to you will be reduced by the amount of any such income taxes payable by us.

Taxable gain or loss on the sale of our common units could be more or less than expected.

A holder of common units generally will recognize capital gain or loss on a sale, an exchange, certain redemptions, or other taxable dispositions of our common units equal to the difference, if any, between the amount realized upon the disposition of such common units and the holder’s adjusted tax basis in those units. To the extent that the amount of our distributions exceeds our current and accumulated earnings and profits, the distributions will be treated as a tax-free return of capital and will reduce a holder’s tax basis in the common units. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in the common units, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the common units.

Our tax liability may be greater than expected if we do not generate sufficient depletion deductions to offset our taxable income and reduce our tax liability.

We expect to generate depletion deductions that we can use to offset our taxable income. As a result, we do not expect to pay material United States federal income tax through 2026. This estimate is based upon assumptions we have made regarding, among other things, the Operating Company’s income and depletion expenses, and it ignores the effect of any possible acquisitions of additional assets.

While we expect that our depletion deductions will be available to us as a benefit, in the event that the depletion deductions are not available as expected, are successfully challenged by the Internal Revenue Service (“IRS”) (in a tax audit or otherwise) or are subject to future limitations, our ability to realize these benefits may be limited. Further, the IRS or other tax authorities could challenge one or more tax positions we or the Operating Company take. Further, any change in law may affect our tax positions.

Future tax legislation could have an adverse impact on our cash tax liabilities, results of operations and financial condition, which could affect our cash available for distribution on common units and the value of our common units.

Changes in federal income tax law relating to our tax treatment could result in (i) our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution on common units and (ii) a greater portion of our distributions being treated as taxable dividends. Congress could, in the future, enact tax law changes, 65

Table of Contents such as increasing the corporate tax rate or reducing or eliminating certain tax preferences currently available with respect to production of oil and gas. For example, President Biden has proposed increasing the U.S. corporate income tax rate from 21% to 28% and eliminating tax preferences available with respect to production of fossil fuels.  Such changes are potentially more likely under the new Democratic party-controlled Congress.  We are unable to predict whether any such changes will ultimately be enacted, but any such changes could have a material impact on our cash tax liabilities, results of operations or financial condition. Moreover, we are subject to tax in numerous jurisdictions. Changes in current law in these jurisdictions could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution on common units.

Certain decreases in the price of our common units could adversely affect our amount of cash available for distribution on common units.

Changes in certain market conditions may cause the price of our common units to decrease. If holders of our OpCo common units and Class B units exercise their right to exchange those units for common units at a point in time when the price of our common units is relatively low, the ratio of our income tax deductions to gross income could decline. Any resulting decline in the ratio of our income tax deductions to gross income could result in our being subject to tax sooner than expected, our tax liability being greater than expected or a greater portion of our distributions being treated as taxable dividends.

The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our units for United States federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your United States federal income tax return.

Distributions we pay with respect to our units constitute “dividends” for United States federal income tax purposes to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits are not be treated as “dividends” for United States federal income tax purposes; instead, they are treated first as a tax-free return of capital to the extent of your tax basis in your units and then as capital gain realized on the sale or exchange of such units.

If you are a holder of our common units, the IRS Form 1099-DIV may not be consistent with our determination of the amount that constitutes a “dividend” to you for United States federal income tax purposes or you may receive a corrected IRS Form 1099-DIV (and you may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify you of available information to assist you with your income tax reporting (such as posting the correct information on our website). However, the information that we provide to you may be inconsistent with the amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return.

The portion of our distributions taxable as dividends may be greater than expected.

If we make distributions from current or accumulated earnings and profits as computed for United States federal income tax purposes, such distributions will generally be taxable to our common unitholders as dividend income for United States federal income tax purposes. Under current law, distributions paid to non-corporate United States common unitholders will be subject to United States federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. We estimate that we will not have material current or accumulated earnings and profits as computed for United States federal income tax purposes through 2023. However, it is difficult to predict whether we will generate earnings and profits in any given tax year. Although we expect that a significant portion of our distributions to common unitholders will exceed our current and accumulated earnings and profits as computed for United States federal income tax purposes, and therefore constitute a non-taxable return of capital to each unitholder to the extent of such unitholder's basis in its common units, this may not occur. In addition, although distributions treated as a return of capital are generally non-taxable to the extent of a unitholder's basis in its common units, such distributions will reduce such unitholder's adjusted tax basis in its common units, which will result in an increase in the amount of gain (or a decrease in the amount of loss) that will be recognized by the unitholder on a future disposition of our common units, and to the extent any such distribution exceeds a unitholder's basis in its common units, such distribution will be treated as gain on the sale or exchange of such common units. 66

Table of Contents

If the Operating Company were to become a publicly traded partnership taxable as a corporation for United States federal income tax purposes, we and the Operating Company might be subject to potentially significant tax inefficiencies.

We intend to operate such that the Operating Company does not become a publicly traded partnership taxable as a corporation for United States federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, it is possible that certain exchanges of the OpCo common units could cause the Operating Company to be treated as a publicly traded partnership. Applicable United States Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges of the OpCo common units qualify for one or more such safe harbors. If the Operating Company were to become a publicly traded partnership taxable as a corporation for United States federal income tax purposes, significant tax inefficiencies might result for us and for the Operating Company including as a result of our inability to file a consolidated United States federal income tax return with the Operating Company. In addition, we would no longer have the benefit of increases in the tax bases of the Operating Company’s assets.

Legal, Environmental and Regulatory Risks

​

Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce our cash available for distribution on common units.

Operations on the properties in which we hold interests are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, discharges or releases of pollutants or wastes and production and conservation matters (discussed in more detail below). From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. For example, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order suspending new fossil fuel leasing and permitting on federal lands for 60 days. In addition, President Biden issued certain Executive Orders focused on addressing climate change, which, among other things, directed the Secretary of the Interior to pause entering into new oil and natural gas leases on public lands or offshore waters “to the extent possible” pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. President Biden also issued an Executive Order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions during the prior administration that may be inconsistent with the current administration’s policies. Further actions of President Biden, and the Biden Administration, may negatively impact oil and gas operations and favor renewable energy projects in the United States, which may negatively impact the demand for oil and natural gas.

In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and safety and the environment. Failure to comply with these laws and regulations by the operators of our properties may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of their operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management.

Laws and regulations governing exploration and production may also affect production levels. The operators of our properties must comply with federal and state laws and regulations governing conservation matters, including:

●	provisions related to the unitization or pooling of the oil and natural gas properties;
●	the establishment of maximum rates of production from wells;
---	---
●	the spacing of wells;
---	---

67

Table of Contents

●	the plugging and abandonment of wells; and
●	the removal of related production equipment.
---	---

Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of operators and third party downstream natural gas transporters.

The operators of our properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

The operators of our properties may be required to make significant expenditures to comply with the governmental laws and regulations described above and are subject to potential fines and penalties if they are found to have violated these laws and regulations. These and other potential regulations could increase the operating costs of the operators and delay production from our properties, which could reduce the amount of cash available for distribution to our common unitholders.

The operators of our properties are subject to complex and evolving environmental and occupational health and safety laws and regulations. As a result, they may incur significant delays, costs and liabilities that could materially adversely affect our business and financial condition.

The operators of our properties may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety laws and regulations applicable to their exploration, development and production activities on our properties. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and safety. These laws, regulations and enforcement policies have become increasingly strict over time, resulting in longer waiting periods to receive permits and other regulatory approvals, and we believe this trend will continue. These laws include, but are not limited to, the federal Clean Air Act (and comparable state laws and regulations that impose obligations related to air emissions), the Clean Water Act and OPA (and comparable state laws and regulations that impose requirements related to discharges of pollutants into regulated bodies of water), the RCRA (and comparable state laws that impose requirements for the handling and disposal of waste), the CERCLA, also known as the “Superfund” law, and the community right to know regulations under Title III of the act (and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by our operators or at locations our operators sent waste for disposal and comparable state laws that require organization and/or disclosure of information about hazardous materials our operators use or produce), the federal Occupational Safety and Health Act (which establishes workplace standards for the protection of health and safety of employees and requires a hazardous communications program) and the Endangered Species Act and the Migratory Bird Treaty Act (and comparable state laws that seek to ensure activities do not jeopardize endangered or threatened animals, fish, plant species by limiting or prohibiting construction activities in areas that are inhabited by such species and penalizing the taking, killing or possession of migratory birds).

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Additionally, actions taken by federal or state agencies under these laws and regulations, such as the designation of previously unprotected species as being endangered or threatened or the designation of previously unprotected areas as a critical habitat for such species, can cause the operators of our properties to incur additional costs or become subject to operating restrictions.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause the operators of our properties to become liable for the conduct of others or for consequences of our operators’ actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and worker health and safety impacts of operations by the operators of our properties. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities, significantly increase our operating or compliance costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business. If the operators of our properties are not able to 68

Table of Contents recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be materially and adversely affected. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The operators of our properties use hydraulic fracturing for the completion of their wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation’s pores to the wellbore. Typically, the fluid used in this process is primarily water. In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply. If the operators of our properties are unable to obtain water to use in their operations from local sources or are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil and natural gas, which could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.

Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that hydraulic fracturing activities can impact drinking water resources under certain circumstances, including large volume spills and inadequate mechanical integrity of wells. These and other ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for the operators of our properties to perform fracturing and increase the costs of compliance and doing business. Additional legislation or regulation could also make it easier for parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. There has also been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, the use of water and the potential for impacts to surface water, groundwater and the environment generally. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business, could create adverse effects on our operators, including creating delays related to the issuance of permits and, depending on the specifics of any particular proposal that is enacted, could be material.

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations or taken other regulatory actions to curtail injection of produced water to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

The adoption of climate change legislation and regulations could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore oil and natural gas production sources in the United States on an annual basis, which include operations on certain of our properties. Most recently, President Biden has issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies, including, for example, directing the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and 69

Table of Contents gas permitting and leasing practices.  An expansion of federal climate regulations could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator’s ability to economically develop our properties. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. In June 2017, President Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated. In November 2019, the State Department formally informed the United Nations of the United States’ withdrawal from the Paris Agreement and withdrew from the Agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reverses this withdrawal, and the United States formally re-joined the Paris Agreement on February 19, 2021. Initiatives to implement the Paris Agreement goals or other or similar initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our operators’ ability to economically develop our properties.

Congress has from time to time considered legislation to reduce emissions of GHGs and may consider adopting legislation to reduce GHG emissions at the federal level in the coming years. In the absence of federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

Moreover, activists and members of the investment community concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for operators on our properties to secure funding for exploration and production activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or restrict more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for operators to engage in exploration and production activities.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events; if any of these effects were to occur, they could materially adversely affect our properties and operations.

General Risk Factors

​

Increased costs of capital could materially adversely affect our business.

Our business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, and place us at a competitive disadvantage. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results. 70

Table of Contents

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls are or will be successful, able to maintain adequate controls over our financial processes and reporting in the future or able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. However, for as long as we are an “emerging growth company” under the JOBS Act or a non-accelerated filer, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

​

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The information required by Item 2 is contained in “Item 1. Business,” and such information is incorporated into this Item 2 by reference herein.

Item 3. Legal Proceedings

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.

Items 4. Mine Safety Disclosures

Not applicable.

​ 71

Table of Contents Part II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our common units are listed on the NYSE under the symbol “KRP.” As of February 19, 2021, there were 38,918,689 common units outstanding held by 191 holders of record and 20,779,781 Class B units outstanding held by 27 holders of record. Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record.

Cash Distribution Policy

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in our partnership agreement and in the limited liability company agreement of the Operating Company and is generally defined below. We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

In light of the unprecedented global economic impact resulting from the COVID-19 pandemic, the related impact to the United States oil and natural gas markets and the potential for further curtailments of production, the Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2020 for the repayment of $3.9 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2020. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future. Any such allocation, whether for debt repayment or another purpose, would have the effect of reducing the amount of cash distribution to our common unitholders.

We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well.

We expect to pay our distributions within 45 days of the end of each quarter.

Definition of Available Cash

Our partnership agreement generally defines “available cash” for any quarter as:

●	the sum of:
●	all of our and our subsidiaries’ cash and cash equivalents on hand at the end of that quarter;
---	---

72

Table of Contents

●	as determined by our General Partner, all of our and our subsidiaries’ cash or cash equivalents on hand on the date of determination of available cash for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter; and
●	all of our cash and cash equivalents received by us from distributions on OpCo common units by the Operating Company made with respect to that quarter subsequent to the end of that quarter and prior to the date of distribution of available cash;
---	---
●	less the amount of cash reserves established by our General Partner to:
---	---
●	provide for the proper conduct of our business (including reserves for our future capital expenditures and for our future credit needs);
---	---
●	comply with applicable law or any debt instrument or other agreement or obligation to which we or our subsidiaries are a party or to which our or our subsidiaries’ assets are subject; or
---	---
●	provide funds for distributions to our unitholders and to our General Partner for any one or more of the next four quarters;
---	---

The limited liability company agreement of the Operating Company generally defines “available cash” as:

●	the sum of:
●	all cash and cash equivalents of the Operating Company and its subsidiaries on hand at the end of that quarter; and
---	---
●	as determined by the managing member of the Operating Company, all cash or cash equivalents of the Operating Company and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter;
---	---
●	less the amount of cash reserves established by the managing member of the Operating Company to:
---	---
●	provide for the proper conduct of the business of the Operating Company and its subsidiaries (including reserves for future capital expenditures and for future credit needs of the Operating Company and its subsidiaries);
---	---
●	comply with applicable law or any debt instrument or other agreement or obligation to which the managing member of the Operating Company, the Operating Company or any of their subsidiaries is a party or to which its assets are subject; and
---	---
●	provide funds for distributions to the Operating Company’s unitholders for any one or more of the next four quarters.
---	---

Working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to unitholders, and with the intent of the borrower to repay such borrowings within 12 months with funds other than additional working capital borrowings.

In addition, the limited liability company agreement of our General Partner contains provisions that prohibit certain actions without a supermajority vote of at least 66^2^/3% of the members of the Board of Directors, including: (i) the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters; (ii) the reservation of a portion of cash generated from operations to finance acquisitions; (iii) modifications to the definition of “available cash” in our partnership agreement; and (iv) the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units. 73

Table of Contents Method of Distributions

Series A preferred units

Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. We have the right, in any four non-consecutive quarters, to elect not to pay such quarterly distribution in cash and instead have the unpaid distribution amount added to the liquidation preference at the rate of 10.0% per annum. If we make such an election in consecutive quarters or otherwise materially breach our obligations to the holders of the Series A preferred units, the distribution rate will increase to 20.0% per annum until the accumulated distributions are paid or the breach is cured, as applicable. Each holder of Series A preferred units has the right to share in any special distributions by us of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. We cannot pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions.

Class B units

Each holder of Class B units has paid five cents per Class B unit to us as an additional capital contribution for the Class B units (such aggregate amount, the “Class B Contribution”) in exchange for Class B units. Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution subsequent to distributions on the Series A preferred units but prior to distributions on our common units.

Common Units

Subject to the distribution preferences of the Series A preferred units and the Class B units, each common unit is entitled to receive cash distributions to the extent we distribute available cash. Common units do not accrue arrearages. Subject to the voting rights of the Series A preferred units, our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank.

General Partner Interest

Our General Partner owns a non-economic general partner interest in us and therefore is not entitled to receive cash distributions. However, it may acquire common units and other partnership interests in the future and will be entitled to receive pro rata distributions in respect of those partnership interests.

Securities Authorized for Issuance under Equity Compensation Plans

See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2020.

Unregistered Sales of Equity Securities

On April 17, 2020, in connection with the closing of the Springbok Acquisition, (i) we issued 2,224,358 common units and 2,497,134 Class B units and (ii) the Operating Company issued 2,497,134 OpCo common units to the Springbok Sellers, as described in a Current Report on Form 8-K, filed with the SEC on April 20, 2020. 74

Table of Contents The following table provides information about the issuance of common units in exchange for OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018, by and among us, the General Partner, the Operating Company and the holders of OpCo common units and Class B units from time to time party thereto.

​	​	​	​	​
​	​	Total Number of Common Units Issued	​	Total Number of OpCo Common Units and Class B Units Exchanged
January 27, 2020	​	​	​	​
EIGF Aggregator III LLC	​	702,071	​	(702,071)
TE Drilling Aggregator LLC	​	47,929	​	(47,929)
January 28, 2020	​	​	​	​
EIGF Aggregator III LLC	​	3,897,483	​	(3,897,483)
TE Drilling Aggregator LLC	​	266,076	​	(266,076)
September 8, 2020	​	​	​	​
Haymaker Management, LLC	​	863,120	​	(863,120)
September 21, 2020	​	​	​	​
Springbok Energy Partners II Holdings, LLC	​	1,498,280	​	(1,498,280)

​

The issuance of each of the foregoing securities was exempt from the registration requirements of the Securities Act in reliance upon Section 4(a)(2) of the Securities Act.

Sales of Reacquired Securities

The following table provides information about purchases of our common units during the three months ended December 31, 2020.

​	​	​	​	​	​	​	​	​	​
Period	​	Total Number of Common Units Purchased(1)	​	Average Price Paid per Common Unit		​	Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs(2)	​	Maximum Number of Common Units That May Yet be Purchased Under the Plans or Programs(2)
October 1, 2020 - October 31, 2020	​	—	​	$	—	​	—	​	—
November 1, 2020 - November 30, 2020	​	—	​	$	—	​	—	​	—
December 1, 2020 - December 31, 2020	​	28,163	​	$	9.48	​	—	​	—
(1)	During the three months ended December 31, 2020, 28,163 common units were withheld to satisfy tax-withholding obligations arising in conjunction with the vesting of restricted units. The required withholding is calculated using the closing sales price per common unit reported by the New York Stock Exchange on the date prior to the applicable vesting date.
---	---
(2)	We did not have at any time during the quarter ended December 31, 2020, and currently do not have, a common unit repurchase program in place.
---	---

​

​ 75

Table of Contents Item 6. Selected Financial Data

Kimbell Royalty Partners, LP was formed in October 2015. The mineral and royalty interests comprising our initial assets were contributed to us by the Contributing Parties at the closing of our IPO on February 8, 2017. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of Rivercrest Royalties, LLC (our “Predecessor”), and does not include the results of the Partnership as a whole. At the time of our IPO, the mineral and royalty interests underlying the oil, natural gas and NGL production revenues of our Predecessor represented approximately 11% of our Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016. Additionally, our results of operations may not be comparable from period to period as a result of the Springbok Acquisition during the year ended December 31, 2020, the Phillips Acquisition and Buckhorn Acquisition during the year ended December 31, 2019 and the Haymaker Acquisition and the Dropdown during the year ended December 31, 2018.

The following table sets forth, as of the dates and for the periods indicated, our selected financial information, which is derived from our audited consolidated financial statements for the respective periods. The information should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto contained in “Item 8. Financial Statements and Supplementary Data.” 76

Table of Contents

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	Partnership											​	​	Predecessor
​	​	Year Ended December 31,								​	Period fromFebruary 8, 2017 to December 31,		​	​	Period from January 1, 2017 to February 7,		​	Year Ended December 31,
​	​	2020			2019		​	2018		​	2017		​	​	2017			2016
Statement of Operations Data:	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Revenue	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Oil, natural gas and NGL revenues	​	$	92,586,685	​	$	107,480,446	​	$	65,713,112	​	$	29,943,920	​	​	$	318,310	​	$	3,606,659
Lease bonus and other income	​	​	345,771	​	​	2,477,145	​	​	1,213,550	​	​	721,172	​	​	​	—	​	​	—
(Loss) gain on commodity derivative instruments, net	​	​	(2,450,541)	​	​	(1,732,321)	​	​	3,331,548	​	​	(318,829)	​	​	​	—	​	​	—
Total revenues	​	​	90,481,915	​	​	108,225,270	​	​	70,258,210	​	​	30,346,263	​	​	​	318,310	​	​	3,606,659
Cost and expenses	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Production and ad valorem taxes	​	​	6,389,231	​		7,719,949	​		4,399,667	​		2,452,058	​	​		19,651	​		280,474
Depreciation, depletion and accretion expense	​	​	47,988,796	​		52,118,367	​		25,213,043	​		15,546,341	​	​		113,639	​		1,604,208
Impairment of oil and natural gas properties	​	​	251,558,557	​		169,150,255	​		67,311,501	​		—	​	​		—	​		4,992,897
Marketing and other deductions	​	​	9,376,375	​		8,145,397	​		4,652,313	​		1,648,895	​	​		110,534	​		750,792
General and administrative expenses	​	​	25,902,496	​		22,666,601	​		16,847,328	​		8,191,792	​	​		532,035	​		1,746,218
Total costs and expenses	​	​	341,215,455	​		259,800,569	​		118,423,852	​		27,839,086	​	​		775,859	​		9,374,589
Operating (loss) income	​	​	(250,733,540)	​		(151,575,299)	​		(48,165,642)	​		2,507,177	​	​		(457,549)	​		(5,767,930)
Other income (expense)	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Equity income in affiliate	​	​	763,988	​	​	80,481	​	​	—	​	​	—	​	​	​	—	​	​	—
Interest expense	​	​	(6,430,061)	​		(5,813,702)	​		(4,091,900)	​		(791,437)	​	​		(39,307)	​		(424,841)
Loss on extinguishment of debt	​	​	(476,350)	​	​	—	​	​	—	​	​	—	​	​	​	—	​	​	—
Other expense	​	​	(100,000)	​	​	—	​	​	—	​	​	—	​	​	​	—	​	​	—
Net (loss) income before income taxes	​	​	(256,975,963)	​	​	(157,308,520)	​	​	(52,257,542)	​	​	1,715,740	​	​	​	(496,856)	​	​	(6,192,771)
(Benefit from) provision for income taxes	​	​	(885,193)	​	​	899,425	​	​	24,681	​		—	​	​		—	​		—
State income taxes	​	​	—	​		—	​		—	​		—	​	​		—	​		19,848
Net (loss) income	​	​	(256,090,770)	​	​	(158,207,945)	​	​	(52,282,223)	​	​	1,715,740	​	​	​	(496,856)	​	​	(6,212,619)
Distribution and accretion on Series A preferred units	​	​	(7,810,588)	​	​	(13,878,336)	​	​	(6,310,040)	​	​	—	​	​	​	—	​	​	—
Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests	​	​	96,642,334	​	​	89,148,428	​	​	1,855,681	​	​	—	​	​	​	—	​	​	—
Distribution on Class B units	​	​	(91,869)	​	​	(94,429)	​	​	(30,967)	​	​	—	​	​	​	—	​	​	—
Net (loss) income attributable to common units	​	$	(167,350,893)	​	$	(83,032,282)	​	$	(56,767,549)	​	$	1,715,740	​	​	$	(496,856)	​	$	(6,212,619)
Net (loss) income attributable to common units	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Basic	​	$	(4.85)	​	$	(3.92)	​	$	(3.08)	​	$	0.11	​	​	$	(0.82)	​	$	(10.28)
Diluted	​	$	(4.85)	​	$	(3.92)	​	$	(3.08)	​	$	0.10	​	​	$	(0.82)	​	$	(10.28)
Cash distributions declared and paid	​	​	0.68	​	​	1.56	​	​	1.70	​	$	1.20	​	​	​	*	​	​	*
Statement of Cash Flows Data:	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Net cash provided by (used in):	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Operating activities	​	$	62,245,341	​	$	80,702,448	​	$	33,202,980	​	$	18,573,481	​	​	$	186,719	​	$	1,086,603
Investing activities	​	$	(90,827,734)	​	$	(15,590,458)	​	$	(200,928,162)	​	$	(125,910,708)	​	​	$	(523)	​	$	(97,464)
Financing activities	​	$	24,183,120	​	$	(66,681,727)	​	$	177,873,674	​	$	112,962,722	​	​	$	—	​	$	(863,000)
Other Financial Data:	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Adjusted EBITDA (1)	​	$	65,873,743	​	$	80,713,596	​	$	44,171,393	​	$	19,170,760	​	​	$	(293,488)	​	$	1,434,234
Selected Balance Sheet Data:	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Cash and cash equivalents	​	$	9,804,977	​	$	14,204,250	​	$	15,773,987	​	$	5,625,495	​	​	$	692,077	​	$	505,880
Total assets	​	$	564,634,193	​	$	748,594,054	​	$	753,285,373	​	$	295,291,004	​	​	$	19,915,596	​	$	20,538,731
Long‑term debt	​	$	171,550,142	​	$	100,135,477	​	$	87,309,544	​	$	30,843,593	​	​	$	10,598,860	​	$	10,598,860
Total liabilities	​	$	186,333,353	​	$	108,699,208	​	$	91,109,570	​	$	33,225,570	​	​	$	11,431,068	​	$	11,906,869
Total equity	​	$	335,634,738	​	$	564,985,114	​	$	592,726,797	​	$	262,065,434	​	​	$	8,484,528	​	$	8,361,862

* Information is not applicable for the periods prior to the initial public offering.

(1)	For more information, please read “—Non-GAAP Financial Measures.”

77

Table of Contents Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution on Common Units

Adjusted EBITDA and cash available for distribution on common units are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution on common units are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.

We define Adjusted EBITDA as net income (loss), net of non-cash unit-based compensation, change in fair value of open commodity derivative instruments, transaction costs, impairment of oil and natural gas properties, income taxes, interest expense and depreciation and depletion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution on common units as Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

Adjusted EBITDA and cash available for distribution on common units should not be considered an alternative to net income (loss), oil, natural gas and NGL revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA and cash available for distribution on common units may not be comparable to other similarly titled measures of other companies. 78

Table of Contents The tables below present a reconciliation of Adjusted EBITDA to net (loss) income and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated.

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	Partnership											​	​	Predecessor
​	​	Year Ended December 31,								​	Period from February 8, 2017 to December 31,		​	​	Period from January 1, 2017 to February 7,		​	Year Ended December 31,
​	​	2020		​	2019		​	2018		​	2017		​	​	2017		​	2016
Reconciliation of net loss to Adjusted EBITDA:	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Net (loss) income	​	$	(256,090,770)	​	$	(158,207,945)	​	$	(52,282,223)	​	$	1,715,740	​	​	$	(496,856)	​	$	(6,212,619)
Depreciation and depletion expense	​	​	47,988,796	​	​	52,118,367	​	​	25,213,043	​		15,546,341	​	​		113,639	​		1,604,208
Interest expense	​	​	6,430,061	​	​	5,813,702	​	​	4,091,900	​		791,437	​	​		39,307	​		424,841
Cash distribution from affiliate	​	​	812,810	​	​	—	​	​	—	​	​	—	​	​	​	—	​	​	—
(Benefit from) provision for income taxes	​	​	(885,193)	​	​	899,425	​	​	24,681	​	​	—	​	​	​	—	​	​	—
State income taxes	​	​	—	​	​	—	​	​	—	​	​	—	​	​	​	—	​	​	19,848
EBITDA	​	​	(201,744,296)	​	​	(99,376,451)	​	​	(22,952,599)	​		18,053,518	​	​		(343,910)	​		(4,163,722)
Impairment of oil and natural gas properties	​	​	251,558,557	​	​	169,150,255	​	​	67,311,501	​		—	​	​		—	​		4,992,897
Transaction costs	​	​	—	​	​	—	​	​	1,188,967	​	​	—	​	​	​	—	​	​	—
Unit-based compensation	​	​	9,261,756	​	​	7,502,678	​	​	3,170,299	​		798,413	​	​	​	50,422	​		605,059
Loss on extinguishment of debt	​	​	476,350	​	​	—	​	​	—	​	​	—	​	​	​	—	​	​	—
Loss (gain) on commodity derivative instruments, net of settlements	​	​	7,085,364	​	​	3,423,445	​	​	(4,546,775)	​	​	318,829	​	​	​	—	​	​	—
Cash distribution from affiliate	​	​	—	​	​	94,150	​	​	—	​	​	—	​	​	​	—	​	​	—
Equity income in affiliate	​	​	(763,988)	​	​	(80,481)	​	​	—	​	​	—	​	​	​	—	​	​	—
Consolidated Adjusted EBITDA	​	​	65,873,743	​	​	80,713,596	​	​	44,171,393	​	​	19,170,760	​	​	​	(293,488)	​	​	1,434,234
Adjusted EBITDA attributable to noncontrolling interest	​	​	(23,914,812)	​	​	(42,228,556)	​	​	(8,234,737)	​	​	—	​	​	​	—	​	​	—
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP	​	​	41,958,931	​	​	38,485,040	​	​	35,936,656	​	​	19,170,760	​	​	​	(293,488)	​	​	1,434,234
Adjustments to reconcile Adjusted EBITDA to cash available for distribution	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Cash interest expense	​	​	3,399,655	​	​	2,430,170	​	​	2,292,023	​	​	455,228	​	​	​	34,505	​	​	373,513
Cash distributions on Series A preferred units	​	​	3,047,466	​	​	3,635,459	​	​	1,291,843	​	​	—	​	​	​	—	​	​	—
Cash income tax expense	​	​	—	​	​	801,669	​	​	—	​	​	—	​	​	​	—	​	​	—
Distributions on Class B units	​	​	91,869	​	​	94,429	​	​	30,967	​	​	—	​	​	​	—	​	​	—
Cash reserves	​	​	—	​	​	(801,669)	​	​	—	​	​	—	​	​	​	—	​	​	—
Cash available for distribution on common units	​	$	35,419,941	​	$	32,324,982	​	$	32,321,823	​	$	18,715,532	​	​	$	(327,993)	​	$	1,060,721

​ 79

Table of Contents

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	Partnership											​	​	Predecessor
​	​	Year Ended December 31,								​	Period from February 8, 2017 to December 31,		​	​	Period from January 1, 2017 to February 7,		​	Year Ended December 31,
​	​	2020		​	2019		​	2018		​	2017		​	​	2017		​	2016
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Net cash provided by operating activities	​	$	62,245,341	​	$	80,702,448	​	$	33,202,980	​	$	18,573,481	​	​	$	186,719	​	$	1,086,603
Interest expense	​		6,430,061	​		5,813,702	​		4,091,900	​		791,437	​	​		39,307	​		424,841
(Benefit from) provision for income taxes	​	​	(885,193)	​	​	899,425	​	​	24,681	​	​	—	​	​	​	—	​	​	—
State income taxes	​	​	—	​	​	—	​	​	—	​	​	—	​	​	​	—	​	​	19,848
Impairment of oil and natural gas properties	​		(251,558,557)	​		(169,150,255)	​		(67,311,501)	​		—	​	​		—	​		(4,992,897)
Amortization of right-of-use assets	​	​	(276,180)	​		(154,525)	​	​	—	​	​	—	​	​	​	—	​	​	—
Amortization of loan origination costs	​		(1,108,685)	​		(1,050,278)	​		(466,002)	​		(57,292)	​	​		(4,241)	​		(46,969)
Loss on extinguishment of debt	​	​	(476,350)	​		—	​		—	​	​	—	​	​	​	—	​	​	—
Amortization of tenant improvement allowance	​	​	—	​	​	—	​	​	—	​	​	—	​	​	​	2,864	​	​	34,369
Equity income in affiliate	​		763,988	​		80,481	​		—	​		—	​	​		—	​		—
Forfeiture of restricted units	​	​	127,934	​	​	—	​	​	​	​	​	​	​	​	​	​	​	​	​
Unit-based compensation	​		(9,261,756)	​		(7,502,678)	​		(3,170,299)	​		(798,413)	​	​		(50,422)	​		(605,059)
(Loss) gain on commodity derivative instruments, net of settlements	​		(7,085,364)	​		(3,423,445)	​		4,546,775	​		(318,829)	​	​		—	​		—
Changes in operating assets and liabilities:	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Oil, natural gas and NGL receivables	​		(1,618,006)	​		(4,410,140)	​		7,041,371	​		1,689,609	​	​		(14,551)	​		66,455
Accounts receivable and other current assets	​		897,088	​		26,317	​		(186,122)	​		236,673	​	​		(333,056)	​		(1,027,172)
Accounts payable	​		319,001	​		125,387	​		(985,936)	​		(316,486)	​	​		(247,972)	​		952,800
Other current liabilities	​		(533,582)	​		(1,762,633)	​		259,554	​		(1,746,662)	​	​		77,442	​		(76,541)
Operating lease liabilities	​	​	275,964	​		429,743	​	​	—	​	​	—	​	​	​	—	​	​	—
EBITDA	​	​	(201,744,296)	​	​	(99,376,451)	​	​	(22,952,599)	​	​	18,053,518	​	​	​	(343,910)	​	​	(4,163,722)
Add:	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Impairment of oil and natural gas properties	​		251,558,557	​		169,150,255	​		67,311,501	​		—	​	​		—	​		4,992,897
Transaction costs	​	​	—	​	​	—	​	​	1,188,967	​	​	—	​	​	​	—	​	​	—
Unit-based compensation	​		9,261,756	​		7,502,678	​		3,170,299	​		798,413	​	​		50,422	​		605,059
Loss on extinguishment of debt	​	​	476,350	​	​	—	​	​	—	​	​	—	​	​	​	—	​	​	—
Loss (gain) on commodity derivative instruments, net of settlements	​		7,085,364	​		3,423,445	​		(4,546,775)	​		318,829	​	​		—	​		—
Equity income in affiliate	​	​	(763,988)	​	​	(80,481)	​	​	—	​	​	—	​	​	​	—	​	​	—
Cash distribution from affiliate	​	​	—	​	​	94,150	​	​	—	​	​	—	​	​	​	—	​	​	—
Consolidated Adjusted EBITDA	​	​	65,873,743	​	​	80,713,596	​	​	44,171,393	​	​	19,170,760	​	​	​	(293,488)	​	​	1,434,234
Adjusted EBITDA attributable to noncontrolling interest	​	​	(23,914,812)	​	​	(42,228,556)	​	​	(8,234,737)	​	​	—	​	​	​	—	​	​	—
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP	​	$	41,958,931	​	$	38,485,040	​	$	35,936,656	​	$	19,170,760	​	​	$	(293,488)	​	$	1,434,234

​

​

​ 80

Table of Contents ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources and should be read together with “Item 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data” and related notes included elsewhere in this Annual Report.

This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Such views, beliefs, assumptions and estimates may, and often do, vary from actual results and the differences can be material. Actual results could differ materially from such forward-looking statements as a result of various factors, including those that may not be in the control of our management. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For further information on items that could impact our future operating performance or financial condition, please read the sections entitled “Risk Factors” and “Forward-Looking Statements” elsewhere in this Annual Report.

Overview

We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, we have elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of December 31, 2020, we owned mineral and royalty interests in approximately 9.1 million gross acres and overriding royalty interests in approximately 4.6 million gross acres, with approximately 60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. As of December 31, 2020, over 98% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 97,000 gross wells, including over 41,000 wells in the Permian Basin.

Recent Developments

2020 Equity Offering

In January 2020, we completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 million (the “2020 Equity Offering”). We used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under our secured revolving credit facility. In connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units pursuant to the exercise of the underwriters’ option to purchase additional common units. We did not receive any proceeds from the sale of the common units by the selling unitholders.

2020 Partial Redemption of Preferred Units

On February 12, 2020, we completed the redemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million.

Acquisitions

On April 17, 2020, we completed the Springbok Acquisition. The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, (ii) the issuance of 2,224,358 common units and (iii) the 81

Table of Contents issuance of 2,497,134 OpCo common units and an equal number of Class B units. At the time of the Springbok Acquisition, the acreage acquired had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other leading basins.

Joint Venture

In connection with the joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, we paid capital contributions of $2.2 million during the year ended December 31, 2020.

Interest Rate Swaps

On January 27, 2021, we entered into an interest rate swap with Citibank, N.A. (“Citi”), which fixed the interest rate on $150.0 million of notional, or approximately 87% of our outstanding balance on our secured revolving credit facility, at approximately 3.9% for a period ending on January 29, 2024.

Fourth Quarter Distributions

On February 3, 2021, we paid a quarterly cash distribution on the Series A preferred units of $1.0 million for the quarter ended December 31, 2020.

On February 4, 2021, we paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of approximately $20,780 for the quarter ended December 31, 2020.

On January 22, 2021, the Board of Directors declared a quarterly cash distribution of $0.19 per common unit for the quarter ended December 31, 2020. The distribution was paid on February 8, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on February 1, 2021.

Business Environment

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption during 2020. On March 11, 2020, the WHO declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, our oil, natural gas, and NGL operators and other parties with whom we have business relations, including a significant reduction in the global demand for oil and natural gas. This significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance has led to a significantly weaker outlook for oil and gas producers and continues to have a disruptive impact on the oil and natural gas industry. Globally, these conditions led to significant economic contraction during 2020.

Our first priority in our response to this crisis has been and will continue to be the health and safety of our employees, the employees of our business counterparties and the community in which we operate. To address these concerns, we have modified certain business practices (including those related to employee travel, employee work locations, and physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the CDC, the WHO and other governmental and regulatory authorities. In mid-March, we restricted access to our offices to only essential employees, and directed the remainder of our employees to work from home to the extent possible. Beginning in mid-May, we opened our offices to employees on a voluntary basis, with employees having the option to work from home. These restrictions have had minimal impact on our operations to date and have allowed us to maintain the engagement and connectivity of our personnel, as well as minimize the number of employees in the office.

There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. 82

Table of Contents While shelter-in-place restrictions subsided in the second half of 2020, the possibility of future restrictions remains. One of the largest impacts of the pandemic has been a significant reduction in global demand for oil and, to a lesser extent, natural gas. This significant decline in demand has been met with a sharp decline in oil prices which has been exacerbated by the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries. Although OPEC agreed in April 2020 to cut oil production and has extended such production cuts through March 2021, crude oil prices remained depressed through December 31, 2020 as a result of an increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other related industries. These industry conditions, coupled with those resulting from the COVID-19 pandemic, have led to significant global economic contraction generally and in our industry in particular.

Oil and natural gas prices have historically been volatile; however, the volatility in the prices for these commodities has substantially increased as a result of COVID-19, the OPEC announcements mentioned above and ongoing storage capacity concerns. Oil prices declined sharply in April 2020 and remained low continuing through year end 2020. Although strip pricing for natural gas has increased meaningfully, the impact of these recent developments on our business and the oil and gas industry is unpredictable. We derived approximately 34% of our revenues and 59% of our production on a Boe/d basis (6:1) from natural gas for the fourth quarter of 2020, which we believe presented some downside protection against depressed oil prices.

In April 2020, we received notices from two operators regarding well shut-ins and curtailments of production on properties in which we own an interest. The properties were primarily located in the Eagle Ford Shale, and the production attributable to such properties on a Boe/d basis (6:1) represented approximately one percent of our total production for the first quarter of 2020. We received subsequent notice that the curtailment on all Eagle Ford Shale production had ceased and production resumed, effective June 1, 2020. We also received notifications of well shut-ins and curtailment in the second quarter of 2020 from additional operators and the production attributable to such properties on a Boe/d basis (6:1) accounted for less than one percent of our total production for the second quarter of 2020. We did not receive any additional notifications of well shut-ins or curtailments in the second half of 2020. While we currently do not expect we will receive additional notices, we cannot predict whether additional shut-ins and curtailments of production from our operators will occur if depressed oil and natural gas prices, reductions in global demand and storage capacity issues continue or worsen. We expect that as the supply and demand imbalance resulting from the COVID-19 outbreak and the OPEC announcements mentioned above continues, and as oil storage facilities reach capacity and/or purchasers of crude products cancel previous orders, more of our operators may adjust or reduce their drilling activities, which could have an adverse effect on our business, cash flows, liquidity, financial condition and results of operations in the first quarter of 2021.

The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on our business, cash flows, liquidity, financial condition and results of operations will depend on future developments, including, among others, the ultimate severity of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other third parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in this report.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from the COVID-19 outbreak and various OPEC announcements have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported by the EIA.

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	Year EndedDecember 31, 2020					​	Year EndedDecember 31, 2019					​	Year EndedDecember 31, 2018
​	​	High			Low		​	High			Low		​	High			Low
Oil ($/Bbl)	​	$	63.27	​	$	(36.98)	​	$	66.24	​	$	46.31	​	$	77.41	​	$	44.48
Natural gas ($/MMBtu)	​	$	3.14	​	$	1.33	​	$	4.25	​	$	1.75	​	$	6.24	​	$	2.49

​ 83

Table of Contents On February 19, 2021, the WTI posted price for crude oil was $59.12 per Bbl and the Henry Hub spot market price of natural gas was $4.96 per MMBtu.

The following table, as reported by the EIA, sets forth the average prices for oil and natural gas.

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019			2018
Oil ($/Bbl)	​	$	39.16	​	$	56.98	​	$	65.23
Natural gas ($/MMBtu)	​	$	2.03	​	$	2.56	​	$	3.15

Rig Count

Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The Baker Hughes United States Rotary Rig count was 332 active land rigs at December 31, 2020, a 57% decrease from 781 active land rigs at December 31, 2019. The 781 active rig count at December 31, 2019 decreased 26% from 1,056 active land rigs at December 31, 2018.

According to the Baker Hughes United States Rotary Rig count, rig activity in the 28 states in which we own mineral and royalty interests decreased 57% from 773 active land rigs at December 31, 2019 to 330 active land rigs at December 31, 2020. The 773 active land rig count at December 31, 2019 decreased 26% from 1,049 active land rigs at December 31, 2018. The decrease in rig count in 2020 is primarily related to the COVID-19 outbreak and international supply and demand imbalances. See Business Environment — COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas for further discussion.

The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated.

​	​	​	​	​	​	​
​	​	December 31,
Basin or Producing Region	​	2020	​	2019	​	2018
Permian Basin	​	17	​	24	​	28
Mid‑Continent	​	7	​	16	​	22
Haynesville	​	9	​	12	​	4
Appalachia	​	1	​	1	​	2
Bakken	​	3	​	11	​	—
Eagle Ford	​	1	​	9	​	4
Rockies	​	1	​	7	​	14
Other	​	—	​	1	​	3
Total	​	39	​	81	​	77

​

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. 84

Table of Contents The following table presents the breakdown of our operating income for the following periods:

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020			2019			2018	​
Royalty income	​	​	​	​	​	​	​	​	​
Oil sales	​	56	%	​	55	%	​	53	%
Natural gas sales	​	34	%	​	34	%	​	33	%
NGL sales	​	9	%	​	8	%	​	12	%
Lease bonus and other income	​	1	%	​	3	%	​	2	%
​	​	100	%	​	100	%	​	100	%

In order to reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative agreements with Frost Bank beginning January 1, 2018. Our commodity derivative agreements with Frost Bank extend through December 2022 and establish, in advance, a price for the sale of a portion of the oil, natural gas and NGLs produced from our mineral and royalty interests. For further discussion on our commodity derivative agreements, see “Note 4—Derivatives.”

Reserves and Pricing

The tables below identify our proved reserves at December 31, 2020, 2019 and 2018, in each case based on the reserve report prepared by Ryder Scott. The prices used to estimate proved reserves for the respective periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

​	​	​	​	​	​	​
​	​	December 31,
Estimated Net Proved Reserves		2020	​	2019	​	2018
Oil (MBbls)		12,294	​	12,318	​	10,795
Natural gas (MMcf)		144,233	​	148,743	​	127,261
Natural gas liquids (MBbls)		6,085	​	6,455	​	5,646
Total (MBoe)(6:1)		42,418	​	43,563	​	37,651

​

​	​	​	​	​	​	​	​	​	​
​	​	December 31,
Unweighted Arithmetic Average First ‑ Day ‑ of ‑ the ‑ Month Prices		2020		​	2019		​	2018
Oil (Bbls)	​	$	39.57	​	$	55.69	​	$	65.56
Natural gas (Mcf)	​	$	1.99	​	$	2.58	​	$	3.10

​

Factors Affecting the Comparability of Our Results

Our historical financial condition and results of operations may not be comparable, either from period to period or going forward, to our future financial condition and results of operations, for the reasons described below:

Ongoing Acquisition Opportunities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the years ended December 31, 2020, 2019 and 2018 include the Springbok Acquisition, the Phillips Acquisition, the Buckhorn Acquisition, the Haymaker Acquisition and the Dropdown.

Further, the affiliates of our Sponsors and Contributing Parties have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such parties offer 85

Table of Contents them to us. We may decide to fund any acquisition, including any potential dropdowns, with cash, common units, other equity securities, proceeds from borrowings under our secured revolving credit facility or the issuance of debt securities, or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.

We typically do not announce a transaction until after we have executed a definitive agreement. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.

Impairment of Oil and Natural Gas Properties

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.

After evaluating certain external factors in the first quarter of 2020, including the significant decline in oil and natural gas prices related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries and other supply factors, as well as longer-term commodity price outlooks, we determined that significant drilling uncertainty existed regarding our PUD reserves that were included in our total estimated proved reserves as of December 31, 2019, as well as our unevaluated oil and natural gas properties. Specifically, with respect to our PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), we determined that we did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties for the three months ended March 31, 2020. We similarly recorded an impairment on the value of our unevaluated oil and natural gas properties for the three months ended March 31, 2020, which primarily were acquired in various acquisitions since our IPO. There were no additional impairments to unevaluated properties in the remainder of 2020.

As a result of our full cost ceiling analysis, we recorded an impairment on our oil and natural gas properties of $251.6 million during the year ended December 31, 2020. The impairment can primarily be attributed to the decline in the 12-month average price of oil and natural gas as a result of the continued impact of the external factors mentioned above. As of December 31, 2020, the 12-month average prices of oil and natural gas were $39.57 per Bbl of oil and $1.99 per Mcf of natural gas. These prices represent a 28.9% and 22.9% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2019, which were $55.69 per Bbl of oil and $2.58 per Mcf of natural gas.

We recorded an impairment on our oil and natural gas properties of $169.2 million during the year ended December 31, 2019. The impairment can primarily be attributed to our quarterly full cost ceiling analysis and a decline in the 12-month average price of oil and natural gas. As of December 31, 2019, the 12-month average prices of oil and natural gas were $55.69 per Bbl of oil and $2.58 per Mcf of natural gas. These prices represent a 15.1% and 16.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2018, which were $65.56 per 86

Table of Contents Bbl of oil and $3.10 per Mcf of natural gas. We also recorded an impairment expense on our oil and natural gas properties of $67.3 million during the year ended December 31, 2018. Of this amount, an impairment expense of $54.8 million was recorded as a result of our quarterly full-cost ceiling analysis for the three months ended March 31, 2018 and an impairment expense of $12.6 million was recorded for the three months ended December 31, 2018 as a result of the Dropdown purchase price exceeding the value of the proved developed reserves added to the full-cost ceiling.

Because we do not intend to book PUD reserves going forward, additional impairment charges could be recorded in connection with future acquisitions. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.

Principal Components of Our Cost Structure

As an owner of mineral and royalty interests, we are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life.

Production and Ad Valorem Taxes

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are jurisdictional taxes levied on the value of oil, natural gas and NGLs minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities.

Depreciation and Depletion

We follow the full cost method of accounting for costs related to our oil, natural gas and NGL mineral and royalty properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10%, including the effect of income taxes. The full cost ceiling is evaluated at the end of each fiscal quarter and additionally when events indicate possible impairment. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of our unevaluated costs into the amortization base is expected to be completed within five years.

Marketing and Other Deductions

Marketing and other deductions include product marketing expense, which is a post-production expense. Generally, the terms of the lease governing the development of our properties permit the operator to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues.

General and Administrative Expense

General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits, office expenses and fees for professional services. We have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective services agreements, affiliates of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. 87

Table of Contents

Interest Expense

We finance a portion of our capital requirements and acquisitions with borrowings under our secured revolving credit facility. As a result, we incur interest expense, which is included in our accompanying consolidated statements of operations. Please read “Liquidity and Capital Resources—Indebtedness” for further discussion of our secured revolving credit facility.

Income Tax Expense

On September 24, 2018, we elected to change our federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election (the “Tax Election”). As a result of the Tax Election, we are subject to federal income tax on our taxable income at the United States corporate tax rate, which is currently 21.0%.

Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A significant portion of our mineral and royalty interests are located in Texas basins and producing regions.

Results of Operations

The table below summarizes our revenue and expenses and production data for the periods indicated.

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Operating Results:	​	​	​	​	​	​	​	​	​
Revenue	​	​	​	​	​	​	​	​	​
Oil, natural gas and NGL revenues	​	$	92,586,685	​	$	107,480,446	​	$	65,713,112
Lease bonus and other income	​	​	345,771	​	​	2,477,145	​	​	1,213,550
(Loss) gain on commodity derivative instruments, net	​	​	(2,450,541)	​	​	(1,732,321)	​	​	3,331,548
Total revenues	​	​	90,481,915	​	​	108,225,270	​	​	70,258,210
Costs and expenses	​	​	​	​	​	​	​	​	​
Production and ad valorem taxes	​		6,389,231	​		7,719,949	​		4,399,667
Depreciation and depletion expense	​		47,988,796	​		52,118,367	​		25,213,043
Impairment of oil and natural gas properties	​		251,558,557	​		169,150,255	​		67,311,501
Marketing and other deductions	​		9,376,375	​		8,145,397	​		4,652,313
General and administrative expenses	​		25,902,496	​		22,666,601	​		16,847,328
Total costs and expenses	​		341,215,455	​		259,800,569	​		118,423,852
Operating loss	​		(250,733,540)	​		(151,575,299)	​		(48,165,642)
Other income (expense)	​	​	​	​	​	​	​	​	​
Equity income in affiliate	​	​	763,988	​	​	80,481	​	​	—
Interest expense	​		(6,430,061)	​		(5,813,702)	​		(4,091,900)
Loss on extinguishment of debt	​	​	(476,350)	​		—	​		—
Other expense	​		(100,000)	​		—	​	​	—
Net loss before income taxes	​	​	(256,975,963)	​	​	(157,308,520)	​	​	(52,257,542)
(Benefit from) provision for income taxes	​	​	(885,193)	​	​	899,425	​	​	24,681
Net loss	​	​	(256,090,770)	​	​	(158,207,945)	​	​	(52,282,223)
Distribution and accretion on Series A preferred units	​	​	(7,810,588)	​	​	(13,878,336)	​	​	(6,310,040)
Net loss attributable to noncontrolling interests	​	​	96,642,334	​	​	89,148,428	​	​	1,855,681
Distribution on Class B units	​	​	(91,869)	​	​	(94,429)	​	​	(30,967)
Net loss attributable to common units	​	$	(167,350,893)	​	$	(83,032,282)	​	$	(56,767,549)
Production Data:	​	​	​	​	​	​	​	​	​
Oil (Bbls)	​		1,409,163	​		1,113,150	​		591,072
Natural gas (Mcf)	​		17,891,384	​		17,045,519	​		7,873,694
Natural gas liquids (Bbls)	​		681,575	​		561,797	​		310,361
Combined volumes (Boe) (6:1)	​		5,072,635	​		4,515,867	​		2,213,715

​ 88

Table of Contents Comparison of the Year Ended December 31, 2020 to the Year Ended December 31, 2019 and the Year Ended December 31, 2019 to the Year Ended December 31, 2018

Oil, Natural Gas and NGL Revenues

For the year ended December 31, 2020, our oil, natural gas and NGL revenues were $92.6 million, a decrease of $14.9 million from $107.5 million for the year ended December 31, 2019. The significant decrease in oil, natural gas and NGL revenues was directly related to the decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2020 as discussed below. This decrease was partially offset by an increase in production associated with various acquisitions throughout the 2019 and 2020 periods.

Our revenues for the year ended December 31, 2019 increased by $41.8 million, from $65.7 million for the year ended December 31, 2018. The increase in revenues was primarily attributable to the revenues associated with the Haymaker Acquisition and the Phillips Acquisition, which represented approximately $20.2 million and $16.3 million, respectively, of the overall increase in oil, natural gas and NGL revenues, and, to a lesser extent, the revenues associated with the Dropdown, which contributed $11.1 million to the overall increase. Partially offsetting the increase in oil, natural gas and NGL revenues, was a decrease in the average prices we received for oil and NGL production.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 5,072,635 Boe or 13,860 Boe/d, for the year ended December 31, 2020, an increase of 556,768 Boe or 1,529 Boe/d, from 4,515,867 Boe or 12,331 Boe/d, for the year ended December 31, 2019. The increase in production for the year ended December 31, 2020 was primarily attributable to production associated with the Springbok Acquisition, which accounted for 568,424 Boe.

Our production volumes for the year ended December 31, 2019 increased by 2,302,152 Boe or 2,333 Boe/d, from 2,213,715 Boe or 9,998 Boe/d, for the year ended December 31, 2018. The increase in production was primarily attributable to the Haymaker Acquisition, which represented 1,341,075 Boe, and to a lesser extent, production associated with the Phillips Acquisition and the Dropdown, which together accounted for 968,102 Boe.

Our operators received an average of $36.98 per Bbl of oil, $1.79 per Mcf of natural gas and $12.39 per Bbl of NGL for the volumes sold during the year ended December 31, 2020 and $54.66 per Bbl of oil, $2.21 per Mcf of natural gas and $15.96 per Bbl of NGL for the volumes sold during the year ended December 31, 2019. The year ended December 31, 2020 decreased 32.3% or $17.68 per Bbl of oil and 19.0% or $0.42 per Mcf of natural gas compared to the year ended December 31, 2019. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 31.3% or $17.82 per Bbl of oil and 20.7% or $0.53 per Mcf of natural gas for the comparable periods.

Average prices received by our operators during the year ended December 31, 2019 decreased 9.2% or $5.51 per Bbl of oil and 22.2% or $0.63 per Mcf of natural gas compared to the year ended December 31, 2018, which our operators received an average of $60.17 per Bbl of oil, $2.84 per Mcf of natural gas and $25.14 per Bbl of NGL. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 12.6% or $8.25 per Bbl of oil and 18.7% or $0.59 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income was $0.3 million for the year ended December 31, 2020, a decrease of $2.2 million from $2.5 million for the year ended December 31, 2019. The decrease in lease bonus and other income is primarily due to the current volatility and uncertainty in the oil and gas market, which has discouraged operators from drilling new wells.

Our lease bonus and other income for the year ended December 31, 2019 increased by $1.3 million, from $1.2 million for the year ended December 31, 2018.

​

(Loss) Gain on Commodity Derivative Instruments

Loss on commodity derivative instruments for the year ended December 31, 2020 included $7.1 million of mark-to-market losses and $4.6 million of gains on the settlement of commodity derivative instruments compared to $3.4 million 89

Table of Contents of mark-to-market losses and $1.7 million of gains on the settlement of commodity derivative instruments for the year ended December 31, 2019.

Gain on commodity derivative instruments for the year ended December 31, 2018 included $4.5 million of mark-to-market gains and $1.2 million of losses on the settlement of commodity derivative instruments.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the year ended December 31, 2020 were $6.4 million, a decrease of $1.3 million from $7.7 million for the year ended December 31, 2019. The decrease in production and ad valorem taxes was primarily related to the significant decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2020.

For the year ended December 31, 2019, production and ad valorem taxes increased by $3.3 million from $4.4 million for the year ended December 31, 2018. The increase was primarily attributable to the Haymaker Acquisition, which accounted for $1.6 million of the increase in production and ad valorem taxes and, to the lesser extent, the Phillips Acquisition and the Dropdown, which contributed $0.8 million and $0.6 million, respectively, to the increase.

Depreciation and Depletion Expense

Depreciation and depletion expense for the year ended December 31, 2020 was $48.0 million, a decrease of $4.1 million from $52.1 million for the year ended December 31, 2019. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the years ended December 31, 2020 and 2019, respectively, which significantly reduced our net capitalized oil and natural gas properties. The decrease in the depreciation and depletion expense was partially offset by the Springbok Acquisition, which added approximately $115.4 million of depletable costs to the full-cost pool.

For the year ended December 31, 2019, depreciation and depletion expense increased by $26.9 million from $25.2 million for the year ended December 31, 2018. The increase in the depreciation and depletion expense was primarily attributable to the multiple acquisitions throughout the 2018 and 2019 period, which together added approximately $470.8 million of depletable costs to the full-cost pool.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a unit-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $9.39 for the year ended December 31, 2020, a decrease of $2.00 per barrel from the $11.39 average depletion rate per barrel for the year ended December 31, 2019. The decrease in depletion rate was due to the impairment that was recorded during the years ended December 31, 2020 and 2019, respectively, which significantly reduced our net capitalized oil and natural gas properties.

For the year ended December 31, 2019, our average depletion rate per barrel remained relatively flat compared to $11.33 average depletion rate per barrel for the year ended December 31, 2018. 90

Table of Contents

Impairment of Oil, Natural Gas and NGL Expense

We recorded an impairment expense on our oil and natural gas properties of $251.6 million, $169.2 million and $67.3 million during the years ended December 31, 2020, 2019 and 2018, respectively. The impairment recorded during the year ended December 31, 2020 included an impairment due to the reduction in our PUD reserves, impairment of our unevaluated oil and natural gas properties in the first quarter of 2020 and impairments on our oil and natural gas properties as the result of the continued decline in the 12-month average price of oil and natural gas, in each case as further described under “—Factors Affecting the Comparability of Our Results to Our Historical Results—Impairment of Oil and Natural Gas Properties.”

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the year ended December 31, 2020 were $9.4 million, an increase of $1.3 million from $8.1 million for the year ended December 31, 2019. The increase in marketing and other deductions was primarily attributable to the Springbok Acquisition.

Marketing and other deductions for the year ended December 31, 2019 increased by $3.4 million from $4.7 million for the year ended December 31, 2018. The increase in marketing and other deductions was primarily attributable to the Haymaker Acquisition and the Phillips Acquisition, which represents $1.7 million and $1.1 million respectively, of the overall increase, and to a lesser extent, the Dropdown, which contributed $0.6 million to the increase.

General and Administrative Expense

General and administrative expenses for the year ended December 31, 2020 were $25.9 million, an increase of $3.2 million from $22.7 million for the year ended December 31, 2019. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to a $2.0 million increase in unit-based compensation expense and cash general and administrative expenses resulting from increases in salaries and wages and our costs associated with company growth.

General and administrative expenses for the year ended December 31, 2019 increased by $5.9 million from $16.8 million for the year ended December 31, 2018. The increase in general and administrative expenses was primarily attributable to the $4.3 million increase in unit-based compensation expense. The remainder of the increase was primarily attributable to cash general and administrative expenses resulting from the Haymaker Acquisition, the Dropdown and the Phillips Acquisition.

Interest Expense

Interest expense for the year ended December 31, 2020 was $6.4 million as compared to interest expense of $5.8 million for the year ended December 31, 2019. The increase in interest expense was primarily due to debt incurred to fund the partial redemption of the Series A preferred units and the Springbok Acquisition, which was partially offset by the repayment of $91.2 million in debt during the year ended December 31, 2020 and the decline in the weighted average interest rate from 4.58% during the year ended December 31, 2019 to 3.31% during the year ended December 31, 2020.

Interest expense for the year ended December 31, 2019 increased by $1.7 million as compared to interest expense of $4.1 million for the year ended December 31, 2018. This increase was due to debt incurred to fund acquisitions in 2018 and 2019, including the Haymaker Acquisition, acquisitions by the Joint Venture and the acquisition of various mineral and royalty interests in Oklahoma.

(Benefit from) Provision for Income Taxes

For the year ended December 31, 2020, we recognized an income tax benefit of $0.9 million, resulting in an effective tax rate of 0.34%, compared to an income tax expense of $0.9 million for the year ended December 31, 2019, resulting in an effective tax rate of 0.57%. The overall change in our effective tax rate for the year ended December 31, 91

Table of Contents 2020 is due to a change in estimate as a result of filing our 2019 income tax return, as well as the impact of the U.S. Coronavirus Aid, Relief, and Economic Security Act carryback provisions.

Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance. As of December 31, 2020 and 2019, we recorded a full valuation allowance on our deferred tax assets. As a result, we did not recognize a benefit from our net operating losses for the respective periods. See Note 13—Income Taxes for further discussion.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations and equity and debt financings and our primary uses of cash are distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. On December 8, 2020, we entered into Amendment No. 2 (the “Second Credit Agreement Amendment”) to the 2018 Amended Credit Agreement (as defined below), increasing commitments under the secured revolving credit facility from $225.0 million to $265.0 million, with an elected commitment amount feature permitting aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million (subject to the limitations of our borrowing base, which is currently $265.0 million, and the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders), to be used for general partnership purposes, including working capital and acquisitions, among other things. As of February 19, 2021, we had an outstanding balance of $171.6 million under our secured revolving credit facility.

Cash Distribution Policy

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in our partnership agreement and in the limited liability company agreement of the Operating Company, and in “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Definition of Available Cash.” We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

In light of the unprecedented global economic impact resulting from the COVID-19 pandemic, the related impact to the United States oil and natural gas markets and the potential for further curtailments of production, the Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2020 for the repayment of $3.9 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2020. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future.

We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy. 92

Table of Contents It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we issued 2,224,358 common units and 2,497,134 OpCo common units and an equal number of Class B units as partial consideration in connection with the Springbok Acquisition. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

On February 3, 2021, we paid a quarterly cash distribution on the Series A preferred units of $1.0 million for the quarter ended December 31, 2020.

On February 4, 2021, we paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of approximately $20,780 for the quarter ended December 31, 2020.

On January 22, 2021, the Board of Directors declared a quarterly cash distribution of $0.19 per common unit for the quarter ended December 31, 2020. The distribution was paid on February 8, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on February 1, 2021.

Cash Flows

The following table presents our cash flows for the periods indicated.

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020			2019		​	2018
Cash Flow Data:	​	​	​	​	​	​	​	​	​
Net cash provided by operating activities	​	$	62,245,341	​	$	80,702,448	​	$	33,202,980
Net cash used in investing activities	​		(90,827,734)	​		(15,590,458)	​		(200,928,162)
Net cash provided by (used in) financing activities	​		24,183,120	​		(66,681,727)	​		177,873,674
Net (decrease) increase in cash and cash equivalents	​	$	(4,399,273)	​	$	(1,569,737)	​	$	10,148,492

Operating Activities

Operating cash flow is impacted by many variables, the most significant of which are the changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2020 were $62.2 million, a decrease of $18.5 million compared to $80.7 million for the year ended December 31, 2019. The decrease in cash flows provided by operating activities was primarily attributable to the decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2020.

Cash flows provided by operating activities for the year ended December 31, 2019 increased by $47.5 million compared to $33.2 million for the year ended December 31, 2018. The increase in cash flows provided by operating activities was primarily attributable to the Haymaker Acquisition and Dropdown in the third and fourth quarters of 2018, respectively, and to the Phillips Acquisition and Buckhorn Acquisition in the first and fourth quarters of 2019, respectively.

Investing Activities

Cash flows used in investing activities for the year ended December 31, 2020 increased by $75.2 million compared to the year ended December 31, 2019. For the year ended December 31, 2020, we used $87.6 million primarily to fund the Springbok Acquisition, $2.2 million to fund the capital commitments of the Joint Venture and $1.0 million to fund the remodel of office space. For the year ended December 31, 2019, we used $3.0 million to fund capital commitments paid to the Joint Venture, $1.2 million to fund the Phillips Acquisition, $9.9 million to fund the acquisition of various 93

Table of Contents mineral and royalty interests in Oklahoma, $0.5 million in connection with the Buckhorn Acquisition and $1.0 million to fund the remodel of office space.

Cash flows used in investing activities for the year ended December 31, 2019 decreased by $185.3 million compared to the year ended December 31, 2018. For the year ended December 31, 2018, we used $211.1 million primarily to fund the Haymaker Acquisition and $0.4 million to fund the remodel of office space, partially offset by $10.6 million in proceeds received from the sale of oil and natural gas properties.

Financing Activities

Cash flows provided by financing activities were $24.2 million for the year ended December 31, 2020 compared to $66.7 million in cash flows used in financing activities for the year ended December 31, 2019. Cash flows provided by financing activities for the year ended December 31, 2020 consists of $162.6 million of additional borrowings under our secured revolving credit facility and $73.6 million in proceeds from the 2020 Equity Offering. Cash flows provided by financing activities for the year ended December 31, 2020 were partially offset by $91.2 million used to repay borrowings under our secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units, $54.9 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $4.5 million paid in connection with amending our secured revolving credit facility and $0.4 million paid in connection with the redemption of Class B units. Cash flows used in financing activities for the year ended December 31, 2019 consist of $78.8 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $0.7 million of issuance costs paid on Series A preferred units and $0.3 million paid in connection with the redemption of Class B units, partially offset by $12.8 million of additional borrowings under our secured revolving credit facility and $0.5 million in contributions from our Class B unitholders.

Cash flows provided by financing activities for the year ended December 31, 2018 were $177.9 million. Cash flows provided by financing activities for the year ended December 31, 2018 consists of $124.4 million of additional borrowings under our secured revolving credit facility, $103.4 million in net proceeds from the 2018 preferred offering, $61.8 million in net proceeds from the 2018 equity offering and $1.0 million in contributions from our Class B unitholders, partially offset by $41.0 million of distributions paid to holders of common units, Series A preferred units and Class B units, $67.9 million of repayments on our secured revolving credit facility and $3.4 million paid in loan origination costs. 94

Table of Contents

Capital Expenditures

During the year ended December 31, 2020, we paid approximately $87.6 million primarily in connection with the Springbok Acquisition. During the year ended December 31, 2019, we paid approximately $1.2 million in connection with the Phillips Acquisition, $9.9 million in connection with the acquisition of various mineral and royalty interests in Oklahoma and $0.5 million in connection with the Buckhorn Acquisition. During the year ended December 31, 2018, we paid approximately $211.1 million for the acquisition of oil and gas mineral and royalty properties, primarily in connection with the Haymaker Acquisition.

Indebtedness

On January 11, 2017, we entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018, in connection with the closing of the Haymaker Acquisition, we entered into an amendment (the “First Credit Agreement Amendment”) to the 2017 Credit Agreement (the 2017 Credit Agreement as amended by the First Credit Agreement Amendment, the “2018 Amended Credit Agreement”), with certain of our subsidiaries, as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto. On December 8, 2020, we entered into the Second Credit Agreement Amendment to the 2018 Amended Credit Agreement (the 2018 Amended Credit Agreement as amended by the Second Credit Agreement Amendment, the “Amended Credit Agreement”). Under the Amended Credit Agreement, availability under our secured revolving credit facility will continue to equal the lesser of the aggregate maximum elected commitments of the lenders, which may be increased up to $500.0 million, subject to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders, and the borrowing base. The Second Credit Agreement Amendment amended the 2018 Amended Credit Agreement to extend the maturity date thereunder from February 8, 2022 to June 7, 2024.

The Second Credit Agreement Amendment increased aggregate commitments under the 2018 Amended Credit Agreement from $225.0 million to $265.0 million providing for maximum availability of $265.0 million. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million, subject to the limitations of our borrowing base and satisfaction of certain conditions, including the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders and the borrowing base. In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be redetermined semiannually on May 1 and November 1 of each year, beginning May 1, 2021, based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries.

The Amended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units and OpCo common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The Amended Credit Agreement also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 3.5 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The Amended Credit Agreement also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change of control. As of December 31, 2020, we had outstanding borrowings of $171.6 million under the secured revolving credit facility and $93.4 million of available capacity.

For additional information on our Amended Credit Agreement, please read Note 8―Long-Term Debt to the consolidated financial statements included in Item 8 of this Annual Report. 95

Table of Contents

Off-Balance Sheet Arrangements

As of December 31, 2020, we did not have any off-balance sheet arrangements.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2020:

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	****	​	​	****	Less than		****	​	​	****	​	​	****	More than 5
​	​	Total		​	1 year		​	1 ‑ 3 years		​	3 ‑ 5 years		​	years
Long-term debt	​	$	171,550,142	​	$	—	​	$	—	​	$	171,550,142	​	$	—
Operating leases	​		4,149,712	​		480,025	​		959,416	​		983,356	​		1,726,915
Total	​	$	175,699,854	​		480,025	​	$	959,416	​	$	172,533,498	​	$	1,726,915

​

Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. We currently expect that (i) we will pay no material federal income taxes through 2021 (no more than approximately 5% of estimated pre-tax distributable cash flow), and (ii) substantially all distributions (more than 95%) paid to our common unitholders will not be taxable dividend income through 2023.

Distributions in excess of the amount taxable as dividend income will reduce a common unitholder's tax basis in its common units or produce capital gain to the extent they exceed a common unitholder's tax basis. Any reduced tax basis will increase a common unitholder's capital gain when it sells its common units. The estimates described above are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax "earnings and profits." Our estimates of the tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company allocated to us. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which we operate. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are encouraged to consult with your tax advisor on this matter. Please read “Item 1A. Risk Factors—Tax Risks” elsewhere in this Annual Report.

New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies within the financial statements included elsewhere in this Annual Report.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. Below, we have provided expanded discussion of our more significant accounting estimates.

See the Note 2—Summary of Significant Accounting Policies to our financial statements for a summary of our significant accounting policies.

Method of Accounting for Oil and Natural Gas Properties

We account for oil, natural gas and NGL producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil, natural gas and NGL 96

Table of Contents properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil, natural gas and NGL properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

Depletion of evaluated oil, natural gas and NGL properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. Oil, natural gas and NGL reserve quantities are used as the basis to calculate unit-of-production depreciation. Depreciation is calculated by taking the ratio of asset costs to total proved reserves applied to actual production. The volumes produced and asset costs are known, while proved reserves are based on estimates that are subject to some variability.

Unevaluated Properties

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on a periodic basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: the operators’ intent to drill; remaining lease term; geological and geophysical evaluations; the operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization or potential impairment.

Oil, Natural Gas and NGL Reserve Quantities

Our independent engineers prepare our estimates of oil, natural gas and NGL reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil, natural gas and NGL reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil, natural gas and NGL reserves. Oil, natural gas and NGL reserve engineering is a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil, natural gas and NGLs that are ultimately recovered. Additionally, we do not intend to book PUD reserves going forward.

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGLs, less production and ad valorem taxes and post-production expenses. The pricing of oil, natural gas and NGLs from the properties in which we own a mineral or royalty interest is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no involvement or operational control over the volumes and method of sale of the oil, natural gas and NGLs produced and sold from the property. We have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development and operation of the property. Oil, natural gas and NGL revenues from our mineral and royalty interests are recognized at the point control of the product is transferred to the purchaser. The price and volumes of certain sales are 97

Table of Contents based on estimates that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized and are finalized when the price and volume is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant.

Full Cost Ceiling Impairment

The net capitalized costs of proved oil, natural gas and NGL properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. Estimated future net revenues are calculated as estimated future revenues from oil, natural gas and NGL properties less production taxes, ad valorem taxes and gas marketing expenses. To the extent capitalized costs of evaluated oil, natural gas and NGL properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil, natural gas and NGL reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil, natural gas and NGL prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the reporting period.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect commodity prices to be even more volatile in the future as a result of COVID-19, ongoing international supply and demand imbalances and limited international storage capacity. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparty to the contracts is an unrelated third party.

Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. See Note 4—Derivatives to the consolidated financial statements in Item 8 of this Annual Report for additional information regarding our commodity derivatives.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2020, we had one counterparty, which is also a lender under our credit facility.

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. During the years ended December 31, 2020, 2019 and 2018, our top purchaser accounted for approximately 7.1%, 6.0% and 10%, respectively, of our oil, natural gas and NGL 98

Table of Contents revenues. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2020, we had total borrowings outstanding under our secured revolving credit facility of $171.6 million. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense of approximately $1.7 million annually, assuming that our indebtedness remained constant throughout the year.

On January 27, 2021, we entered into an interest rate swap with Citi, which fixed the interest rate on $150.0 million of notional, or approximately 87% of our outstanding balance on our secured revolving credit facility, at approximately 3.9% for three years.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the period from January 1, 2018 through December 31, 2020.

Item 8. Financial Statements and Supplementary Data

The Partnership’s consolidated financial statements required by this item are included in this Annual Report beginning on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management of our General Partner, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Disclosure controls and procedures are defined as controls designed to ensure that the information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon that evaluation, our General Partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2020.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed under the supervision of our General Partner’s principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting includes those policies and procedures that:

●	Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

99

Table of Contents

●	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our General Partner’s management and directors; and
●	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
---	---

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting can also be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, the risk.

As of December 31, 2020, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework (2013). Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based on this assessment, management has concluded our internal controls over financial reporting were effective as of December 31, 2020.

Attestation Report of the Registered Public Accounting Firm

This Annual Report does not include an attestation report of our independent registered public accounting firm due to rules of the SEC. Our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table shows information for the executive officers, directors and director nominees of our General Partner as of December 31, 2020. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the Board of 100

Table of Contents Directors. Messrs. R. Ravnaas and D. Ravnaas are father and son, respectively, and Messrs. Fortson and Wynne are father-in-law and son-in-law, respectively.

​	​	​	​	​
Name	****	Age	****	Position With Our General Partner
Robert D. Ravnaas	​	63	​	Chief Executive Officer and Chairman of the Board of Directors
R. Davis Ravnaas	​	35	​	President and Chief Financial Officer
Matthew S. Daly	​	48	​	Chief Operating Officer
R. Blayne Rhynsburger	​	34	​	Controller
Brett G. Taylor	​	60	​	Executive Vice Chairman of the Board of Directors
Ben J. Fortson	​	88	​	Director
T. Scott Martin	​	70	​	Director
Mitch S. Wynne	​	62	​	Director
William H. Adams III	​	62	​	Independent Director
Craig Stone	​	57	​	Independent Director
Erik B. Daugbjerg	​	51	​	Independent Director

​

Robert D. Ravnaas. Robert D. Ravnaas was appointed Chief Executive Officer of our General Partner and Chairman of the Board of Directors in November 2015. Mr. R. Ravnaas served as President of Cawley, Gillespie & Associates, Inc., a petroleum engineering firm, from 2011 until February 2017. He also served as President and director of Rivercrest Royalties II, LLC from 2014 until December 2017, and as President and director of our Predecessor from 2013 until our IPO, and he is a partial owner of certain of the Contributing Parties. Prior to joining Cawley, Gillespie & Associates, Inc. in 1983, he worked as a Production Engineer for Amoco Production Company from 1981 to 1983. Mr. R. Ravnaas received a Bachelor of Science degree with special honors in Chemical Engineering from the University of Colorado at Boulder and a Master of Science degree in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in Texas and a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers and the American Association of Petroleum Geologists. Mr. R. Ravnaas was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

R. Davis Ravnaas. R. Davis Ravnaas was appointed President and Chief Financial Officer of our General Partner in November 2015. Mr. D. Ravnaas co-founded our Predecessor in October 2013, served as Vice President and Chief Financial Officer from November 2013 to October 2015 and served as President and Chief Financial Officer of our Predecessor from October 2015 until our IPO. He has also served as Vice President and Chief Financial Officer of Rivercrest Royalties Holdings II, LLC and/or its predecessor, Rivercrest Royalties II, LLC, since August 2014, and he is a partial owner of certain of the Contributing Parties. From 2010 to 2012, Mr. D. Ravnaas was responsible for sourcing, evaluating and monitoring investments in energy and industrials companies as an associate investment professional with Crestview Partners, a New York based private equity fund with $6.0 billion under management. Mr. D. Ravnaas left Crestview Partners in 2012 to attend the Stanford Graduate School of Business, where he earned his Master in Business Administration in 2014. Mr. D. Ravnaas also has an AB in Economics from Princeton University and a MSc in Finance and Economics from the London School of Economics.

Matthew S. Daly. Matthew S. Daly was appointed Chief Operating Officer of our General Partner in May 2017. Mr. Daly has served as Senior Vice President—Corporate Development of our General Partner since September 2016. Mr. Daly served as Senior Vice President—Corporate Development of our Predecessor from August 2016 until our IPO. From 2014 to 2016, Mr. Daly served as Senior Analyst—Energy at Hirzel Capital Management LLC, a Dallas-based hedge fund, where he managed public energy investments. From 2004 to 2013, he served as Senior Analyst—Energy at Kleinheinz Capital Partners, Inc., where he managed public and private energy investments and assisted with macro hedging trades. From 2002 to 2004, Mr. Daly was a Vice President—Mergers and Acquisitions at Lazard Frères & Co. in New York City. Mr. Daly has a Bachelor of Business Administration from the University of Texas at Austin and a Master of Business Administration from the University of Chicago Booth School of Business and is a certified public accountant.

R. Blayne Rhynsburger. R. Blayne Rhynsburger has served as the Controller of the General Partner since February 2017.  Mr. Rhynsburger previously served as the Controller of our Predecessor from November 2015 until our IPO. Prior to that time, Mr. Rhynsburger served as audit manager from July 2014 to November 2015, audit senior from July 2011 to June 2014, and audit staff from September 2009 to June 2011 at Whitley Penn LLP, where he specialized in assurance and advisory services for clients in multiple industries, primarily energy clients in the public and private sectors.

101

Table of Contents Mr. Rhynsburger also has served as an adjunct professor of petroleum accounting in the graduate school of Texas Christian University’s Neeley School of Business since 2015. Mr. Rhynsburger holds a Bachelor of Business Administration degree in Accounting and Finance and a Master of Accounting degree from Texas Christian University. He is also a member of the Texas Society of Certified Public Accountants.

Brett G. Taylor. Brett G. Taylor was appointed as Executive Vice Chairman of the Board of Directors in November 2015. Mr. Taylor has over 35 years of experience in the oil and gas industry as a petroleum landman. He began his career at Texas Oil and Gas Corporation from 1982 to 1985. He then spent thirteen years at Fortson Oil Company, where he served as Land Manager and Vice President—Land from 1985 to 1998. In 1998, Mr. Taylor co-founded, with Joe B. Neuhoff, Neuhoff-Taylor Royalty Company and began acquiring producing royalties and minerals. He has also served as President and Chief Executive Officer of various private companies since 1998, and certain of such companies are Contributing Parties. Mr. Taylor has a Bachelor of Business Administration—Petroleum Land Management degree from the University of Texas at Austin and is a member of the American Association of Professional Landmen. Mr. Taylor was selected to serve as a director because of his broad knowledge of land management, oil and gas title, due diligence and related matters.

Ben J. Fortson. Ben J. Fortson was appointed as a director of our General Partner in November 2015. He has nearly 60 years of experience in the oil and gas industry. Mr. Fortson has served as President and Chief Executive Officer of Fortson Oil Company since 1986 and has been Chief Investment Officer and an Executive Vice President or Vice President of the Kimbell Art Foundation, a Contributing Party, since 1975. Mr. Fortson has served on the Board of Trustees of the Kimbell Art Foundation since 1964. He is also a member of the Exchange Club of Fort Worth, a Trustee Emeritus of Texas Christian University and an Emeritus Member of the All-American Wildcatters. Mr. Fortson has a Bachelor of Arts degree from the Texas Christian University. Mr. Fortson was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

T. Scott Martin. T. Scott Martin was appointed as a director of our General Partner in November 2015. Mr. Martin served as Chief Executive Officer of our Predecessor since July 2014 until our IPO. Mr. Martin has served as Chief Executive Officer and Chairman of EE3 LLC since 2013. He has also served as Chairman of the board of directors of Rivercrest Royalties Holdings II, LLC and/or its predecessor, Rivercrest Royalties II, LLC, since July 2015. He has over 40 years of experience in the oil and gas industry. Mr. Martin founded Ellora Energy LLC in 1995 and was Chairman and Chief Executive Officer of Ellora Energy Inc. from 2002 to 2010. Before that, he was Chief Operating Officer of Alta Energy Corporation from 1992 to 1994, Chief Executive Officer of TPEX Exploration, Inc. from 1990 to 1992 and a consulting engineer at BWAB, Inc. from 1985 to 1990. Mr. Martin began his career in the oil and gas industry in 1979 at Amoco Production Company. Mr. Martin has a Bachelor of Arts degree in Biology from Colorado College and a degree in Chemical Engineering from the University of Colorado at Boulder. He is a member of the Society of Petroleum Engineers and the Independent Petroleum Association of America. Mr. Martin was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

Mitch S. Wynne. Mitch S. Wynne was appointed as a director of our General Partner in November 2015. He has been President and owner of Wynne Petroleum Co. since 1992. Mr. Wynne has been engaged in the oil and gas industry for 37 years. In 2013, he founded MSW Royalties, LLC, a Contributing Party, where he serves as manager. Mr. Wynne served on the board of Inspire Insurance Solutions from 1997 to 2002, Millers Mutual Insurance in 1997 and the All Saints’ Episcopal School from 1994 to 1996. He has also served on the board of the Union Gospel Mission in Fort Worth since 2010. Mr. Wynne has a Bachelor of Arts degree in Political Science from Washington and Lee University. Mr. Wynne was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

William H. Adams III. William H. Adams III was appointed as a director of our General Partner effective as of the date that our common units were first listed on the NYSE. Since 2007, Mr. Adams has served as Chairman and Principal Owner of Texas Appliance Supply, Inc., a wholesale and retail appliance distribution company. From 1981 to 2006, Mr. Adams held a variety of positions in the commercial and energy banking sector, including as Executive Regional President of Texas Bank in Fort Worth and as President of Frost Bank—Arlington. From 2001 to 2010, Mr. Adams served as a member of the board of directors of XTO Energy, Inc. Mr. Adams currently serves as a member of the board of directors of Morningstar Partners, a private oil and gas production company, and as a member of the board of directors of Graham Savings and Loan, SSB, a privately owned savings bank. Mr. Adams has a Bachelor of Business Administration

102

Table of Contents in Finance from Texas Tech University. Mr. Adams was selected to serve as a director because of his extensive experience in the energy banking sector and as a former director of a public oil and gas company.

Craig Stone. Craig Stone was appointed as a director of our General Partner effective as of the date that our common units were first listed on the NYSE. Mr. Stone concluded a 30-year career with Ernst & Young LLP when he retired effective September 2015. Prior to his retirement from Ernst & Young LLP, Mr. Stone was an audit partner and the Fort Worth Managing Partner at Ernst & Young LLP. Over the course of his career, he has served many public oil and gas clients and assisted in numerous mergers, acquisitions and public offerings, including initial public offerings, secondary offerings and public debt transactions. In February 2017, Mr. Stone accepted a ministry position with the Hills Church where he oversees and manages campus construction and enhancement plans and other strategic expansion initiatives. He has a Bachelor of Sciences in Accounting from Abilene Christian University and is a certified public accountant. Mr. Stone was selected to serve as a director because of his extensive financial experience with public oil and gas companies.

Erik Daugbjerg. Erik Daugbjerg was appointed as a director of our General Partner in April 2018. Mr. Daugbjerg has more than 20 years of experience in upstream and midstream energy companies, including founding roles at two oil and gas operators based in the Permian Basin. Prior to Concho Resources, Inc.’s acquisition of RSP Permian, Inc. in July 2018, Mr. Daugbjerg served as the Executive Vice President of Land and Business Development of RSP Permian, Inc., a role to which he was appointed in March 2017. Starting in 2010, Mr. Daugbjerg served in various other roles for RSP Permian, Inc. and its affiliates, including Vice President of Business Development and Vice President of Marketing. Mr. Daugbjerg has a Bachelor in Business Administration degree from Southern Methodist University and is active with several Texas energy industry organizations. Mr. Daugbjerg was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

Board Leadership Structure

Robert D. Ravnaas currently serves as the Chief Executive Officer and Chairman of the Board of Directors. The Board of Directors has no policy with respect to the separation of the offices of chairman of the Board of Directors and chief executive officer. Instead, that relationship is defined and governed by the limited liability company agreement of our General Partner, which permits the same person to hold both offices. Directors of the Board of Directors are appointed by Kimbell Holdings, which is jointly owned by our Sponsors. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Director Independence

Because we are a limited partnership, we rely on an exemption from the provisions of the NYSE Listed Company Manual that would otherwise require our Board of Directors to be composed of a majority of independent directors. We are not required to have a compensation committee or a nominating and governance committee, although we have elected to confer matters related to the compensation of the executive officers and directors of our General Partner to the conflicts and compensation committee. In addition, we are required to have an audit committee composed of at least three members who meet the independence and experience tests established by the NYSE and the Exchange Act. Our Board of Directors has determined that William H. Adams III, Craig Stone and Erik B. Daugbjerg, each of whom serves on our audit committee (the “Audit Committee”) and our conflicts and compensation committee (the “Conflicts and Compensation Committee”), are independent under the independence standards of the NYSE and the Exchange Act.

Board Role in Risk Oversight

Our corporate governance guidelines (“Governance Guidelines”) provide that the Board of Directors is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is largely satisfied by the Audit Committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies. Our Governance Guidelines are available on our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.” 103

Table of Contents Committees of the Board of Directors

The Board of Directors has an audit committee and a conflicts and compensation committee. The Board of Directors may also have such other committees as it determines from time to time.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and Rule 10A-3 promulgated under the Exchange Act. The Audit Committee is composed of William H. Adams III, Craig Stone and Erik B. Daugbjerg. The Audit Committee assists the Board of Directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approves any non-audit services and tax services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the Audit Committee and our management, as necessary.

Each of Messrs. Adams, Stone and Daugbjerg is deemed to be “financially literate” as defined by the listing standards of NYSE, and Mr. Stone is deemed an “audit committee financial expert,” as defined in SEC regulations. Each of the members of the Audit Committee is independent under the independence standards of the NYSE. Our Audit Committee charter is available on our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Conflicts and Compensation Committee

In accordance with the terms of our partnership agreement, at least two members of the Board of Directors will serve on our Conflicts and Compensation Committee to review specific matters that may involve conflicts of interest. The Conflicts and Compensation Committee is also responsible for the oversight, and periodic review of, the General Partner’s compensation philosophy and the effectiveness of the various elements of the General Partner’s compensation program. The Conflicts and Compensation Committee is currently composed of William H. Adams III, Craig Stone and Erik B. Daugbjerg. The members of our Conflicts and Compensation Committee cannot be officers or employees of our General Partner or directors, officers or employees of its affiliates or the Contributing Parties and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our Conflicts and Compensation Committee cannot own any interest in our General Partner, its affiliates or the Contributing Parties or any interest in us or our subsidiaries other than common units and awards, if any, under our long-term incentive plan. Our Conflicts and Compensation Committee charter is available on our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires directors, executive officer and persons who beneficially own more than 10 percent of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that during fiscal year 2020 all of our directors, executive officers and persons who beneficially own more than 10 percent of a registered class of our equity securities complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act. 104

Table of Contents Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics applicable to all employees, directors and officers. Our Code of Business Conduct and Ethics covers topics including, but not limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality, bribery and corruption, sanctions and compliance procedures. Our Code of Business Conduct and Ethics is posted on the “Corporate Governance” section of our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Corporate Governance Information

Interested parties may communicate directly with the independent members of the Board of Directors by submitting correspondence in an envelope marked “Confidential” addressed to the “Independent Members of the Board” in care of the secretary of the General Partner at the following address:

Kimbell Royalty Partners, LP

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

Our Governance Guidelines, which contain our definition of director independence, provide that the non-management directors of the Board of Directors will meet periodically in executive sessions without management participation. Additionally, all of the independent directors of the Board of Directors meet in executive sessions without management participation or participation by non-independent directors at least once a year. Currently, the chairman of the Audit Committee of the Board of Directors, Craig Stone, presides at the executive sessions of the non-management directors and the executive sessions of the independent directors.  This information is also available on our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Item 11. Executive Compensation and Other Information

Compensation Discussion and Analysis

We are providing compensation disclosure that satisfies the requirements applicable to emerging growth companies, as defined in the JOBS Act. This Compensation Discussion and Analysis (“CD&A”) describes the rationale and policies with regard to the compensation of our named executive officers (“Named Executive Officers” or “NEOs”) for the year ended December 31, 2020. As an emerging growth company, our NEOs include the Chief Executive Officer and our other two most highly compensated officers. Our Named Executive Officers for the year ended December 31, 2020 include:

​	​	​
Name	​	Principal Position
Robert D. Ravnaas	​	Chairman and Chief Executive Officer (“CEO”)
R. Davis Ravnaas	​	President and Chief Financial Officer (“CFO”)
Matthew S. Daly	​	Chief Operating Officer (“COO”)

​

This CD&A is intended to provide context for the tabular disclosure provided in the executive compensation tables below and to provide investors with the material information necessary to understanding our executive compensation program.

Overview of Our Executive Compensation Program

Our General Partner has the sole responsibility for conducting our business and for managing our operations, and its executive officers and the Board of Directors make decisions on our behalf. We do not directly employ any of the persons responsible for managing our business. Our General Partner’s executive officers manage and operate our business as part of the services provided by Kimbell Operating to our General Partner under a management services agreement. All of our General Partner’s executive officers and other employees necessary to operate our business are employed and compensated by Kimbell Operating or an entity with which Kimbell Operating arranges for the provision of services. The compensation for all our executive officers is indirectly paid by us pursuant to the management services agreement with 105

Table of Contents Kimbell Operating as described in “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements.” Neither Kimbell Operating nor any affiliated entity has entered into any employment agreement with any of its executive officers.

The Partnership’s Conflicts and Compensation Committee adopted an annual review process for our executive compensation program. The most recent review of our executive compensation program was conducted in December 2020. This annual review process allows us to adjust our position based on market conditions and our business strategy to provide continual alignment between our compensation philosophy and corporate objectives.

Use of an Independent Compensation Advisory Firm

In October of 2018 we engaged Pearl Meyer LLC (“Pearl Meyer”) to review our compensation practices against the norms of its competitive markets.

Pearl Meyer also provided the Conflicts and Compensation Committee with an Independence Letter consistent with and confirming their independence with the rules under the Dodd-Frank Act, and corresponding regulations issued by the SEC and the NYSE requiring certification of their compliance as our independent compensation advisor to the Conflicts and Compensation Committee.

The Benchmarking and Market Evaluation Process

Pearl Meyer went through a formal process to identify peers in and surrounding our operations and revenue scope. This process was completed in late November 2018, and Pearl Meyer provided the Conflicts and Compensation Committee with its findings after such time. The findings indicated that the overall compensation of each of the three NEOs was at or slightly below the market median.

Later in the year and into 2019, Pearl Meyer worked with management of the General Partner and the Conflicts and Compensation Committee, including outside counsel to assist in the development of formal measures for our long-term plan and reviewed both the long and the short-term incentive plans and assisted in certain modifications to the long-term incentive program. Both plans have quantitative measures directly linked to the desired financial and operational goals to the NEOs pay opportunities.

Key Components of Our Executive Compensation Program and Compensation Mix

Our executive compensation program is a traditional structure that has been customized to align with our business and organizational objectives. We annually evaluate the various components of our compensation program relative to the competitive market. Our compensation and benefit programs for the years ended December 31, 2019 and 2018 consisted of the following key components, which are described in greater detail below:

●	Base salary;
●	Long-term incentive restricted units;
---	---
●	Non-equity incentive plan compensation, consisting of short-term incentive cash bonuses (“STI Bonuses”);
---	---
●	Other compensation, consisting of distributions received and stock vesting from the awarded restricted units; and
---	---
●	Broad-based retirement, health, and welfare benefits.
---	---

In allocating compensation among the various components, we emphasize performance-based, at-risk compensation while also providing competitive levels of fixed compensation. Long-term incentives constitute the largest portion of total compensation and provide an important connection to common unitholder interests. We do not target a specific percentage for each element of compensation relative to total compensation. We evaluate each element against the competitive market within the parameters of our compensation strategy. Therefore, the relative weighting of each element of our total pay mix may change over time as the competitive market moves or other market conditions that affect us change. Our resulting compensation mix reflects alignment with our compensation strategy of competitively targeting the market for all elements of compensation. Below expected performance against the goals in our short or long-term plans will generally yield below 106

Table of Contents market total pay but performance above our operational and financial targets can yield pay above market median into the upper third quartile of the market.

The table below presents the annual compensation of our Named Executive Officers for the years ended December 31, 2020, 2019 and 2018.

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	​	​	​	​	​	​	​	​	Non-Equity		​	​	​	​	​	​
​	​	​	​	​	​	​	Long-Term		​	Incentive Plan		​	Other		​	​	​
Name	​	Year	​	Salary		​	Restricted Units (1)(2)		​	Compensation (1)(3)		​	Compensation (4)		​	Total
Robert D. Ravnaas	​	2020	​	$	575,000	​	$	2,186,663	​	$	790,625	​	$	245,890	​	$	3,798,178
Chairman and CEO	​	2019	​	$	575,000	​	$	2,372,081	​	$	790,625	​	$	371,072	​	$	4,108,778
​	​	2018	​	$	300,000	​	$	4,221,724	​	$	300,000	​	$	303,048	​	$	5,124,772
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
R. Davis Ravnaas	​	2020	​	$	550,000	​	$	1,692,900	​	$	756,250	​	$	184,881	​	$	3,184,031
President and CFO	​	2019	​	$	550,000	​	$	1,836,450	​	$	756,250	​	$	266,992	​	$	3,409,692
​	​	2018	​	$	275,000	​	$	2,826,549	​	$	275,000	​	$	104,145	​	$	3,480,694
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Matthew S. Daly	​	2020	​	$	450,000	​	$	1,199,138	​	$	618,750	​	$	125,079	​	$	2,392,967
COO	​	2019	​	$	450,000	​	$	1,300,819	​	$	618,750	​	$	161,183	​	$	2,530,752
​	​	2018	​	$	250,000	​	$	1,652,896	​	$	220,000	​	$	26,720	​	$	2,149,616
(1)	Beginning in 2019, NEOs received their long-term incentive restricted units and STI Bonus in the first quarter of the following year, subsequent to year-end results.
---	---
(2)	Amounts for 2020 reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the February 25, 2021 grant date at $10.26 per common unit. Amounts for 2019 reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the February 28, 2020 grant date at $11.13 per common unit. Amounts for 2018 reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the January 29, 2018 grant date and the December 7, 2018 grant date at $19.10 and $17.43, respectively, per common unit. The January 29, 2018 grant reflects restricted units granted in connection with the 2017 year end, whereas the December 7, 2018 grants reflect restricted units granted in connection with the 2018 year end.
---	---
(3)	Our non-equity incentive plan compensation consists of the STI Bonus for our respective NEOs.
---	---
(4)	Amounts reflected in other compensation are presented in the table below:
---	---
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
​	​	​	​	Management		​	Distributions		​	​	​	​	​	​
​	​	​	​	Services		​	on Long-Term		​	401(k) Matching		​	Total Other
Name	​	Year	​	Agreement (i)		​	Restricted Units		​	Contributions		​	Compensation
Robert D. Ravnaas	​	2020	​	$	—	​	$	231,640	​	$	14,250	​	$	245,890
​	​	2019	​	$	—	​	$	357,072	​	$	14,000	​	$	371,072
​	​	2018	​	$	130,000	​	$	163,048	​	$	10,000	​	$	303,048
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
R. Davis Ravnaas	​	2020	​	$	—	​	$	170,631	​	$	14,250	​	$	184,881
​	​	2019	​	$	—	​	$	252,992	​	$	14,000	​	$	266,992
​	​	2018	​	$	—	​	$	94,812	​	$	9,333	​	$	104,145
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Matthew S. Daly	​	2020	​	$	—	​	$	110,829	​	$	14,250	​	$	125,079
​	​	2019	​	$	—	​	$	147,183	​	$	14,000	​	$	161,183
​	​	2018	​	$	—	​	$	18,797	​	$	7,923	​	$	26,720

(i) Amounts reflect Mr. Ravnaas’ compensation as part of the service agreement with Steward Royalties, LLC (“Steward Royalties”). See “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements*.*” 107

Table of Contents Elements of the Executive Compensation Program

Base Salary

Each NEO’s base salary is a fixed component of compensation based on the position, the incumbent’s experience and demonstrated level of expertise. Base pay, once set each year, does not vary depending on the level of performance achieved. As a result, our philosophy is to set base salary at a sufficient level necessary to attract and retain individuals with superior talent, expertise and experience. We review the base salaries for each NEO annually as well as at the time of any promotion or significant change in job responsibilities, and in connection with each review, we consider individual and company performance over the course of that year.

Long-Term Incentive Awards

The Board of Directors granted awards under the LTIP to our NEOs on February 28, 2020 consisting of 495,000 restricted units of the Partnership. In connection with the guidelines developed following the benchmark process with Pearl Meyer, as discussed above, management determined no annual long-term incentive awards would be granted to our executive officers in 2019. Beginning in 2020, and continuing in subsequent years, long-term incentive awards have quantitative measures directly linked to the desired financial and operational goals and will be granted once annually in the first quarter of each year, subsequent to year-end results. The Board of Directors granted awards under the LTIP to our NEOs on January 29, 2018 and December 7, 2018 consisting of 127,035 and 360,000, respectively, restricted units.

Each award is subject to the terms and conditions of the award agreement that we entered into with the applicable NEO. The restricted units vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through each applicable vesting date. Upon a grantee’s termination of service for any reason other than death or disability, all unvested restricted units will be immediately forfeited as of the date of termination. In the case of termination resulting from death or disability, all unvested restricted units will become fully vested as of the date of termination.

The following table reflects information regarding outstanding unvested restricted units held by our NEOs as of December 31, 2020.

​	​	​	​	​	​
​	​	Unit Awards
​	​	Number of	​	Market Value of
​	​	Restricted Units that	​	Restricted Units that
Name	​	have not vested (1)	​	have not vested (2)
Robert D. Ravnaas	​	291,319	​	$	2,304,333
R. Davis Ravnaas	​	217,825	​	$	1,722,996
Matthew S. Daly	​	148,198	​	$	1,172,246
(1)	The NEO’s outstanding restricted units will generally vest in accordance with the schedule set forth above under “Long-Term Incentive Awards” so long as the NEO remains employed by the Partnership or one of its affiliates through such dates.
---	---
(2)	Reflects the market value of our common units computed based on the closing price, $7.91, of our common units on December 31, 2020.
---	---

108

Table of Contents

Non-Equity Incentive Plan Compensation

The STI Bonuses provide our NEOs with an incentive in the form of an annual cash bonus to achieve our overall qualitative business goals. Bonuses for each of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly are based on their target bonus, qualitative performance and other discretionary factors, including achievement of strategic objectives, goals in compliance and ethics and teamwork within the Partnership. A variety of qualitative factors that vary by year and are given different weights in different years depending on facts and circumstances were considered, with no single factor being determinative to the overall bonus decision. In making the bonus determinations for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, other post-performance evaluation criteria taken into account include performance in internal and public financial reporting, budgeting and forecasting processes, compliance and infrastructure and investment and cost-savings initiatives. Non-financial factors considered also included, among other items, providing strategic leadership and direction for the Partnership, including corporate governance matters, managing the strategic direction of the Partnership, increasing operational efficiency, expanding our asset base and communicating to investors and other important constituencies. The actual amounts of Messrs. Robert D. Ravnaas’, R. Davis Ravnaas’ and Matthew S. Daly’s annual bonuses are determined by the Conflicts and Compensation Committee in its sole discretion and may be higher or lower than their target amounts.

For the years ended December 31, 2020 and 2019, respectively, after considering the factors described above and management’s recommendations, the Conflicts and Compensation Committee determined that the bonuses for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly would be set at amounts equal to 137.5% of their annual target bonus amounts. For the year ended December 31, 2018, after considering the factors described above and management’s recommendations, the Conflicts and Compensation Committee determined that the bonuses for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly would be set at amounts equal to 100% of their annual target bonus amounts. This is reflected in the Conflicts and Compensation Committee’s and management’s assessment that overall company performance and discretionary factors justified payment of such bonus to each of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly based on their and the Partnership’s performance during the fiscal year. Specifically, the Conflicts and Compensation Committee set the amount of Mr. Robert D. Ravnaas’ bonus after considering the quality of his individual performance in managing the overall operations and resources of the Partnership, the amount of Mr. R. Davis Ravnaas’ bonus after considering the quality of his individual performance in running the partnership-wide finance function and the amount of Mr. Matthew S. Daly’s bonus after considering the quality of his individual performance in running the ongoing business operations as well as the performance of the Partnership.

Additional Narrative Disclosure

Health, Welfare and Additional Benefits

Our NEOs are eligible to participate in the employee benefit plans and programs that the Partnership offers to its employees, subject to the terms and eligibility requirements of those plans.

Retirement Benefits

We currently maintain a 401(k) Plan, which permits all eligible employees, including the NEOs, to make voluntary pre-tax or after-tax (Roth) contributions to the plan. In addition, we are permitted to make discretionary matching contributions under the plan. Company matching contributions vest immediately. All contributions under the plan are subject to certain annual dollar limitations, which are periodically adjusted for changes in the cost of living.

Long-Term Incentive Plan

In order to incentivize our management and directors to continue to grow our business, the Board of Directors adopted a LTIP for employees, officers, consultants and directors of our General Partner, Kimbell Operating and their respective affiliates, who perform services for us. Our General Partner implemented the LTIP prior to the completion of our IPO to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us. We filed a registration statement on Form S-8 on May 12, 2017 for units issued pursuant to the LTIP. 109

Table of Contents The description set forth below is a summary of the material features of the LTIP. This summary, however, does not purport to be a complete description of all the provisions of the LTIP. This summary is qualified in its entirety by reference to the LTIP, which has been filed as an exhibit to a Form 8-K we filed on May 11, 2017.

The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire ownership and, consistent with stock price performance accumulate capital as a retentive force. Also, our objectives for participants is to have them build up and retain ownership of our equity interests.

The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights and cash awards (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the Board of Directors or a committee thereof that may be established for such purpose. We are responsible for the cost of awards granted under the LTIP.

Administration

The Board of Directors appointed the Conflicts and Compensation Committee to administer the LTIP, which we refer to as the “committee” for purposes of this summary. The committee administers the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee has the power to determine to whom and when awards will be granted, determine the number of awards (measured in cash or our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “non-employee directors” within the meaning of Rule 16b-3 under the Exchange Act, we expect that the full Board of Directors or a subcommittee of two or more non-employee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

Securities to be Offered

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP will not exceed 4,541,600 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP. Under the LTIP, the maximum aggregate grant date fair value of awards granted to a non-employee director of our General Partner, in such individual’s capacity as a non-employee director, during any calendar year will not exceed $500,000 (or $600,000 in the first year in which an individual becomes a non-employee director).

If any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our General Partner in the open market, from any other person, directly from us, or any combination of the foregoing.

Awards

Unit Options

We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for a unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option. Unit options may be exercised in the manner and at such times as the committee determines for each unit option and the term of the unit option will not exceed ten years. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant. 110

Table of Contents Unit Appreciation Rights

A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right. The term of the unit appreciation right will not exceed ten years.

Restricted Units

A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed. Unless otherwise determined by the committee, each restricted unit will be entitled to receive distributions in the same manner as other outstanding common units.

Unit Awards

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom Units

Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof determined by the committee. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

Distribution Equivalent Rights

The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

Miscellaneous

Tax Withholding

At our discretion, and subject to conditions that the committee may impose, the payment of any applicable taxes with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of our common units in each case up to the maximum statutory rate.

Anti-Dilution Adjustments

In the event that any distribution, recapitalization, split, reverse split, reorganization, merger, consolidation, split-up, spin-off, combination, repurchase or exchange of our common units, issuance of warrants or other rights to 111

Table of Contents purchase our common units or other similar transaction or event affects our common units, then a corresponding and proportionate adjustment will be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Change of Control

If the participant remains in service as of the date of a change in control, any unvested restricted units will be vested as of the date of such change in control. A change in control is defined as, and will be deemed to have occurred upon, the occurrence of one or more of the following events: (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than the General Partner or its affiliates, will become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by either the Partnership of all or substantially all of its assets in one or more transactions to any person other than the Partnership or an affiliate of the Partnership; or (iv) a transaction resulting in a person other than the Partnership or an affiliate of the Partnership being the general partner of the Partnership.

Termination of Employment or Service

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the Board of Directors will be determined by the committee in the terms of the relevant award agreement.

Director Compensation

Officers or employees of the Partnership who also serve as directors of our General Partner will not receive additional compensation for such service. Each director of our General Partner who is not employed by Kimbell Operating or engaged by Kimbell Operating through a management services agreement (a “non-employee director”) receives the following cash compensation:

●	(i) for a non-independent director, an annual base retainer fee of $60,000 per year or (ii) for an independent director, an annual base retainer fee of $80,000 per year, and
●	an additional retainer of $15,000 per year for an independent director who serves as a member of the Audit Committee or the Conflicts and Compensation Committee.
---	---

In addition to cash compensation, our non-employee directors receive annual equity-based compensation under the LTIP. Our non-employee directors were granted awards under the LTIP on February 28, 2020 consisting of 117,082 restricted units. No long-term incentive awards were granted to our non-employee directors in 2019. Beginning in 2020, and continuing in subsequent years, long-term incentive awards are, and will be, granted once annually in the first quarter of each year.

All retainers are paid in cash on a quarterly basis in arrears. Our non-employee directors do not receive any meeting fees, but each director is reimbursed for travel and miscellaneous expenses to attend meetings and activities of the Board of Directors or its committees. 112

Table of Contents The following table provides information concerning the compensation of our directors who are not NEOs for the year ended December 31, 2020.

​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	​	​	​	​	​	​	​	All Other	​	​	​
Name	​	Fees Earned		​	Unit Awards (6)		​	Compensation		​	Total
William H. Adams III (1)	​	$	95,000	​	$	105,688	​	$	—	​	$	200,688
Erik Daugbjerg (1)	​	$	95,000	​	$	105,688	​	$	—	​	$	200,688
Ben J. Fortson (2)	​	$	—	​	$	453,800	​	$	—	​	$	453,800
T. Scott Martin (3)	​	$	60,000	​	$	77,875	​	$	—	​	$	137,875
Craig Stone (1)	​	$	95,000	​	$	105,688	​	$	—	​	$	200,688
Brett G. Taylor (4)	​	$	—	​	$	1,647,846	​	$	250,000	​	$	1,897,846
Mitch S. Wynne (5)	​	$	—	​	$	453,800	​	$	120,000	​	$	573,800
(1)	Mr. Adams’, Mr. Daugbjerg’s and Mr. Stone’s Fees Earned include the annual cash retainer fee and committee member fees for each non-employee director, as more fully explained above. Mr. Adams, Mr. Daugbjerg and Mr. Stone each have 14,158 unvested restricted units outstanding as of December 31, 2020.
---	---
(2)	Mr. Fortson has 67,984 unvested restricted units outstanding as of December 31, 2020.
---	---
(3)	Mr. Martin’s Fees Earned includes the annual cash retainer fee for each non-employee director, as more fully explained above. Mr. Martin has 10,527 unvested restricted units outstanding as of December 31, 2020.
---	---
(4)	Mr. Taylor’s All Other Compensation consists of his salary earned as an employee of Kimbell Operating. Mr. Taylor has 206,354 unvested restricted units outstanding as of December 31, 2020.
---	---
(5)	Mr. Wynne’s All Other Compensation consists of payments made to K3 Royalties, LLC (“K3 Royalties”) as described in *“*Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements.” Mr. Wynne has 67,984 unvested restricted units outstanding as of December 31, 2020.
---	---
(6)	Amounts reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the February 28, 2020 grant date at $11.13 per common unit.
---	---

Compensation Committee Interlocks and Insider Participation

The Conflicts and Compensation Committee includes the following members: Mr. William H. Adams III, as Chairman, Mr. Craig Stone and Mr. Erik B. Daugbjerg.

None of our officers or employees has been or will be members of the Conflicts and Compensation Committee. None of our executive officers currently serve, or has served during the last year, on the board of directors or compensation committee of a company that has an executive officer that serves on our Board of Directors or Conflicts and Compensation Committee. No member of our Board of Directors is an executive officer of a company in which one of our executive officers currently serves, or has served during the last year, as a member of the board of directors or compensation committee of that company. 113

Table of Contents Conflicts and Compensation Committee Report

The Conflicts and Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis. Based on the review and discussions, the Conflicts and Compensation Committee recommends to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table presents information regarding the beneficial ownership of our common units and Class B units as of February 19, 2021 by:

●	each unitholder known by us to beneficially hold 5% or more of our common units;
●	each of our General Partner’s directors and executive officers; and
---	---
●	all of our General Partner’s directors and executive officers as a group.
---	---

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is 777 Taylor Street, Suite 810, Fort Worth, Texas 76102.

​	​	​	​	​	​	​	​	​	​
​	​	​	​	​	****	​	****	Percentage of	****
​	​	​	​	​	​	Common Units	​	Common Units	****
​	​	Common	​	Class B	​	Beneficially	​	Beneficially	****
Name of Beneficial Owner	​	Units	​	Units	​	Owned (1)	​	Owned (1)	****
Kimbell Art Foundation (2)	​	—	​	5,135,020		5,135,020		8.6	%
EIGF Aggregator III LLC (3)	​	3,897,483	​	—	​	3,897,483	​	6.5	%
PEP II Holdings, LLC (4)(6)	​	—	​	3,318,200	​	3,318,200	​	5.6	%
PEP III Holdings, LLC (5)(7)	​	—	​	5,358,000	​	5,358,000	​	9.0	%
Directors and Officers	​	​	​	​	​	​	​	​	​
Robert D. Ravnaas (8)	​	728,230	​	263,380		991,610		1.7	%
R. Davis Ravnaas (9)	​	357,668	​	263,380		621,048		1.0	%
Matthew S. Daly (10)	​	240,704	​	—		240,704		*	%
Blayne Rhynsburger (11)	​	31,145	​	—	​	31,145	​	*	%
Brett G. Taylor (12)	​	564,265	​	—		564,265		*	%
Ben J. Fortson (13)	​	203,092	​	5,135,020		5,338,112		8.9	%
Mitch S. Wynne (14)	​	211,251	​	—		211,251		*	%
T. Scott Martin (15)	​	39,252	​	263,380		302,632		*	%
William H. Adams III (16)	​	50,654	​	—		50,654		*	%
Craig Stone	​	25,382	​	—		25,382		*	%
Erik B. Daugbjerg	​	38,978	​	—	​	38,978	​	*	%
All directors and executive officers as a group (11 persons)	​	2,490,621	​	5,925,160		8,415,781		14.1	%
*	Less than 1%
---	---
(1)	Assumes the full exchange of all outstanding OpCo common units and Class B units for common units.
---	---
(2)	The principal business address of the Kimbell Art Foundation is 301 Commerce Street, Suite 2300, Fort Worth, Texas 76102. Ben J. Fortson is Executive Vice President and Chief Investment Officer of the Kimbell Art Foundation. Mr. Fortson was delegated authority to manage the investment assets of the Kimbell Art Foundation and, therefore, may be deemed to have voting or investment power over the securities owned by the Kimbell Art Foundation. Mr. Fortson disclaims beneficial ownership of such securities.
---	---
(3)	EIGF Aggregator LLC (“EIGF Aggregator”) is the managing member of EIGF Aggregator III. KKR Energy Income and Growth Fund I L.P. (“KKR Energy Income”) is the managing member of EIGF Aggregator. KKR Associates
---	---

114

Table of Contents

EIGF L.P. (“KKR Associates”) is the general partner of KKR Energy Income. KKR Energy Income and Growth Fund I-TE L.P. (“KKR Energy Income TE”) is the sole member of TE Drilling Aggregator LLC (“TE Drilling Aggregator”), and KKR Associates EIGF TE L.P. (“KKR Associates TE”) is the general partner of KKR Energy Income TE. KKR EIGF LLC (“KKR EIGF”) is the general partner of KKR Associates and the general partner of KKR Associates TE. KKR Upstream Associates LLC (“KKR Upstream Associates”) is the sole member of KKR EIGF. KKR Group Partnership L.P. (“KKR Group Partnership”) and KKR Upstream LLC (“KKR Upstream”) are the members of KKR Upstream Associates. KKR Group Partnership is the sole member of KKR Upstream. KKR Group Holdings Corp. (“KKR Group Holdings”) is the general partner of KKR Group Partnership. KKR & Co. Inc. (“KKR & Co.”) is the sole shareholder of KKR Group Holdings. KKR Management LLP (“KKR Management”) is the Class B shareholder of KKR & Co. Messrs. Kravis and Roberts are the founding partners of KKR Management. As such, each of the above may be deemed the beneficial owners having shared voting and investment power with respect to all or a portion of the securities held by EIGF Aggregator III and TE Drilling Aggregator. The principal business address of each of the entities and persons identified in this paragraph, except Mr. Roberts, is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, NY 10019. The principal business address for Mr. Roberts is c/o Kohlberg Kravis Roberts & Co. L.P., 2800 Sand Hill Road, Suite 200, Menlo Park, CA 94025.
(4)	EnCap Partners GP, LLC, a Delaware limited liability company (“EnCap Partners GP”), is the sole general partner of EnCap Partners, LP, a Delaware limited partnership, which is the managing member of EnCap Investments Holdings, LLC, a Delaware limited liability company, which is the sole member of EnCap Investments GP, L.L.C., a Delaware limited liability company, which is the general partner of EnCap Investments L.P., a Delaware limited partnership, which is the general partner of EnCap Equity Fund VI GP, L.P., a Texas limited partnership (“EnCap Fund VI GP”), EnCap Equity Fund VII GP, L.P., a Texas limited partnership, and EnCap Equity Fund VIII GP, L.P., a Texas limited partnership, which are the general partners of EnCap Energy Capital Fund VI, L.P., a Texas limited partnership (“EnCap Fund VI”), EnCap Energy Capital Fund VII, L.P., a Texas limited partnership (“EnCap Fund VII”), and EnCap Energy Capital Fund VIII, L.P., a Texas limited partnership (“EnCap Fund VIII”), respectively. Additionally, EnCap Fund VI GP is the general partner of EnCap Energy Capital Fund VI-B, L.P., a Texas limited partnership, which is the sole member of EnCap VI-B Acquisitions GP, LLC, a Delaware limited liability company, which is the general partner of EnCap VI-B Acquisitions, L.P., a Texas limited partnership (“EnCap VI-B”). The securities reported above as beneficially owned by the Phillips Sellers may be distributed by the Phillips Sellers to each of their members in accordance with the terms of their respective limited liability company agreements. The principal business address of the Phillips Sellers and each of the entities identified in this paragraph is 1100 Louisiana Street, Suite 4900, Houston, Texas 77002.
---	---
(5)	EnCap Fund VI and EnCap VI B are the managing members of Phillips I. Therefore, EnCap Partners GP, EnCap Fund VI and EnCap VI B may be deemed to beneficially own all of the reported securities that are deemed to be beneficially owned by Phillips I. Each of EnCap Partners GP, EnCap Fund VI and EnCap VI B disclaims beneficial ownership of the reported securities except to the extent of its pecuniary interest therein, and this statement shall not be deemed an admission that it is the beneficial owner of the reported securities for the purposes of Section 13(d) of the Exchange Act or any other purpose.
---	---
(6)	EnCap Fund VII is the managing member of Phillips II. Therefore, EnCap Partners GP and EnCap Fund VII may be deemed to beneficially own all of the reported securities that are deemed to be beneficially owned by Phillips II. Each of EnCap Partners GP and EnCap Fund VII disclaims beneficial ownership of the reported securities except to the extent of its pecuniary interest therein, and this statement shall not be deemed an admission that it is the beneficial owner of the reported securities for the purposes of Section 13(d) of the Exchange Act or any other purpose. 42,081 OpCo common units and an equivalent number of Class B units are held in escrow pending the outcome of ongoing litigation involving certain of the Acquired Phillips Subsidiaries.
---	---
(7)	EnCap Fund VIII is the managing member of Phillips III. Therefore, EnCap Partners GP and EnCap Fund VIII may be deemed to beneficially own all of the reported securities that are deemed to be beneficially owned by Phillips III. Each of EnCap Partners GP and EnCap Fund VIII disclaims beneficial ownership of the reported securities except to the extent of its pecuniary interest therein, and this statement shall not be deemed an admission that it is the beneficial owner of the reported securities for the purposes of Section 13(d) of the Exchange Act or any other purpose.
---	---

115

Table of Contents

(8)	Robert D. Ravnaas is a partner or member in certain entities that directly or indirectly hold, in the aggregate, approximately 134,264 common units and 3,076,559 Class B units. Mr. R. Ravnaas may be deemed to have voting or investment power with respect to 114,264 common units and 263,380 Class B units held by such entities. Mr. R. Ravnaas has a pecuniary interest in an aggregate of approximately 150,666 common units and 15,110 Class B units based on his ownership interest in such entities, and Mr. R. Ravnaas disclaims beneficial ownership of the securities that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.
(9)	R. Davis Ravnaas is a partner or member in certain entities that hold, directly or indirectly, in the aggregate, approximately 34,243 common units and 3,076,559 Class B units. Mr. D. Ravnaas may be deemed to have voting or investment power with respect to 263,380 Class B units held by such entities. Mr. D. Ravnaas has a pecuniary interest in an aggregate of approximately 34,243 common units and 15,110 Class B units based on his ownership interest in such entities, and Mr. D. Ravnaas disclaims beneficial ownership of the securities that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.
---	---
(10)	Matthew Daly is a member of Rivercrest Capital Investors LP, a member of Rivercrest Capital Partners LP (the “Fund”), which holds 2,813,179 Class B units. Mr. Daly does not have voting or investment power with respect to the Class B units held by the Fund. Mr. Daly has a pecuniary interest in approximately 3,376 Class B units owned by the Fund based on his ownership interest in the Fund, and Mr. Daly disclaims beneficial ownership of the securities that may be deemed to be owned by such entity except to the extent of his pecuniary interest therein.
---	---
(11)	Blayne Rhynsburger is a member of Rivercrest Capital Investors LP, a member of the Fund, which holds 2,813,179 Class B units. Mr. Rhynsburger does not have voting or investment power with respect to the Class B units held by the Fund. Mr. Rhynsburger has a pecuniary interest in approximately 563 Class B units owned by the Fund based on his ownership interest in the Fund, and Mr. Rhynsburger disclaims beneficial ownership of the securities that may be deemed to be owned by such entity except to the extent of his pecuniary interest therein.
---	---
(12)	Brett G. Taylor is a partner in, member of or sole trustee of certain entities that hold, directly or indirectly, in the aggregate, approximately 185,689 common units, and Mr. Taylor may be deemed to have voting or investment power with respect to such common units. Mr. Taylor has a pecuniary interest in an aggregate of approximately 150,505 common units based on his ownership interest in such entities, and Mr. Taylor disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.
---	---
(13)	Ben J. Fortson is Executive Vice President and Chief Investment Officer of the Kimbell Art Foundation. Mr. Fortson was delegated authority to manage the investment assets of the Kimbell Art Foundation and, therefore, may be deemed to have voting or investment power over 5,135,020 Class B units owned by the Kimbell Art Foundation. Furthermore, Mr. Fortson is a member, sole shareholder or trustee of certain entities that hold, directly or indirectly, in the aggregate, approximately 63,082 common units, and Mr. Fortson may be deemed to have voting or investment power with respect to such common units. Mr. Fortson has a pecuniary interest in an aggregate of approximately 38,082 common units based on his ownership interest in such entities, and Mr. Fortson disclaims beneficial ownership of all of the securities that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.
---	---
(14)	Mitch S. Wynne is a member of or trustee of certain entities that hold, directly or indirectly, in the aggregate, approximately 77,455 common units, and Mr. Wynne may be deemed to have voting or investment power with respect to all of such common units. Mr. Wynne has a pecuniary interest in an aggregate of approximately 40,539 common units based on his ownership interest in such entities, and Mr. Wynne disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein. 27,539 common units owned by a trust for which Mr. Wynne serves as trustee are subject to a negative pledge under a loan agreement with a bank.
---	---
(15)	T. Scott Martin is a member in certain entities that directly or indirectly hold, in the aggregate, approximately 12,100 common units and 3,076,559 Class B units. Mr. Martin has voting or investment power with respect to 12,100 common units and 263,380 Class B units held by such entities. Mr. Martin has a pecuniary interest in approximately 12,100 common units and 15,110 Class B units based on his ownership interest in such entities, and Mr. Martin disclaims beneficial ownership of the securities that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.
---	---

116

Table of Contents

(16)	Bill Adams has pledged approximately 36,496 common units as collateral for a margin account with a bank.

In July 2018, in connection with the closing of the Haymaker Acquisition, we completed the private placement of 110,000 Series A preferred units to certain affiliates of Apollo Global Management, LLC (the “Series A Purchasers”). On February 12, 2020, we completed the redemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The below table sets forth the beneficial ownership of our Series A preferred units as of February 19, 2021 by each unitholder known by us to beneficially hold 5% or more of our Series A preferred units. The Series A Purchasers collectively hold all of the Series A preferred units.

​	​	​	​	​	​
​	​	Series A	​	Percentage of	​
​	​	Preferred Units	​	Series A	​
​	​	Beneficially	​	Preferred Units	​
Name of Beneficial Owner (1)	​	Owned	****	Owned	****
AHVF Intermediate Holdings, L.P.	​	30,140		54.8	%
AP KRP Credit Intermediate, LLC	​	6,655		12.1	%
ATCF SPV, LLC	​	6,655		12.1	%
(1)	The address for each beneficial owner in this table is 9 West 57th Street, 37th Floor, New York, New York 10019. We have been advised that Joseph D. Glatt, as vice president of one or more affiliates and/or funds or separate accounts managed by Apollo Credit Management, LLC and/or its affiliates, has the power to vote or dispose of the securities.
---	---

The below table sets forth the beneficial ownership of the equity interests in our General Partner as of February 19, 2021:

​	​	​	​
Name of Beneficial Owner (1)		Membership Interest	****
Kimbell GP Holdings, LLC (2)		100	%
Robert D. Ravnaas (3)		33.33	%
Brett G. Taylor (3)		33.33	%
Mitch S. Wynne / Ben J. Fortson (3)		33.33	%
(1)	The address for each beneficial owner in this table is 777 Taylor Street, Suite 810, Fort Worth, Texas 76102.
---	---
(2)	Kimbell GP Holdings, LLC is controlled by entities affiliated with Robert D. Ravnaas, Brett G. Taylor, Mitch S. Wynne and Ben J. Fortson.
---	---
(3)	Messrs. R. Ravnaas, Taylor, Wynne and Fortson, by virtue of their indirect ownership interest in Kimbell GP Holdings, LLC, which owns our General Partner, may be deemed to beneficially own the non-economic general partner interest in us held by our General Partner. Each of Messrs. R. Ravnaas, Taylor, Wynne and Fortson disclaims beneficial ownership of this interest.
---	---

117

Table of Contents Equity Compensation Plan Information

On February 3, 2017, the Board of Directors adopted the LTIP. On September 23, 2018, the General Partner entered into the First Amendment to the LTIP (the “LTIP Amendment”), which increased the number of common units eligible for issuance under the LTIP by 2,500,000 common units for a total of 4,541,600 common units. The following table provides certain information with respect to this plan as of December 31, 2020:

​	​	​	​	​	​	​
**** ​	****	Number of	****	​	****	​
​	​	Securities to be	​	Weighted	​	Number of Securities
​	​	Issued Upon	​	-Average	​	Remaining Available for
​	​	Exercise of	​	Exercise Price	​	Future Issuance Under
​	​	Outstanding	​	of Outstanding	​	Equity Compensation
​	​	Options,	​	Options,	​	Plans (Excluding
​	​	Warrants	​	Warrants and	​	Securities Reflected in
​	​	and Rights(1)	​	Rights(2)	​	Column(a))
​	​	(a)	​	(b)	​	(c)
Equity compensation plans approved by unitholders		—		—		2,366,456
Equity compensation plans not approved by unitholders		—		—		—
Total	​	—	​	—	​	2,366,456
(1)	The long-term incentive plan currently permits the grant of awards covering an aggregate of 4,541,600 units of which, 2,175,144 restricted and common units have been granted. Because these awards have already resulted in the issuance of common units (whether or not restricted), they are not included in column (a).
---	---

Director Independence

Because we are a publicly traded partnership, the NYSE does not require our Board of Directors to have a majority of independent directors. For a discussion of the independence of our Board of Directors, please read “Item 10. Directors, Executive Officers and Corporate Governance.”

Item 13. Certain Relationships and Related Party Transactions, and Director Independence

As of February 19, 2021, Kimbell Holdings owns 30,000 common units, representing 0.05% of our limited partner interests outstanding. In addition, Kimbell Holdings owns a 100.0% membership interest in the General Partner, which owns a non-economic general partner interest in us. Messrs. R. Ravnaas and Taylor each own a 33.33% interest in Kimbell Holdings, and Messrs. Wynne and Fortson each own a 16.67% interest in Kimbell Holdings. Kimbell Holdings and each of the Sponsors may be deemed to be a “parent” by virtue of their control over the General Partner. Please read “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for more information relating to each Sponsor’s beneficial ownership in us and the General Partner.

Restructuring, Tax Election and Related Transactions

On July 24, 2018, we entered into a Recapitalization Agreement (the “Recapitalization Agreement”) with Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC (collectively, the “Haymaker Holders”), the Kimbell Art Foundation, Haymaker Resources, LP, the General Partner and the Operating Company pursuant to which (a) our equity interest in the Operating Company was recapitalized into 13,886,204 newly issued OpCo common units of the Operating Company and 110,000 newly issued OpCo Series A preferred units and (b) the 10,000,000 and 2,953,258 common units held by the Haymaker Holders and the Kimbell Art Foundation, respectively, were exchanged for (i) 10,000,000 and 2,953,258 newly issued Class B units, respectively, and (ii) 10,000,000 and 2,953,258 newly issued OpCo common units, respectively. The Class B units and OpCo common units are exchangeable together into an equal number of our common units.

In May 2018, the Board of Directors unanimously approved a change of our federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. The Tax Election became effective on September 24, 2018. In preparation for making this election, on September 23, 2018, we (i) amended and restated our partnership agreement, (ii) amended and restated the limited liability company agreement of the Operating Company and (iii) entered into an exchange agreement with the Haymaker Holders, the Kimbell Art Foundation, the General Partner and 118

Table of Contents the Operating Company. Simultaneously with the effectiveness of these agreements, the transactions described in the Recapitalization Agreement were consummated.

Pursuant to the terms of the Recapitalization Agreement, the Haymaker Holders and the Kimbell Art Foundation each paid five cents per Class B unit to the Partnership as additional consideration with respect to the Class B units. The Haymaker Holders and the Kimbell Art Foundation, as holders of the Class B units, are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units but prior to distributions on the common units. Furthermore, in advance of the effectiveness of the Tax Election, Messrs. Fortson, R. Ravnaas, Taylor and Wynne facilitated a total contribution of 30,000 common units to Kimbell Holdings.

Following the effectiveness of the Tax Election and the completion of the related transactions, our royalty and minerals business continues to be conducted through the Operating Company, which is taxed as a partnership for federal and state income tax purposes.

Haymaker Registration Rights Agreement

On July 12, 2018, in connection with the closing of the Haymaker Acquisition and the issuance of the Series A preferred units, we entered into a registration rights agreement (the “Haymaker Registration Rights Agreement”) with the Haymaker Holders and the Series A Purchasers, pursuant to which, among other things, we agreed to (i) prepare, file with the SEC and use our reasonable best efforts to cause to become effective within 160 days of the execution of the Haymaker Registration Rights Agreement, a shelf registration statement with respect to the resale of the common units issued or issuable to the Haymaker Holders and the Series A Purchasers, (ii) use our reasonable best efforts to maintain the effectiveness of a shelf registration statement while the Haymaker Holders, the Series A Purchasers and each of their transferees are in possession of such securities and (iii) under certain circumstances, initiate underwritten offerings for such securities.

On July 30, 2018, we filed a registration statement on Form S-3 (the “Haymaker Form S-3”) to satisfy, in part, certain rights and obligations under the Haymaker Registration Rights Agreement. Prior to the effectiveness, the Haymaker Form S-3 was amended on September 19, 2018. The Haymaker Form S-3 was subsequently declared effective by the SEC on September 21, 2018.

Dropdown Registration Rights Agreement

On December 20, 2018, we completed the acquisition of (i) certain overriding royalty, royalty and other mineral interests from Rivercrest Capital Partners LP, the Kimbell Art Foundation and Cupola Royalty Direct, LLC and (ii) all of the equity interests of a subsidiary of Rivercrest Royalties Holdings II, LLC in exchange for a total of 6,500,000 OpCo common units and an equal number of Class B units. Certain of the Dropdown Sellers are affiliates of the General Partner, and the entities that control the General Partner, as well as members of the Board of Directors and our Chief Executive Officer and President and Chief Financial Officer. The Kimbell Art Foundation, which is one of our affiliates, received 2,181,762 OpCo common units and an equal number of Class B units in connection with the Dropdown.

Also on December 20, 2018, in connection with the Dropdown, we entered into a registration rights agreement (the “Dropdown Registration Rights Agreement”) with the Dropdown Sellers, pursuant to which, among other things, we agreed to (i) prepare a shelf registration statement or an amendment to our existing shelf registration statement, in either event, with respect to the resale of the common units issued or issuable to the Dropdown Sellers, (ii) file a shelf registration statement satisfying the requirements of clause (i) with the SEC within 30 days of the execution of the Dropdown Registration Rights Agreement and use our reasonable best efforts to cause such shelf registration statement to become effective as soon as reasonably practicable following such filing, but in any event within 180 days of the execution of the Dropdown Registration Rights Agreement, and (iii) use our reasonable best efforts to maintain the effectiveness of such shelf registration statement while the Dropdown Sellers and each of their transferees are in possession of such securities.

On January 29, 2019, we filed a registration statement on Form S-3 (the “Dropdown Form S-3”) to satisfy, in part, certain rights and obligations under the Dropdown Registration Rights Agreement. Prior to the effectiveness, the 119

Table of Contents Dropdown Form S-3 was amended on March 18, 2019, and March 19, 2019, and the Dropdown Form S-3 was declared effective by the SEC on March 21, 2019.

Phillips Registration Rights Agreement

In connection with the closing of the Phillips Acquisition, on March 25, 2019, we entered into an Amended and Restated Registration Rights Agreement (the “Amended and Restated Registration Rights Agreement”) with the Phillips Sellers, the Haymaker Holders, the Series A Purchasers and certain of the Dropdown Sellers. The Amended and Restated Registration Rights Agreement amended and consolidated the Haymaker Registration Rights Agreement and the Dropdown Registration Rights Agreement.

Pursuant to the terms of the Amended and Restated Registration Rights Agreement, we are obligated to, among other things, prepare a shelf registration statement or an amendment to our existing shelf registration statement, in either event, with respect to the resale of our common units issued or issuable upon the exchange of the OpCo common units and a corresponding number of Class B units issued in connection with the Haymaker Acquisition, the Dropdown and the Phillips Acquisition.

On April 23, 2019, we filed a registration statement on Form S-3 (the “Phillips Form S-3”) to satisfy, in part, certain rights and obligations under the Amended and Restated Registration Rights Agreement. Prior to the effectiveness, the Phillips Form S-3 was amended on May 17, 2019. The Phillips Form S-3 was subsequently declared effective by the SEC on May 23, 2019.

Springbok Registration Rights Agreement

In connection with the closing of the Springbok Acquisition, on April 17, 2020, we entered into a Registration Rights Agreement (the “Springbok Registration Rights Agreement”) with the Springbok Sellers.

Pursuant to the terms of the Springbok Registration Rights Agreement, we are obligated to, among other things, prepare a shelf registration statement or an amendment to our existing shelf registration statement, in either event, with respect to the resale of our common units issued or issuable upon the exchange of the OpCo common units and a corresponding number of Class B units issued in connection with the Springbok Acquisition.

On May 15, 2020, we filed a registration statement on Form S-3 (the “Springbok Form S-3”) to satisfy, in part, certain rights and obligations under the Springbok Registration Rights Agreement. The Springbok Form S-3 was subsequently declared effective by the SEC on May 29, 2020.

Distributions and Payments to our General Partner and its Affiliates

Distributions

We generally make cash distributions to our unitholders pro rata. Our General Partner owns a non-economic general partner interest in us and therefore is not entitled to receive cash distributions. However, it may acquire common units and other partnership interests in the future and will be entitled to receive pro rata distributions in respect of those partnership interests.

Following the Restructuring, Kimbell Holdings is entitled to receive its pro rata portion of the distributions we make on our common units.

The Dropdown Sellers are entitled to receive their pro rata portion of the distributions the Operating Company makes on the OpCo common units, and, as the holder of Class B units, they are also entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution. Certain of the Haymaker Holders, which may be deemed to be affiliates by virtue of their significant beneficial ownership of an interest in us, are entitled to receive their pro rata portion of the distributions the Operating Company makes on the OpCo common units, and, as holders of Class B units, they are also entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contributions. 120

Table of Contents The Series A Purchasers, which may be deemed to be affiliates by virtue of their significant beneficial ownership of an interest in us and certain rights afforded to the Series A Purchasers under our partnership agreement, are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus any accrued and unpaid distributions.

Payments

We will reimburse our General Partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all expenses they incur and payments they make on our behalf. Our partnership agreement and the limited liability company agreement of the Operating Company provide that our General Partner will determine the expenses that are allocable to us, but do not limit the amount of expenses for which our General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates.

Agreements and Transactions with Affiliates in Connection with our Initial Public Offering

In connection with our IPO, we entered into certain agreements and transactions with our Sponsors, the Contributing Parties and their respective affiliates, as described in more detail below. These agreements and transactions were not the result of arm’s-length negotiations and they, or any of the transactions that they provide for, were not effected on terms at least as favorable to the parties to these agreements as could have been obtained from unaffiliated third parties. Because some of these agreements related to formation transactions that, by their nature, would not occur in a third-party situation, it is not possible to determine what the differences would be in the terms of these transactions when compared to the terms of transactions with an unaffiliated third party. We believe the terms of these agreements to be comparable to the terms of agreements used in similarly structured transactions.

Contribution Agreement

In connection with our IPO, we entered into a contribution agreement with our Sponsors and the Contributing Parties that effected the transfer of the mineral and royalty interests owned by the Contributing Parties to us and the use of the net proceeds of our IPO, and also addressed the following matters:

●	our option to participate in certain acquisitions by the Contributing Parties of mineral and royalty interests;
●	our Sponsors’ and the Contributing Parties’ registration rights with respect to the registration and sale of common units held by them or their affiliates; and
---	---
●	the Contributing Parties’ obligation to indemnify us for certain limited matters associated with the mineral and royalty interests and associated entities, and our obligation to indemnify the Contributing Parties for certain limited matters related to the mineral and royalty interests and associated entities to the extent they are not required to indemnify us.
---	---

Participation Right. Pursuant to the contribution agreement, we have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. Unless consented to in writing by our General Partner on our behalf, the participation right shall be on terms and conditions substantially the same as or better than the acquisition by our Sponsors and the Contributing Parties. The participation right will last for so long as any of our Sponsors or their respective affiliates control our General Partner.

Registration Rights. Pursuant to the contribution agreement, the Contributing Parties have specified demand and piggyback participation rights with respect to the registration and sale of common units held by them or their affiliates. At any time following the time when we are eligible to file a registration statement on Form S-3, each of our Sponsors has the right to cause us to prepare and file a registration statement on Form S-3 with the SEC covering the offering and sale of common units held by its affiliates. We are not obligated to effect more than one such demand registration in any 12-month period or two such demand registrations in the aggregate. If we propose to file a registration statement pursuant to a Sponsor’s demand registration discussed above, the Contributing Parties may request to “piggyback” onto such registration statement in order to offer and sell common units held by them or their affiliates. We have agreed to pay all 121

Table of Contents registration expenses in connection with such demand and piggyback registrations. Registration expenses do not include underwriters’ compensation, stock transfer taxes or counsel fees.

Indemnification. The Contributing Parties made representations and warranties to us regarding their respective mineral and royalty interests and the associated entities. In addition, the Contributing Parties are, severally but not jointly, obligated to indemnify us for any federal, state and local income tax liabilities attributable to the ownership and operation of the mineral and royalty interests and the associated entities prior to the closing of our IPO until 30 days after the applicable statute of limitations. This indemnification obligation is capped at ten percent of the net proceeds received by any such Contributing Party with respect to the entity or asset that is subject to such claim for indemnification. The Contributing Parties are not required to indemnify us for breaches of any other representations and warranties under the contribution agreement, including breaches related to other title matters, consents and permits or compliance with environmental laws, and such other representations and warranties did not survive the closing of our IPO.

In addition, the Contributing Parties will indemnify us indefinitely against losses arising from certain liens created during their ownership of the entities and breaches of special warranty of title relating to the assets contributed to us in connection with our IPO. This indemnification obligation is capped at the net proceeds received by any such Contributing Party with respect to the entity or asset that is subject to such claim for indemnification.

We have agreed to indemnify the Contributing Parties for breaches of specified representation and warranties and for events and conditions associated with the ownership or operation of the mineral and royalty interests and the associated entities (other than any liabilities for which the Contributing Parties are specifically required to indemnify us as described above). Our indemnification obligation for breaches of specified representations and warranties is capped at ten percent of the aggregate net proceeds received by all of the Contributing Parties. Our indemnification obligation for all other liabilities is capped at the aggregate net proceeds received by all of the Contributing Parties.

Management Services Agreements

Management Services Agreement with Kimbell Operating

We have entered into a management services agreement with Kimbell Operating, pursuant to which Kimbell Operating provides management, administrative, operational and acquisition services to us, including via the services agreements with the Sponsor Managers and the Non-Sponsor Managers (each as defined below). The management services agreement with Kimbell Operating is under terms and conditions similar to those described below in “—Services Agreements with Our Sponsors” and “—Other Services Agreements,” except that neither party to the agreement may terminate unless all of the services agreements with the Sponsor Managers and the Non-Sponsor Managers have terminated. During the years ended December 31, 2020, 2019 and 2018, we paid to Kimbell Operating services fees equal to $0.9 million, $1.5 million and $1.7 million, respectively, which amounts represent an estimated allocation of all projected costs to be incurred by Kimbell Operating in providing such services to us for the respective year, including pursuant to the services agreements with the Sponsor Managers and the Non-Sponsor Managers.

Services Agreements with Our Sponsors

Services. Kimbell Operating currently has services agreements with BJF Royalties, LLC (“BJF Royalties”) and K3 Royalties (collectively, the “Sponsor Managers”), which are entities controlled by Messrs. Fortson and Wynne, respectively. Pursuant to these agreements, the Sponsor Managers provide management, administrative and operational services to Kimbell Operating. In addition, the Sponsor Managers or their affiliates provide acquisition services to us, including identifying, evaluating and recommending to us acquisition opportunities and any related negotiating of such opportunities. The services to be provided by each Sponsor Manager are as set forth below:

●	BJF Royalties: For all of our assets and the assets of our affiliates, BJF Royalties assists in sourcing, evaluating and recommending acquisitions, and assisting with business development opportunities related to potential acquisitions and other strategic transactions.
●	K3 Royalties: For all of our assets and the assets of our affiliates, K3 Royalties assists in sourcing, evaluating and recommending acquisitions, and assists with business development, investor and public relations and
---	---

122

Table of Contents

relationship management with our sponsors, past and future sellers of mineral assets and the Kimbell Art Foundation.

The Sponsor Managers have the exclusive right to provide the acquisition services listed above in connection with acquisitions by us, as well as the exclusive right to provide any additional management services reasonably required with respect to properties newly acquired by us.

Kimbell Operating previously had services agreements with Steward Royalties and Taylor Companies Mineral Management, LLC (“Taylor Companies”). Effective as of December 31, 2019, Kimbell Operating and each of Steward Royalties and Taylor Companies entered into agreements to terminate the services agreements of such service providers. The individuals who previously provided services pursuant to the Steward Royalties and Taylor Companies services agreements have been hired as employees of Kimbell Operating and will continue to provide the same services to us through the management services agreement between us and Kimbell Operating, and no monthly services fee will be paid to Steward Royalties or Taylor Companies following the termination of such services agreements. The services that were provided by each Steward Royalties and Taylor Companies are as set forth below:

​

●	Steward Royalties: For all of our assets and the assets of our affiliates, Steward Royalties assists in sourcing, evaluating (including providing pricing guidance, reservoir engineering analysis, and geological work), and negotiating acquisition opportunities for us; and provides ongoing petroleum engineering services.
●	Taylor Companies:
---	---
●	Taylor Companies assists in sourcing, evaluating (including directing all land and legal due diligence) and negotiating acquisition opportunities for us; assists in notifying and providing recorded transfer documents for newly acquired properties; assists in retaining outside legal counsel and landmen in connection with acquisition opportunities; maintains land and legal records with respect to newly acquired properties; and performs certain additional services with respect to newly acquired properties.
---	---
●	In addition, with respect to certain of our subsidiaries and assets, Taylor Companies provides management services including: negotiating and executing leases, right of way agreements, pooling orders and similar agreements and orders; providing certain recordkeeping services; resolving title issues; receiving and disbursing royalty and other payments; and providing certain additional accounting, title, human resources, regulatory compliance and other services.
---	---

Service Fees and Reimbursement. Under the services agreements, Kimbell Operating paid to K3 Royalties a monthly services fee of $10,000 for the year ended December 31, 2020. Under the services agreements, Kimbell Operating paid to Taylor Companies and K3 Royalties a monthly services fee of approximately $43,900 and $10,000, respectively, for the year ended December 31, 2019. Kimbell Operating paid to Steward Royalties, Taylor Companies and K3 Royalties a monthly services fee of approximately $10,800, $43,900 and $10,000, respectively, for the year ended December 31, 2018. These amounts represent an estimated allocation of all projected costs to be incurred by such Sponsor Manager in providing services to Kimbell Operating for the respective year. Upon the approval of the Board of Directors, Kimbell Operating will pay a monthly services fee of $10,000 to K3 Royalties, for the period from January 1, 2021 through December 31, 2021. In addition, BJF Royalties will continue to not receive a monthly services fee in connection with providing its services.

Subject to the approval of the Board of Directors, the monthly services fee will be adjusted in the future (i) annually, (ii) in the event of any sale of serviced properties or (iii) in the event of the provision of any additional management services (including with respect to acquisitions of new properties). In addition, Kimbell Operating is required to reimburse each Sponsor Manager for all other reasonable costs and expenses (including, but not limited to, third-party expenses and expenditures) that such Sponsor Manager incurs on behalf of Kimbell Operating in providing services. If Kimbell Operating terminates a services agreement for any reason other than the Sponsor Manager’s default (as described below), then Kimbell Operating will also reimburse the applicable Sponsor Manager for its reasonable costs and expenses incurred in connection with such termination. 123

Table of Contents Term and Termination. The initial term of the services agreement with the Sponsor Managers is five years, after which date they will continue on a year-to-year basis unless terminated by Kimbell Operating or by the applicable Sponsor Manager upon 90 days’ notice, except as otherwise stated below:

●	The applicable Sponsor Manager may terminate its services agreement, or the provision of any service thereunder, upon at least 180 days’ notice to Kimbell Operating.
●	The applicable Sponsor Manager may terminate its services agreement upon a default by Kimbell Operating, which includes (i) Kimbell Operating’s failure to perform any of its material obligations under the agreement, where such default continues unremedied for a period of 15 days after notice thereof, and (ii) the occurrence of certain events relating to the bankruptcy or insolvency of Kimbell Operating.
---	---
●	Kimbell Operating may terminate a services agreement upon a default by the applicable Sponsor Manager, upon 15 days’ notice to such Sponsor Manager. A Sponsor Manager is in default upon the occurrence of any gross negligence or willful misconduct of such Sponsor Manager in performing services under its services agreement, which results in material harm to us and our affiliates, including Kimbell Operating (the “Partnership Service Group”).
---	---
●	Kimbell Operating or the Sponsor Manager may terminate the applicable services agreement if, at any time, the Sponsors or their affiliates no longer control our General Partner, upon at least 90 days’ notice to the other party.
---	---

Kimbell Operating’s only remedy for a Sponsor Manager’s default under its services agreement is the termination of the applicable agreement as described in the third bullet point above.

Indemnification. Under the services agreements with the Sponsor Managers, Kimbell Operating agreed to indemnify each Sponsor Manager, its affiliates and any of their respective employees, officers, directors and agents from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including legal fees) resulting from or arising out of (i) any material breach by Kimbell Operating of the applicable services agreement or (ii) the personal injury, death, property damage or liability of any member of the Partnership Service Group, any third party or any of their respective employees, officers, directors and agents arising from, connected with or under the applicable services agreement. The Sponsor Managers do not have corresponding indemnification obligations with respect to Kimbell Operating.

Other Services Agreements

Management Services. Kimbell Operating has services agreements with Nail Bay Royalties and Duncan Management (collectively, the “Non-Sponsor Managers”), which are entities controlled by Benny D. Duncan, who served on the Board of Directors during the year ended December 31, 2017 and a portion of the year ended December 31, 2018. Pursuant to these agreements, the Non-Sponsor Managers provide management, administrative and operational services to Kimbell Operating. These services include, with respect to the serviced properties: negotiating and executing leases, right of way agreements, pooling orders and similar agreements and orders; providing certain recordkeeping services; resolving title issues; collecting and disbursing payments and rendering related accounting and bookkeeping services; monitoring drilling and production activities; assisting in preparing certain federal and state tax forms; and providing certain additional accounting, title, human resources, regulatory compliance and other services.

Service Fees and Reimbursement. Under the services agreements with the Non-Sponsor Managers, Kimbell Operating paid to Nail Bay Royalties a monthly services fee of approximately $22,018, $27,306 and $29,736 for the years ended December 31, 2020, 2019 and 2018, respectively. Kimbell Operating paid to Duncan Management a monthly services fee of approximately $46,788, $41,525 and $43,500 for the years ended December 31, 2020, 2019 and 2018, respectively. In accordance with the amended services agreements, Kimbell Operating will pay to Nail Bay Royalties and Duncan Management a monthly services fee of approximately $25,110 and $45,707, respectively, for the period from January 1, 2021 to December 31, 2021 upon the approval of the Board of Directors. These amounts represent an estimated allocation of all projected costs to be incurred by such Non-Sponsor Manager in providing services to Kimbell Operating for the respective year. Subject to the approval of the Board of Directors, the monthly services fee will be adjusted 124

Table of Contents (i) annually, (ii) in the event of any sale of serviced properties or (iii) in the event of the provision of any additional services by the Non-Sponsor Manager. In addition, Kimbell Operating is required to reimburse each Non-Sponsor Manager for all other reasonable costs and expenses (including, but not limited to, third-party expenses and expenditures) that such Non-Sponsor Manager incurs on behalf of Kimbell Operating in providing services. If Kimbell Operating terminates a services agreement for any reason other than the Non-Sponsor Manager’s default (as described below), then Kimbell Operating will also reimburse the applicable Non-Sponsor Manager for its reasonable costs and expenses incurred in connection with such termination.

Term and Termination. The initial term of the services agreements with the Non-Sponsor Managers is be five years, after which date they will continue on a year-to-year basis unless terminated by us or by the applicable Non-Sponsor Manager upon 90 days’ notice, except as otherwise stated below:

●	The applicable Non-Sponsor Manager may terminate its services agreement, or the provision of any service thereunder, upon at least 180 days’ notice to Kimbell Operating.
●	The applicable Non-Sponsor Manager may terminate its services agreement upon a default by Kimbell Operating, which includes (i) Kimbell Operating’s failure to perform any of its material obligations under the agreement, where such default continues unremedied for a period of 15 days after notice thereof, and (ii) the occurrence of certain events relating to the bankruptcy or insolvency of Kimbell Operating.
---	---
●	Kimbell Operating may terminate a services agreement upon a default by the applicable Non-Sponsor Manager, upon 15 days’ notice to such Non-Sponsor Manager. A Non-Sponsor Manager is in default upon the occurrence of any gross negligence or willful misconduct of such Sponsor Manager in performing services under its services agreement, which results in material harm to any member of the Partnership Service Group.
---	---
●	Kimbell Operating or the Non-Sponsor Manager may terminate the applicable services agreement upon the sale of all or substantially all of the properties serviced thereunder, upon at least 90 days’ notice to the other party.
---	---

Kimbell Operating’s only remedy for a Non-Sponsor Manager’s default under its services agreement is the termination of the applicable agreement as described in the third bullet point above.

Indemnification. Under the services agreements with the Non-Sponsor Managers, Kimbell Operating agreed to indemnify each Non-Sponsor Manager, its affiliates and any of their respective employees, officers, directors and agents from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including legal fees) resulting from or arising out of (i) any material breach by Kimbell Operating of the applicable services agreement or (ii) the personal injury, death, property damage or liability of any member of the Partnership Service Group, any third party or any of their respective employees, officers, directors and agents arising from, connected with or under the applicable services agreement. The Non-Sponsor Managers do not have corresponding indemnification obligations with respect to Kimbell Operating.

Limited Liability Company Agreement of Kimbell Holdings

Our Sponsors have entered into the limited liability company agreement of Kimbell Holdings. Kimbell Holdings is the sole member of our General Partner. Pursuant to Kimbell Holdings’ limited liability company agreement, for so long as Messrs. Fortson, R. Ravnaas, Taylor and Wynne (or their designated successors) serve as directors of Kimbell Holdings, such persons will also serve as directors of our General Partner.

Other Transactions and Relationships with Related Persons

Family members of certain of our General Partner’s executive officers and directors serve as officers or employees of our General Partner and Kimbell Operating. Rand P. Ravnaas, the son of Robert D. Ravnaas and the brother of R. Davis Ravnaas, serves as Vice President—Business Development of our General Partner and Kimbell Operating, and he is a partial owner of certain of the Contributing Parties. In addition, Peter Alcorn, the son-in-law of Mitch Wynne, serves as 125

Table of Contents Vice President—Land of our General Partner and Kimbell Operating, and he is a partial owner of certain of the Contributing Parties. Each of these family members will participate in the LTIP and receive compensation comprising a base salary and bonuses commensurate with other similarly-situated employees.

John Wynne, the son of Mitch S. Wynne, acts as the Partnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne derived a commission of approximately $20,160 for the year ended December 31, 2020 and approximately $18,900 for the years ended December 31, 2019 and 2018 for the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $440,160, $350,000 and $320,000 for the years ended December 31, 2020, 2019 and 2018, respectively.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

The Board of Directors has adopted policies for the review, approval and ratification of transactions with related persons. The Board of Directors has adopted a written code of business conduct and ethics, under which a director is expected to bring to the attention of our chief executive officer or the Board of Directors any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our General Partner on the other. The resolution of any conflict or potential conflict should, at the discretion of the Board of Directors in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our General Partner or its affiliates, including our Sponsors or their respective affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the Board of Directors in accordance with the provisions of our partnership agreement. At the discretion of the Board of Directors in light of the circumstances, the resolution may be determined by the Board of Directors in its entirety or by the conflicts committee.

Under our code of business conduct and ethics, executive officers are required to avoid conflicts of interest unless approved by the Board of Directors.

The code of business conduct and ethics described above was adopted in connection with the closing of our IPO, and as a result, certain of the transactions described above were not reviewed according to such procedures.

Director Independence

Because we are a publicly traded partnership, the NYSE does not require our Board of Directors to have a majority of independent directors. For a discussion of the independence of our Board of Directors, please read “Item 10. Directors, Executive Officers and Corporate Governance.”

​

Item 14. Principal Accounting Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The Audit Committee’s charter requires the Audit Committee to approve in advance all audit and non-audit services to be provided by Grant Thornton LLP. All services reported in the audit, audit-related, tax and all other fees categories below with respect to our annual reports for the years ended December 31, 2020, 2019 and 2018 were approved by the Audit Committee. The following table sets forth audit and non-audit fees we have paid to Grant Thornton LLP for the periods indicated (in thousands).

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Audit Fees (1)	​	$	691,569	​	$	543,439	​	$	514,181
Audit-Related Fees (2)	​		—	​		—	​		69,765
Tax Fees (3)	​		—	​		—	​		—
All Other Fees (4)	​		—	​		—	​		—
Total	​	$	691,569	​	$	543,439	​	$	583,946

126

Table of Contents

(1)	Audit fees relate to professional services rendered in connection with the audit of our Annual Report, quarterly review of our Quarterly Reports, and quarterly review of financial statements included in our Registration Statement on Form S-1 filed with the SEC.
(2)	Audit-related fees relate to assurance and related services that are reasonably related to the performance of the audit or review of our financial statements or that are traditionally performed by the independent auditor, such as employee benefit plan audits or agreed upon procedures required to comply with financial, accounting or regulatory reporting.
---	---
(3)	Tax fees relate to professional services rendered in connection with tax audits and tax consulting and planning services.
---	---
(4)	All other fees represent fees for services not classifiable under the other categories listed in the table above.
---	---

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

Our consolidated financial statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying notes, please read “Index to Financial Statements” on page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(a)(3) List of Exhibits

​

​ 127

Table of Contents ​

EXHIBIT INDEX

Exhibit<br><br>Number	​	Description
2.1^††^	—	Contribution, Conveyance, Assignment and Assumption Agreement, dated as of December 20, 2016, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Intermediate GP, LLC, Kimbell Intermediate Holdings, LLC, Kimbell Royalty Holdings, LLC, and the other parties named therein (incorporated by reference to Exhibit 2.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
2.2 ^††^	—	Securities Purchase Agreement, dated as of May 28, 2018, by and among Kimbell Royalty Partners, LP, Haymaker Minerals & Royalties, LLC and Haymaker Services, LLC (incorporated by reference to Exhibit 2.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on June 1, 2018)
2.3^††^	—	Securities Purchase Agreement, dated as of May 28, 2018, by and among Kimbell Royalty Partners, LP, Haymaker Resources, LP and Haymaker Services, LLC (incorporated by reference to Exhibit 2.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on June 1, 2018)
2.4^††^	—	Securities Purchase Agreement, dated as of February 6, 2019, by and among PEP I Holdings, LLC, PEP II Holdings, LLC, PEP III Holdings, LLC, Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 2.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 12, 2019)
2.5	—	Amendment No. 1 to Securities Purchase Agreement, dated as of March 25, 2019, by and among PEP I Holdings, LLC, PEP II Holdings, LLC, PEP III Holdings, LLC, Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 2.1 to Kimbell Royalty Partners, LP's Current Report on Form 8-K filed on March 26, 2019)
2.6^††^	—	Securities Purchase Agreement, dated as of January 9, 2020, among Springbok Energy Feeder Fund, LLC, NGP XI Mineral Holdings, LLC, Springbok Energy Feeder Fund A, LLC, Springbok Investments, LLC, Jasmine Interests, LLC, KLF Red Head Oil and Gas LLC, Fielding and Rita Claytor, Silver Spur Resources, LLC, Virginia Altick, Springbok Class B Vehicle, LP, Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on January 9, 2020)
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.2	—	Third Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on September 25, 2018)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.4	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
3.5	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on September 25, 2018)
4.1	—	Amended and Restated Registration Rights Agreement, dated as of March 25, 2019, by and among Kimbell Royalty Partners,  LP, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, Haymaker Minerals & Royalties, LLC, AP KRP Holdings, L.P., ATCF SPV, L.P., Zeus Investments, L.P., Apollo Kings Alley Credit SPV, L.P., Apollo Thunder Partners, L.P., AIE III Investments, L.P., Apollo Union Street SPV, L.P., Apollo Lincoln Private Credit Fund, L.P., Apollo SPN Investments I (Credit), LLC, AA Direct, L.P., PEP I Holdings, LLC, PEP II Holdings, LLC, PEP III Holdings, LLC, Cupola Royalty Direct, LLC, Kimbell Art Foundation and Rivercrest Capital Partners LP (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners,  LP’s Current Report on Form 8-K filed on March 26, 2019)

128

Table of Contents	4.2	—	Registration Rights Agreement, dated as of April 17, 2020, by and among Kimbell Royalty Partners, LP, Silver Spur Resources, LLC, SEP I Holdings, LLC, Springbok Energy Partners II Holdings, LLC (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on April 20, 2020)
4.3	—	Description of Common Units Representing Limited Partnership Interests (incorporated by reference to Exhibit 4.2 to Kimbell Royalty Partners, LP’s Form 10-K filed on February 28, 2020)
10.1^†^	—	Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 7, 2017)
10.2^†^	—	First Amendment to the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on September 25, 2018)
10.3^†^	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on May 11, 2017)
10.4^†^	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Director Unit Agreement (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Form 10-Q filed on August 14, 2017)
10.5^†^	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan 2018 Restricted Unit Agreement (incorporated by reference to Exhibit 10.4 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 9, 2018)
10.6	—	Credit Agreement, dated as of January 11, 2017, among Kimbell Royalty Partners, LP, the several lenders from time to time parties thereto and Frost Bank, as administrative agent and sole arranger (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Amendment No. 1 to Registration Statement on Form S-1 (File No. 333-215458) filed on January 17, 2017)
10.7	—	Commitment Letter, dated as of May 28, 2018, by and between Kimbell Royalty Partners, LP and Frost Bank, Wells Fargo Bank, National Association, Credit Suisse AG, Cayman Islands Branch, Wells Fargo Securities, LLC and Credit Suisse Loan Funding LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on June 1, 2018)
10.8	—	Amendment No. 1 to Credit Agreement, dated as of July 12, 2018, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Frost Bank, as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 18, 2018)
10.9	—	Total Commitment Increase Agreement, dated as of May 23, 2019, between Frost Bank, Kimbell Royalty Partners, LP and Frost Bank, as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed May 28, 2019)
10.10	—	Additional Lender Agreement, dated as of May 23, 2019, between Independent Bank, Kimbell Royalty Partners, LP and Frost Bank, as administrative agent (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed May 28, 2019)
10.11*^††^	—	Amendment No. 2 to Credit Agreement, dated as of December 8, 2020, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A, as administrative agent
10.12^†^	—	Management Services Agreement, dated February 8, 2017, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.13^†^	—	Amendment No. 1 to Management Services Agreement, dated December 10, 2018, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.10 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 12, 2019)
10.14^†^	—	Amendment No. 2 to Management Services Agreement, dated December 16, 2019, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.13 to Kimbell Royalty Partners, LP’s Form 10-K filed on February 28, 2020)	129

Table of Contents	10.15^†^	—	Management Services Agreement, dated February 8, 2017, by and between BJF Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.16^†^	—	Management Services Agreement, dated February 8, 2017, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.4 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.17^†^	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.11 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 9, 2018)
10.18^†^	—	Amendment No. 2 to Management Services Agreement, dated December 10, 2018, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.17 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 12, 2019)
10.19^†^	—	Amendment No. 3 to Management Services Agreement, dated December 16, 2019, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.18 to Kimbell Royalty Partners, LP’s Form 10-K filed on February 28, 2020)
10.20	—	Series A Preferred Unit Purchase Agreement, dated as of May 28, 2018, by and among Kimbell Royalty Partners, LP and AA Direct, L.P., AP KRP Holdings, L.P., AIE III Investments, L.P., Apollo Kings Alley Credit SPV, L.P., Apollo SPN Investments I (Credit), LLC, Apollo Thunder Partners, L.P., ATCF Subsidiary (DC), LLC, Apollo Union Street SPV, L.P., Zeus Strategic US Holdings, L.P. and Apollo Lincoln Private Credit Fund, L.P. (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on June 1, 2018)
10.21	—	Board Representation and Observation Agreement, dated as of July 12, 2018, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell GP Holdings, LLC, AA Direct, L.P., AP KRP Holdings, L.P., AIE III Investments, L.P., Apollo Kings Alley Credit SPV, L.P., Apollo SPN Investments I (Credit), LLC, Apollo Thunder Partners, L.P., ATCF SPV, L.P., Apollo Union Street SPV, L.P., Zeus Investments, L.P. and Apollo Lincoln Private Credit Fund, L.P. (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 18, 2018)
10.22	—	First Amendment to the Securities Purchase Agreements, dated as of July 11, 2018, by and among Haymaker Resources, LP, Haymaker Minerals & Royalties, LLC, Haymaker Services, LLC and Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 10.9 to Kimbell Royalty Partners, LP’s Quarterly Report on Form 10-Q filed on August 10, 2018)
10.23	—	Exchange Agreement, dated as of September 23, 2018, by and among Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, Kimbell Art Foundation, Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on September 25, 2018)
10.24^††^	—	Purchase and Sale Agreement, dated as of November 20, 2018, by and among Rivercrest Capital Partners LP, Kimbell Art Foundation, Cupola Royalty Direct, LLC, Rivercrest Royalties Holdings II, LLC, Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on November 23, 2018)
10.25^††^	—	Securities Purchase Agreement, dated as of January 9, 2020, among Springbok Energy Partners II Holdings, LLC, Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on January 9, 2020)
10.26^††^	—	First Amendment to Securities Purchase Agreement, dated as of April 17, 2020, among NGP XI Mineral Holdings, LLC, Springbok Investment Management, LP, SEP I Holdings, LLC, Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.3 to Kimbell Royalty Partners, LP’s Current Report on Form 10-Q filed on May 7, 2020)
21.1*	—	List of Subsidiaries of Kimbell Royalty Partners, LP
23.1*	—	Consent of Grant Thornton LLP
23.2*	—	Consent of Ryder Scott Company, L.P.	130

Table of Contents

31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350
99.1*	—	Report of Ryder Scott Company, L.P. as of December 31, 2020
101.INS*	—	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	—	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	—	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	—	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*      —Filed herewith.

**    —Furnished herewith.

†      —Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Annual Report pursuant to Item 15(b).

††—Certain schedules and similar attachments to this agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant hereby undertakes to furnish a supplemental copy of each such omitted schedule or similar attachment to SEC upon request.

Item 16. Form 10-K Summary

The Partnership has elected not to include summary information.

​ 131

Table of Contents SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

​	​	​
​		Kimbell Royalty Partners, LP
​	​
​	​	By:	Kimbell Royalty GP, LLC
​	​	​	its general partner
​	​	​
Date: February 25, 2021	​	By:	/s/ Robert D. Ravnaas
​	​	​	Name:	Robert D. Ravnaas
​	​	​	Title:	Chief Executive Officer and Chairman

​

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	****	Title	****	Date
​	​	​	​	​
/s/ Robert D. Ravnaas	​	Chairman of the Board of Directors and Chief	​	​
Robert D. Ravnaas	​	Executive Officer (Principal Executive Officer)	​	February 25, 2021
​	​	​	​	​
/s/ R. Davis Ravnaas	​	President and Chief Financial Officer (Principal	​	​
R. Davis Ravnaas	​	Financial Officer)	​	February 25, 2021
​	​	​	​	​
/s/ R. Blayne Rhynsburger	​	​	​	​
R. Blayne Rhynsburger	​	Controller (Principal Accounting Officer)	​	February 25, 2021
​	​	​	​	​
/s/ William H. Adams III	​	​	​	​
William H. Adams III	​	Director	​	February 25, 2021
​	​	​	​	​
/s/ Erik B. Daugbjerg	​	​	​	​
Erik B. Daugbjerg	​	Director	​	February 25, 2021
​	​	​	​	​
/s/ Ben J. Fortson	​	​	​	​
Ben J. Fortson	​	Director	​	February 25, 2021
​	​	​	​	​
/s/ T. Scott Martin	​	​	​	​
T. Scott Martin	​	Director	​	February 25, 2021
​	​	​	​	​
/s/ Craig Stone	​	​	​	​
Craig Stone	​	Director	​	February 25, 2021
​	​	​	​	​
/s/ Brett G. Taylor	​	​	​	​
Brett G. Taylor	​	Director	​	February 25, 2021
​	​	​	​	​
/s/ Mitch S. Wynne	​	​	​	​
Mitch S. Wynne	​	Director	​	February 25, 2021
​	​	​	​	​

​

​

​ 132

Table of Contents INDEX TO FINANCIAL STATEMENTS

​

2018	​
Report of Independent Registered Public Accounting Firm	F-2
​	​
Consolidated Balance Sheets at December 31, 2020 and 2019	F-3
​	​
Consolidated Statements of Operations for the Years Ended December 31, 2020, 2019 and 2018	F-4
​	​
Consolidated Statements of Changes in Unitholders’ Equity for the Years Ended December 31, 2020, 2019 and 2018	F-5
​	​
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018	F-6
​	​
Notes to Consolidated Financial Statements	F-8

​

​ F-1

Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

​

​

Board of Directors of Kimbell Royalty GP, LLC and Unitholders of

Kimbell Royalty Partners, LP

​

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Kimbell Royalty Partners, LP (a Delaware limited partnership) and subsidiaries (collectively, the “Partnership”) as of December 31, 2020 and 2019, the related consolidated statements of operations, changes in unitholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2015.

​

Dallas, Texas

February 25, 2021

​ F-2

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

​	​	​	​	​	​	​
​	​	December 31,		​	December 31,
​	​	2020		​	2019
ASSETS	​	​	​	​	​	​
Current assets	​	​	​	​	​	​
Cash and cash equivalents	​	$	9,804,977	​	$	14,204,250
Oil, natural gas and NGL receivables	​	​	17,552,756	​	​	19,170,762
Commodity derivative assets	​	​	—	​	​	687,933
Accounts receivable and other current assets	​	​	973,956	​	​	76,868
Total current assets	​	​	28,331,689	​	​	34,139,813
Property and equipment, net	​	​	1,964,660	​	​	1,327,057
Investment in affiliate (equity method)	​	​	5,134,951	​	​	2,952,264
Oil and natural gas properties	​	​	​	​	​	​
Oil and natural gas properties, using full cost method of accounting ($225,681,626 and $275,041,784 excluded from depletion at December 31, 2020 and 2019, respectively)	​	​	1,149,095,232	​	​	1,033,355,017
Less: accumulated depreciation, depletion and impairment	​	​	(628,102,279)	​	​	(328,913,425)
Total oil and natural gas properties, net	​	​	520,992,953	​	​	704,441,592
Right-of-use assets, net	​	​	3,123,454	​	​	3,399,634
Commodity derivative assets	​	​	—	​	​	116,568
Loan origination costs, net	​	​	5,086,486	​	​	2,217,126
Total assets	​	$	564,634,193	​	$	748,594,054
​	​	​	​	​	​	​
LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY	​	​	​	​	​	​
Current liabilities	​	​	​	​	​	​
Accounts payable	​	$	888,735	​	$	1,207,736
Other current liabilities	​	​	4,765,161	​	​	4,231,579
Commodity derivative liabilities	​	​	3,113,178	​	​	—
Total current liabilities	​	​	8,767,074	​	​	5,439,315
Operating lease liabilities, excluding current portion	​	​	2,848,452	​	​	3,124,416
Commodity derivative liabilities	​	​	3,167,685	​	​	—
Long-term debt	​	​	171,550,142	​	​	100,135,477
Total liabilities	​	​	186,333,353	​	​	108,699,208
Commitments and contingencies (Note 16)	​	​	​	​	​	​
Mezzanine equity:	​	​	​	​	​	​
Series A preferred units (55,000 and 110,000 units issued and outstanding as of December 31, 2020 and 2019, respectively)	​	​	42,666,102	​	​	74,909,732
Unitholders' equity:	​	​	​	​	​	​
Common units (38,918,689 units issued and outstanding as of December 31, 2020 and 23,518,652 units issued and outstanding as of December 31, 2019)	​	​	257,593,307	​	​	282,549,841
Class B units (20,779,781 units issued and outstanding as of December 31, 2020 and 25,557,606 units issued and outstanding as of December 31, 2019)	​	​	1,038,989	​	​	1,277,880
Total unitholders' equity	​	​	258,632,296	​	​	283,827,721
Noncontrolling interest	​	​	77,002,442	​	​	281,157,393
Total equity	​	​	335,634,738	​	​	564,985,114
Total liabilities, mezzanine equity and unitholders' equity	​	$	564,634,193	​	$	748,594,054

​

The accompanying notes are an integral part of these consolidated financial statements.

​ F-3

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Revenue	​	​	​	​	​	​	​	​	​
Oil, natural gas and NGL revenues	​	$	92,586,685	​	$	107,480,446	​	$	65,713,112
Lease bonus and other income	​	​	345,771	​	​	2,477,145	​	​	1,213,550
(Loss) gain on commodity derivative instruments, net	​	​	(2,450,541)	​	​	(1,732,321)	​	​	3,331,548
Total revenues	​	​	90,481,915	​	​	108,225,270	​	​	70,258,210
Costs and expenses	​	​	​	​	​	​	​	​	​
Production and ad valorem taxes	​	​	6,389,231	​	​	7,719,949	​	​	4,399,667
Depreciation and depletion expense	​	​	47,988,796	​	​	52,118,367	​	​	25,213,043
Impairment of oil and natural gas properties	​	​	251,558,557	​	​	169,150,255	​	​	67,311,501
Marketing and other deductions	​	​	9,376,375	​	​	8,145,397	​	​	4,652,313
General and administrative expense	​	​	25,902,496	​	​	22,666,601	​	​	16,847,328
Total costs and expenses	​	​	341,215,455	​	​	259,800,569	​	​	118,423,852
Operating loss	​	​	(250,733,540)	​	​	(151,575,299)	​	​	(48,165,642)
Other income (expense)	​	​	​	​	​	​	​	​	​
Equity income in affiliate	​	​	763,988	​	​	80,481	​	​	—
Interest expense	​	​	(6,430,061)	​	​	(5,813,702)	​	​	(4,091,900)
Loss on extinguishment of debt	​	​	(476,350)	​	​	—	​	​	—
Other expense	​	​	(100,000)	​	​	—	​	​	—
Net loss before income taxes	​	​	(256,975,963)	​	​	(157,308,520)	​	​	(52,257,542)
(Benefit from) provision for income taxes	​	​	(885,193)	​	​	899,425	​	​	24,681
Net loss	​	​	(256,090,770)	​	​	(158,207,945)	​	​	(52,282,223)
Distribution and accretion on Series A preferred units	​	​	(7,810,588)	​	​	(13,878,336)	​	​	(6,310,040)
Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests	​	​	96,642,334	​	​	89,148,428	​	​	1,855,681
Distribution on Class B units	​	​	(91,869)	​	​	(94,429)	​	​	(30,967)
Net loss attributable to common units	​	$	(167,350,893)	​	$	(83,032,282)	​	$	(56,767,549)
​	​	​	​	​	​	​	​	​	​
Net loss attributable to common units	​	​	​	​	​	​	​	​	​
Basic	​	$	(4.85)	​	$	(3.92)	​	$	(3.08)
Diluted	​	$	(4.85)	​	$	(3.92)	​	$	(3.08)
Weighted average number of common units outstanding	​	​	​	​	​	​	​	​	​
Basic	​	​	34,530,398	​	​	21,192,714	​	​	18,442,234
Diluted	​	​	34,530,398	​	​	21,192,714	​	​	18,442,234

​

The accompanying notes are an integral part of these consolidated financial statements.

​ F-4

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	​	​	​	​		​	​	​	​	​		​	Noncontrolling		​	​
​	​	Common Units		****	Amount		​	Class B Units		****	Amount		​	Interest		​	Total
Balance at January 1, 2018	​	​	16,509,799	​	$	262,065,434	​	​	—	​	$	—	​	$	—	​	$	262,065,434
Common units issued for Haymaker Acquisition	​	​	10,000,000	​	​	235,400,000	​	​	—	​	​	—	​	​	—	​	​	235,400,000
Common units issued for equity offering	​	​	3,450,000	​	​	61,411,708	​	​	—	​	​	—	​	​	—	​	​	61,411,708
Class B units issued for Drop Down Acquisition	​	​	—	​	​	—	​	​	6,500,000	​	​	325,000	​	​	90,025,000	​	​	90,350,000
Recapitalization related to tax conversion	​	​	(12,953,258)	​	​	(209,591,880)	​	​	12,953,258	​	​	647,663	​	​	209,591,880	​	​	647,663
Unit-based compensation	​	​	1,049,946	​	​	3,170,299	​	​	—	​	​	—	​	​	—	​	​	3,170,299
Distributions to unitholders	​	​	—	​	​	(32,474,077)	​	​	—	​	​	—	​	​	(5,828,966)	​	​	(38,303,043)
Issuance of Series A preferred units	​	​	—	​	​	36,607,966	​	​	—	​	​	—	​	​	—	​	​	36,607,966
Distribution and accretion on Series A preferred units	​	​	—	​	​	(4,510,648)	​	​	—	​	​	—	​	​	(1,799,392)	​	​	(6,310,040)
Distribution on Class B units	​	​	—	​	​	(30,967)	​	​	—	​	​	—	​	​	—	​	​	(30,967)
Net loss	​	​	—	​	​	(52,225,934)	​	​	—	​	​	—	​	​	(56,289)	​	​	(52,282,223)
Balance at December 31, 2018	​	​	18,056,487	​	​	299,821,901	​	​	19,453,258	​	​	972,663	​	​	291,932,233	​	​	592,726,797
Class B units issued for acquisitions	​	​	—	​	​	—	​	​	11,569,348	​	​	578,467	​	​	207,734,725	​	​	208,313,192
Conversion of Class B units to common units	​	​	5,465,000	​	​	93,688,489	​	​	(5,465,000)	​	​	(273,250)	​	​	(93,688,489)	​	​	(273,250)
Restricted units used for tax withholding	​	​	(2,835)	​	​	(46,280)	​	​	—	​	​	—	​	​	—	​	​	(46,280)
Unit-based compensation	​	​	—	​	​	7,502,678	​	​	—	​	​	—	​	​	—	​	​	7,502,678
Distributions to unitholders	​	​	—	​	​	(35,384,665)	​	​	—	​	​	—	​	​	(35,672,648)	​	​	(71,057,313)
Distribution and accretion on Series A preferred units	​	​	—	​	​	(6,552,484)	​	​	—	​	​	—	​	​	(7,325,852)	​	​	(13,878,336)
Distribution on Class B units	​	​	—	​	​	(94,429)	​	​	—	​	​	—	​	​	—	​	​	(94,429)
Net loss	​	​	—	​	​	(76,385,369)	​	​	—	​	​	—	​	​	(81,822,576)	​	​	(158,207,945)
Balance at December 31, 2019	​	​	23,518,652	​	​	282,549,841	​	​	25,557,606	​	​	1,277,880	​	​	281,157,393	​	​	564,985,114
Common units issued for equity offering	​	​	5,000,000	​	​	73,601,668	​	​	—	​	​	—	​	​	—	​	​	73,601,668
Units issued for Springbok Acquisition	​	​	2,224,358	​	​	13,257,174	​	​	2,497,134	​	​	124,857	​	​	14,758,062	​	​	28,140,093
Conversion of Class B units to common units	​	​	7,274,959	​	​	92,065,325	​	​	(7,274,959)	​	​	(363,748)	​	​	(92,065,325)	​	​	(363,748)
Redemption of Series A preferred units	​	​	—	​	​	(16,150,018)	​	​	—	​	​	—	​	​	(9,697,873)	​	​	(25,847,891)
Restricted units used for tax withholding	​	​	(29,181)	​	​	(273,244)	​	​	—	​	​	—	​	​	—	​	​	(273,244)
Forfeitures of restricted units	​	​	(16,737)	​	​	(127,934)	​	​	—	​	​	—	​	​	—	​	​	(127,934)
Unit-based compensation	​	​	946,638	​	​	9,535,000	​	​	—	​	​	—	​	​	—	​	​	9,535,000
Distributions to unitholders	​	​	—	​	​	(29,513,612)	​	​	—	​	​	—	​	​	(20,507,481)	​	​	(50,021,093)
Distribution and accretion on Series A preferred units	​	​	—	​	​	(4,946,646)	​	​	—	​	​	—	​	​	(2,863,942)	​	​	(7,810,588)
Distribution on Class B units	​	​	—	​	​	(91,869)	​	​	—	​	​	—	​	​	—	​	​	(91,869)
Net loss	​	​	—	​	​	(162,312,378)	​	​	—	​	​	—	​	​	(93,778,392)	​	​	(256,090,770)
Balance at December 31, 2020	​	​	38,918,689	​	$	257,593,307	​	​	20,779,781	​	$	1,038,989	​	$	77,002,442	​	$	335,634,738

​

The accompanying notes are an integral part of these consolidated financial statements. F-5

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020			2019		​	2018
CASH FLOWS FROM OPERATING ACTIVITIES	​	​	​	​	​	​	​	​	​
Net loss	​	$	(256,090,770)	​	$	(158,207,945)	​	$	(52,282,223)
Adjustments to reconcile net loss to net cash provided by operating activities:	​	​	​	​	​	​	​	​	​
Depreciation and depletion expense	​	​	47,988,796	​	​	52,118,367	​	​	25,213,043
Impairment of oil and natural gas properties	​	​	251,558,557	​	​	169,150,255	​	​	67,311,501
Amortization of right-of-use assets	​	​	276,180	​	​	154,525	​	​	—
Amortization of loan origination costs	​	​	1,108,685	​	​	1,050,278	​	​	466,002
Loss on extinguishment of debt	​	​	476,350	​	​	—	​	​	—
Equity income in affiliate	​	​	(763,988)	​	​	(80,481)	​	​	—
Cash distribution from affiliate	​	​	812,810	​	​	—	​	​	—
Forfeiture of restricted units	​	​	(127,934)	​	​	—	​	​	—
Unit-based compensation	​	​	9,261,756	​	​	7,502,678	​	​	3,170,299
Loss (gain) on commodity derivative instruments, net of settlements	​	​	7,085,364	​	​	3,423,445	​	​	(4,546,775)
Changes in operating assets and liabilities:	​	​	​	​	​	​	​	​	​
Oil, natural gas and NGL receivables	​	​	1,618,006	​	​	4,410,140	​	​	(7,041,371)
Accounts receivable and other current assets	​	​	(897,088)	​	​	(26,317)	​	​	186,122
Accounts payable	​	​	(319,001)	​	​	(125,387)	​	​	985,936
Other current liabilities	​	​	533,582	​	​	1,762,633	​	​	(259,554)
Operating lease liabilities	​	​	(275,964)	​	​	(429,743)	​	​	—
Net cash provided by operating activities	​	​	62,245,341	​	​	80,702,448	​	​	33,202,980
CASH FLOWS FROM INVESTING ACTIVITIES	​	​	​	​	​	​	​	​	​
Purchases of property and equipment	​	​	(996,102)	​	​	(1,032,105)	​	​	(403,699)
Proceeds from sale of oil and natural gas properties	​	​	—	​	​	—	​	​	10,576,595
Purchase of oil and natural gas properties	​	​	(87,600,123)	​	​	(11,686,570)	​	​	(211,101,058)
Investment in affiliate	​	​	(2,231,509)	​	​	(2,965,933)	​	​	—
Cash distribution from affiliate	​	​	—	​	​	94,150	​	​	—
Net cash used in investing activities	​	​	(90,827,734)	​	​	(15,590,458)	​	​	(200,928,162)
CASH FLOWS FROM FINANCING ACTIVITIES	​	​	​	​	​	​	​	​	​
Proceeds from the issuance of Series A preferred units, net of issuance costs	​	​	—	​	​	—	​	​	103,359,603
Proceeds from equity offering	​	​	73,601,668	​	​	—	​	​	61,411,708
Contributions from Class B unitholders	​	​	—	​	​	470,000	​	​	972,663
Redemption of Class B contributions on converted units	​	​	(363,748)	​	​	(273,250)	​	​	—
Issuance costs paid on Series A preferred units	​	​	—	​	​	(717,612)	​	​	—
Redemption on Series A preferred units	​	​	(61,089,600)	​	​	—	​	​	​
Distributions to common unitholders	​	​	(29,513,612)	​	​	(35,384,665)	​	​	(38,303,043)
Distribution to OpCo unitholders	​	​	(20,507,481)	​	​	(35,672,648)	​	​	—
Distribution and accretion on Series A preferred units	​	​	(4,812,509)	​	​	(7,700,000)	​	​	(2,630,834)
Distribution on Class B units	​	​	(91,869)	​	​	(94,429)	​	​	(12,953)
Borrowings on long-term debt	​	​	162,614,665	​	​	12,825,933	​	​	124,336,547
Repayments on long-term debt	​	​	(91,200,000)	​	​	—	​	​	(67,870,596)
Payment of loan origination costs	​	​	(4,454,394)	​	​	(88,777)	​	​	(3,389,421)
Restricted units used for tax withholding	​	​	—	​	​	(46,279)	​	​	—
Net cash provided by (used in) financing activities	​	​	24,183,120	​	​	(66,681,727)	​	​	177,873,674
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	​	​	(4,399,273)	​	​	(1,569,737)	​	​	10,148,492
CASH AND CASH EQUIVALENTS, beginning of period	​	​	14,204,250	​	​	15,773,987	​	​	5,625,495
CASH AND CASH EQUIVALENTS, end of period	​	$	9,804,977	​	$	14,204,250	​	$	15,773,987

​

The accompanying notes are an integral part of these consolidated financial statements.

​ F-6

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020			2019		​	2018
Supplemental cash flow information:	​	​	​	​	​	​	​	​	​
Cash paid for interest	​	$	5,346,892	​	$	5,181,650	​	$	3,285,387
Cash paid for taxes	​	$	—	​	$	801,669	​	$	—
Non-cash investing and financing activities:	​	​	​	​	​	​	​	​	​
Right-of-use assets obtained in exchange for operating lease liabilities	​	$	—	​	$	3,554,159	​	$	—
Units issued in exchange for oil and natural gas properties	​	$	28,140,092	​	$	207,843,194	​	$	325,425,000
Distribution to Series A preferred unitholders in accounts payable	​	$	—	​	$	981,837	​	$	981,837
Non-cash deemed distribution to Series A preferred units	​	$	2,998,079	​	$	6,178,336	​	$	2,697,369
Noncash effect of Series A preferred unit redemption	​	$	25,847,891	​	$	—	​	$	—
Distribution to Class B unitholders in accounts payable	​	$	—	​	$	—	​	$	18,014
Oil and natural gas property acquisition costs in accounts payable	​	$	—	​	$	2,042	​	$	—
Capital expenditures and consideration payable included in accounts payable and other liabilities	​	$	—	​	$	—	​	$	10,645

​

The accompanying notes are an integral part of these consolidated financial statements.

​

​ F-7

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

​

​

Unless the context otherwise requi res, references to “Kimbell Royalty Partners, LP,” “the Partnership,” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner.  References to “the Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership at the closing of its initial public offering (“IPO”).

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP is a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGL”) from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest.

Basis of Presentation

The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (‘‘GAAP’’). A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole. F-8

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Restructuring, Tax Election and Related Transactions

On July 24, 2018, the Partnership entered into a Recapitalization Agreement with Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC (collectively, the “Haymaker Holders”), the Kimbell Art Foundation, Haymaker Resources, LP, the General Partner and the Operating Company pursuant to which (a) the Partnership’s equity interest in the Operating Company was recapitalized into 13,886,204 newly issued common units of the Operating Company (“OpCo common units”) and 110,000 newly issued Series A Cumulative Convertible Preferred Units (“Series A preferred units”) in the Operating Company and (b) the 10,000,000 and 2,953,258 common units held by the Haymaker Holders and the Kimbell Art Foundation, respectively, were exchanged for (i) 10,000,000 and 2,953,258 newly issued Class B common units representing limited partner interests of the Partnership (“Class B units”), respectively, and (ii) 10,000,000 and 2,953,258 newly issued OpCo common units, respectively. The Class B units and OpCo common units are exchangeable together into an equal number of common units representing limited partner interests in the Partnership (“common units”).

In May 2018, the General Partner’s Board of Directors (the “Board of Directors”) unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election (the “Tax Election”). The Tax Election became effective on September 24, 2018.

For each Class B unit issued, five cents has been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B units are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units but prior to distributions on the common units.

Following the effectiveness of the Tax Election and the completion of the related transactions, the Partnership’s royalty and minerals business continues to be conducted through the Operating Company, which is taxed as a partnership for federal and state income tax purposes. The Operating Company passes income to the noncontrolling interest and the Partnership, which is treated as a corporation for federal and state income tax purposes. As of February 19, 2021, 65.2% of the OpCo common units were held by the Partnership and 34.8% were held by third parties.

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

The global spread of coronavirus (“COVID-19”) created significant volatility, uncertainty, and economic disruption during year ended 2020. On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, the Partnership’s oil, natural gas, and NGL operators and other parties with whom the Partnership has business relations, including a significant reduction in the global demand for oil and natural gas. This significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance has led to a significantly weaker outlook for oil and gas producers and is having a disruptive impact on the oil and natural gas industry.

The Partnership has modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the WHO and other governmental and regulatory authorities. In mid-March, the Partnership restricted access to its offices to only essential employees, and directed the remainder of its employees to work from home to the extent possible. Beginning in mid-May, the Partnership opened its offices to employees on a voluntary basis, with employees having the option to work from the office or from home. These restrictions have had minimal impact on the Partnership’s operations to date and have allowed the Partnership to maintain the engagement and connectivity of its personnel, as well as minimize the number of employees in the office. F-9

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on the Partnership’s business, cash flows, liquidity, financial condition and results of operations will depend on future developments, including, among others, the ultimate severity of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other third parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, valuation of commodity derivative financial instruments and equity-based compensation.

The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information.

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

Reclassification of Prior Period Presentation

Certain prior period amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on previously reported net income (loss), total cash flows from operations or working capital.

Cash and Cash Equivalents

The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.

Accounts Receivable

Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2020 and 2019, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs. F-10

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Derivative Financial Instruments

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions.

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statement of operations within gain (loss) on commodity derivative instruments.

Property and Equipment

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.

Oil and Natural Gas Properties

The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.

The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties.

The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2020, 2019 or 2018.

Due to the nature of the Partnership’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2020, 2019 or 2018. F-11

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Other Current Liabilities

Other current liabilities consist primarily of Series A preferred unit and Class B unit distributions, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short term operating lease liabilities.

Income Taxes

As discussed further in Note 1—Organization and Basis of Presentation, on May 28, 2018, the Partnership announced that the Board of Directors had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018.

Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership incurred de minimis amounts of income taxes during the years ended December 31, 2020, 2019 and 2018.

Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership had no uncertain tax positions at December 31, 2020, 2019 and 2018.

The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2020, 2019 and 2018, the Partnership did not recognize any interest or penalty expense related to uncertain tax positions.

The Partnership has filed all tax returns to date that are currently due.

Concentration of Credit Risk

The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations.

During the years ended December 31, 2020, 2019 and 2018, the Partnership’s top purchaser accounted for approximately 7.1%, 6.0% and 10%, respectively, of oil, natural gas and NGL sales revenue.

​

At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits.

Revenue from Contracts with Customers

Royalty income represents the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index. F-12

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Royalty income from oil, natural gas and NGL sales

The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and NGL. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

Transaction price allocated to remaining performance obligations

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s royalty income contracts.

Contract balances

Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for one to four months after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and NGL contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Fair Value Measurements

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements.

New Accounting Pronouncements

Recently Adopted Pronouncements

In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement.” This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. The Partnership adopted this update F-13

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

on January 1, 2020 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the year ended December 31, 2020.

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard replaced the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The Partnership adopted this update using the modified retrospective approach, effective January 1, 2020. The adoption of this update did not have a material impact on the Partnership’s results of operations for the year ended December 31, 2020.

​

Accounting Pronouncements Not Yet Adopted

In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In October 2020, the FASB issued ASU 2020-10, “Codification Improvements.” This update provides clarification and corrects unintended application of the guidance in various sections. This update is effective for financial statements issued for fiscal years beginning after December 15, 2020, including interim periods within that fiscal year. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

NOTE 3—ACQUISITIONS, JOINT VENTURES AND DIVESTITURES

Acquisitions

2020 Activity

On April 17, 2020, the Partnership completed the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”). The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, (ii) the issuance of 2,224,358 common units and (iii) the issuance of 2,497,134 OpCo common units and an equal number of Class B units. At the time of the Springbok Acquisition, the acreage acquired had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other leading basins.

2019 Activity

On March 25, 2019, the Partnership acquired all of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC that own oil and natural gas mineral and royalty interests (the “Phillips Acquisition”). The aggregate consideration for the Phillips Acquisition consisted of 9,400,000 OpCo common units and an equal number of Class B units. The assets acquired in the Phillips Acquisition consisted of approximately 866,528 gross acres and 12,210 net royalty acres.

On November 6, 2019, the Partnership acquired various mineral and royalty interests in Oklahoma for an aggregate purchase price of approximately $9.9 million. The Partnership funded the payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired consist of approximately 279,680 gross acres and 186 net royalty acres.

On December 12, 2019, the Partnership acquired certain mineral and royalty assets (the “Buckhorn Acquisition) from certain affiliates of Buckhorn Resources GP, LLC (collectively, the “Buckhorn Sellers”). The aggregate consideration F-14

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

for the Buckhorn Acquisition consisted of 2,169,348 OpCo common units and an equal number of Class B units. The assets acquired in the Buckhorn Acquisition consisted of approximately 86,005 gross acres and 405 net royalty acres.

2018 Activity

On July 12, 2018, the Partnership completed the acquisition of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (the “Haymaker Acquisition”) in a transaction valued at approximately $444.0 million. The purchase price for the Haymaker Acquisition was comprised of (i) net cash consideration of approximately $208.6 million and (ii) 10,000,000 common units of the Partnership. The Partnership funded the Cash Consideration with borrowings under the Amended Credit Agreement (as defined in Note 8—Long-term debt) and net proceeds from the Preferred Unit Transaction (as defined in Note 9—Preferred Units). The assets acquired in the Haymaker Acquisition consisted of approximately 5.4 million gross acres and 43,000 net royalty acres.

On December 20, 2018, the Partnership completed the acquisition (the “Dropdown”) of (i) certain overriding royalty, royalty and other mineral interests from Rivercrest Capital Partners LP, the Kimbell Art Foundation, and Cupola Royalty Direct, LLC, as well as all of the interests of a subsidiary of Rivercrest Royalties Holdings II, LLC in exchange for a total of 6,500,000 OpCo common units and an equal number of Class B units. The assets acquired in the Dropdown consisted of approximately 1.0 million gross acres and 16,700 net royalty acres.

Joint Ventures

On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed $15.0 million. The Joint Venture is managed by Springbok Operating Company, LLC. While certain members of Springbok Operating Company, LLC are affiliated with the entities acquired as part of the Springbok Acquisition, none of the assets held by the Joint Venture were included in the Springbok Acquisition. The purpose of the Joint Venture is to make direct or indirect investments in royalty, mineral and overriding royalty interests and similar non-cost bearing interests in oil and gas properties, excluding leasehold or working interests. The Partnership currently utilizes the equity method of accounting for its investment in the Joint Venture. As of December 31, 2020, the Partnership has paid approximately $5.2 million under its capital commitment.

Divestitures

In May 2018, the Partnership executed two purchase and sale agreements to sell a small portion of its Delaware Basin acreage for $10.6 million, which was recorded as a reduction in the full-cost pool, with no gain or loss recorded on the sale. At the time of the divestiture, the sales represented approximately 29 barrels of equivalent (“Boe”) per day of production, less than 0.8% of total production and 59 net royalty acres, approximately 0.08% of total net royalty acres.

NOTE 4—DERIVATIVES

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty.

At December 31, 2020, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The Partnership hedges its daily production based on the amount of debt and/or preferred equity as a percent of its enterprise value. As of December 31, 2020, these economic hedges constituted approximately 32% of daily oil and natural gas production. F-15

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.

The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. The Partnership records all derivative contracts at fair value. Changes in the fair values of the Partnership’s derivative instruments are recognized as gains or losses in the current period and are presented on a net basis in the accompanying consolidated statements of operations and consisted of the following:

​

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Beginning fair value of commodity derivative instruments	​	$	804,501	​	$	4,227,946	​	$	(318,829)
(Loss) gain on commodity derivative instruments	​	​	(2,450,541)	​	​	(1,732,321)	​	​	3,331,548
Net cash (received) paid on settlements of derivative instruments	​	​	(4,634,823)	​	​	(1,691,124)	​	​	1,215,227
Ending fair value of commodity derivative instruments	​	$	(6,280,863)	​	$	804,501	​	$	4,227,946

​

The following table presents the fair value of the Partnership’s derivative contracts as of December 31, 2020 and 2019:

​

​	​	​	​	​	​	​	​	​
​	​	​	​	December 31,		​	December 31,
Classification	​	Balance Sheet Location	​	2020		​	2019
Assets:	​	​	​	​	​	​	​	​
Current asset	​	Commodity derivative assets	​	$	—	​	$	687,933
Long-term asset	​	Commodity derivative assets	​	​	—	​	​	116,568
Liabilities:	​	​	​	​	​	​	​	​
Current liability	​	Commodity derivative liabilities	​	​	(3,113,178)	​	​	—
Long-term liability	​	Commodity derivative liabilities	​	​	(3,167,685)	​	​	—
​	​	​	​	$	(6,280,863)	​	$	804,501

​

At December 31, 2020, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

​	​	​	​	​	​	​	​	​	​	​	​
​	​	Notional	​	Weighted Average		​	Range (per Bbl)
​	​	Volumes (Bbl)	​	Fixed Price (per Bbl)		​	Low		​	High
December 2020	​	45,477	​	$	41.61	​	$	33.87	​	$	50.65
January 2021 - December 2021	​	535,455	​	$	44.26	​	$	34.95	​	$	56.10
January 2022 - December 2022	​	500,552	​	$	41.86	​	$	35.65	​	$	46.00

Natural Gas Price Swaps

​	​	​	​	​	​	​	​	​	​	​	​
​	​	Notional	​	Weighted Average		​	Range (per MMBtu)
​	​	Volumes (MMBtu)	​	Fixed Price (per MMBtu)		​	Low		​	High
January 2021 - December 2021	​	6,886,090	​	$	2.54	​	$	2.33	​	$	2.85
January 2022 - December 2022	​	6,357,449	​	$	2.46	​	$	2.23	​	$	2.70

​

​ F-16

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

NOTE 5—FAIR VALUE MEASUREMENTS

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the consolidated balance sheets approximated fair value at December 31, 2020 and 2019 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below.

●	Level 1—Unadjusted quoted market prices for identical assets or liabilities in active markets.
●	Level 2—Quoted prices for similar assets or liabilities in non-active markets, or inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the asset or liability.
---	---
●	Level 3— Measurement based on prices or valuations models that require inputs that are both unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).
---	---

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the years ended December 31, 2020 and 2019.

The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets.

The following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy:

​

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	Fair Value Measurements Using								​	​	​	​	​	​
​	​	Level 1		​	Level 2		​	Level 3		​	Effect of Counterparty Netting		​	Total
December 31, 2020	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Liabilities	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Commodity derivative contracts	​	$	—	​	$	(6,280,863)	​	$	—	​	$	—	​	$	(6,280,863)
December 31, 2019	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Assets	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Commodity derivative contracts	​	$	—	​	$	804,501	​	$	—	​	$	—	​	$	804,501

​

​ F-17

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

NOTE 6 — OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

​

​	​	​	​	​	​	​
​		December 31,		​	December 31,
​	​	2020		​	2019
Oil and natural gas properties	​	​	​	​	​	​
Proved properties	​	$	923,413,606	​	$	758,313,233
Unevaluated properties	​	​	225,681,626	​	​	275,041,784
Less: accumulated depreciation, depletion and impairment	​	​	(628,102,279)	​	​	(328,913,425)
Total oil and natural gas properties	​	$	520,992,953	​	$	704,441,592

​

Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made.

The Partnership assesses all unevaluated properties on periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test. The Partnership transferred $48.6 million to the full cost pool in the first quarter of 2020 as a result of this impairment assessment. There were no additional impairments to unevaluated properties for the remainder of 2020.

After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated proved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties for the three months ended March 31, 2020. In addition, the Partnership no longer intends to book PUD reserves.

As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $251.6 million during the year ended December 31, 2020, including the $48.6 million in unevaluated properties transferred to the full cost pool as mentioned above. The impairment can primarily be attributed to the decline in the 12-month average price of oil and natural gas as a result of the continued impact of the external factors mentioned above.

The Partnership recorded an impairment on its oil and natural gas properties of $169.2 million and $67.3 million during the years ended December 31, 2019 and 2018, respectively, as a result of its quarterly full cost ceiling analysis and a decline in the 12-month average price of oil and natural gas.

NOTE 7—LEASES

Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying consolidated balance sheets. Short F-18

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of December 31, 2020 is 8.35 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the year ended December 31, 2020.

Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018. The total operating lease expense recorded for the years ended December 31, 2020, 2019 and 2018 was $0.5 million, $0.3 million and $0.1 million, respectively.

Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations. In July 2019, the Partnership became the lessee in several other related lease agreements for additional office space. In addition, the Partnership was involved in the construction and design of the underlying assets.

Future minimum lease commitments as of December 31, 2020 were as follows:

​

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	Total		​	2021		​	2022		​	2023		​	2024		​	2025		​	Thereafter
Operating leases	​	$	4,149,712	​	$	480,025	​	$	478,837	​	$	480,579	​	$	486,323	​	$	497,033	​	$	1,726,915
Less: Imputed Interest	​		(1,024,463)	​		​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Total	​	$	3,125,249	​		​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​

​

NOTE 8—LONG-TERM DEBT

On January 11, 2017, the Partnership entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018, in connection with the Haymaker Acquisition, the Partnership entered into an amendment (the “First Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement (the 2017 Credit Agreement as amended by the First Credit Agreement Amendment, the “2018 Amended Credit Agreement”), by and among the Partnership, certain subsidiaries of the Partnership, as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto.

The First Credit Agreement Amendment amended the 2017 Credit Agreement to provide for, among other things, (i) the addition of the subsidiaries the Partnership acquired in the Haymaker Acquisition, as well as the Operating Company, as guarantors under the 2018 Amended Credit Agreement, (ii) limitations on the Partnership’s ability to incur certain debt or issue preferred equity, (iii) limitations on redemptions of the Series A preferred units and the ability of the Partnership and the restricted subsidiaries of the Partnership to make distributions and other restricted payments, in each case, unless certain conditions are satisfied, (iv) increased limitations on the Partnership’s ability to dispose of certain assets or encumber certain assets, (v) a decrease in the applicable margin under the 2017 Credit Agreement, which varies based upon the level of borrowing base usage, by 0.25% for each applicable level as set forth in the 2018 Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ABR Loans (as defined in the 2018 Amended Credit Agreement) and 2.00% to 3.00% in the case of LIBOR Loans (as defined in the 2018 Amended Credit Agreement) and (vi) the addition of certain restrictions on the Partnership’s and the Operating Company’s ability to take certain actions or amend their organizational documents.

On December 8, 2020, the Partnership entered into Amendment No. 2 (the “Second Credit Agreement Amendment”) to the 2018 Amended Credit Agreement (the 2018 Amended Credit Agreement as amended by the Second Credit Agreement Amendment, the “Amended Credit Agreement”), with certain subsidiaries of the Partnership, as F-19

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

guarantors, the lenders party thereto, Citibank, N.A. (“Citi”), as administrative agent and Frost Bank (“Frost”), as resigning administrative agent.

The Second Credit Agreement Amendment amends the 2018 Amended Credit Agreement to, among other things, (i) increase commitments under the Amended Credit Agreement’s senior secured revolving credit facility from $225.0 million to $265.0 million, the availability of which will equal the lesser of the aggregate maximum elected commitments of the lenders up to $500.0 million, subject to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders, and the borrowing base, (ii) extend the maturity date under the 2018 Amended Credit Agreement from February 8, 2022 to June 7, 2024, (iii) reflect the change in administrative agent from Frost to Citi under the Amended Credit Agreement, (iv) increase the applicable margin under the 2018 Amended Credit Agreement, which varies based upon the level of borrowing base usage, by 1.00% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 2.00% to 3.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 3.00% to 4.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement), (v) provide for a LIBOR (as defined in the Amended Credit Agreement) floor of 0.25%, (vi) modify the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) financial covenant to permit the numerator of the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) to be calculated as Total Debt (as defined in the Amended Credit Agreement) minus up to $25 million in unrestricted cash held by the Partnership and its restricted subsidiaries and to decreases the maximum permitted Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) from

4.0

to 1.0 to

3.5

to 1.0, and (vii) modify the conditions permitting restricted distributions to holders of Kimbell Common Units (as defined in the Amended Credit Agreement) including, among other things, a limitation on such distributions to not be in excess of the Partnership’s Projected Cash Available For Distribution (as defined in the Amended Credit Agreement). In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year, beginning May 1, 2021, based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the Partnership’s wholly owned subsidiaries. The Amended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units and OpCo common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The Amended Credit Agreement also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) of not more than

3.5

to 1.0; and (ii) a ratio of current assets to current liabilities of not less than

1.0

to 1.0. The Amended Credit Agreement also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change of control. In connection with the Second Credit Agreement Amendment, the Partnership recorded a loss on extinguishment of debt of $0.5 million as a result of writing off all unamortized loan origination costs associated with the lenders to the 2017 Credit Agreement and the 2018 Amended Credit Agreement that did not participate in the Second Credit Agreement Amendment.

During the year ended December 31, 2020, the Partnership borrowed an additional $162.6 million under the secured revolving credit facility and repaid approximately $91.2 million of the outstanding borrowings. As of December 31, 2020, the Partnership’s outstanding balance was $171.6 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2020.

As of December 31, 2020, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 3.50% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.50%. For the year ended December 31, 2020, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.31%. F-20

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

NOTE 9—PREFERRED UNITS

In July 2018, the Partnership completed the private placement of 110,000 Series A preferred units to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $110.0 million (the “Preferred Unit Transaction”). Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the third anniversary of the original issuance date, and board appointment rights beginning the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units.

The Series A preferred units are convertible by the Series A Purchasers after two years at a 30% discount to the issue price, subject to certain conditions. The Partnership may redeem the Series A preferred units at any time. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.

For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the July 12, 2018 (the “Series A Issuance Date”), a 13.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary of the Series A Issuance Date, a 14.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the Series A Issuance Date, a 15.0% internal rate of return with respect to the Series A preferred units.

On February 12, 2020, the Partnership completed the redemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than 50% of the carrying value of the Series A preferred units as of the redemption date and 50% of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $5.7 million was taken directly to unitholders’ equity and non-controlling interest during the year ended December 31, 2020.

The following table summarizes the changes in the number of the Series A preferred units:

​

​	​	​
​	​	Series A
​	​	Preferred Units
Balance at December 31, 2019	​	110,000
Redemption of Series A preferred units	​	(55,000)
Balance at December 31, 2020	​	55,000

​

​

​

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. At December 31, 2020, the Partnership had a total of 38,918,689 common units issued and outstanding and 20,779,781 Class B units outstanding.

In January 2020, the Partnership completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 million (the “2020 Equity Offering”). The Partnership used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. In F-21

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units pursuant to the exercise of the underwriters’ option to purchase additional common units. The Partnership did not receive any proceeds from the sale of the common units by the selling unitholders.

The following table summarizes the changes in the number of the Partnership’s common units:

​

​	​	​
​	​	Common Units
Balance at December 31, 2019	​	23,518,652
Common units issued for equity offering	​	5,000,000
Common units issued for Springbok Acquisition	​	2,224,358
Conversion of Class B units	​	7,274,959
Common units issued under the LTIP (1)	​	946,638
Restricted units used for tax withholding	​	(29,181)
Forfeiture of restricted units	​	(16,737)
Balance at December 31, 2020	​	38,918,689
(1)	Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on February 28, 2020.
---	---

The following table presents information regarding the common unit cash distributions approved by the Board of Directors for the periods presented:

​

​	​	​	​	​	​	​	​	​	​
​	​	Amount per		​	Date	​	Unitholder	​	Payment
​	​	Common Unit		​	Declared	​	Record Date	​	Date
Q1 2020	​	$	0.17	​	April 24, 2020	​	May 4, 2020	​	May 11, 2020
Q2 2020	​	$	0.13	​	July 24, 2020	​	August 3, 2020	​	August 10, 2020
Q3 2020	​	$	0.19	​	October 23, 2020	​	November 2, 2020	​	November 9, 2020
Q4 2020	​	$	0.19	​	January 22, 2021	​	February 1, 2021	​	February 8, 2021
​	​	​	​	​	​	​	​	​	​
Q1 2019	​	$	0.37	​	April 26, 2019	​	May 6, 2019	​	May 13, 2019
Q2 2019	​	$	0.39	​	July 26, 2019	​	August 5, 2019	​	August 12, 2019
Q3 2019	​	$	0.42	​	October 25, 2019	​	November 4, 2019	​	November 11, 2019
Q4 2019	​	$	0.38	​	January 24, 2020	​	February 3, 2020	​	February 10, 2020
​	​	​	​	​	​	​	​	​	​
Q1 2018	​	$	0.42	​	April 27, 2018	​	May 7, 2018	​	May 14, 2018
Q2 2018	​	$	0.43	​	July 27, 2018	​	August 6, 2018	​	August 13, 2018
Q3 2018	​	$	0.45	​	October 26, 2018	​	November 5, 2018	​	November 12, 2018
Q4 2018	​	$	0.40	​	January 25, 2019	​	February 4, 2019	​	February 11, 2019

​

The following table summarizes the changes in the number of the Partnership’s Class B units:

​

​	​	​
​	​	Class B Units
Balance at December 31, 2019	​	25,557,606
Conversion of Class B units	​	(7,274,959)
Class B units issued for Springbok Acquisition	​	2,497,134
Balance at December 31, 2020	​	20,779,781

​

Holders of the Class B units, are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units but prior to distributions on the common units and OpCo common units.

The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership. F-22

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

NOTE 11—NET LOSS PER COMMON UNIT

Basic loss per common unit is calculated by dividing net loss attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net loss per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s LTIP for its employees, directors and consultants, potential conversion of Class B units.

The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted loss per common unit:

​

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Net loss attributable to common units	​	$	(167,350,893)	​	$	(83,032,282)	​	$	(56,767,549)
​	​	​	​	​	​	​	​	​	​
Weighted average number of common units outstanding:	​	​	​	​	​	​	​	​	​
Basic	​	​	34,530,398	​	​	21,192,714	​	​	18,442,234
Effect of dilutive securities:	​	​	​	​	​	​	​	​	​
Series A preferred units	​	​	—	​	​	—	​	​	—
Class B units	​	​	—	​	​	—	​	​	—
Restricted units	​	​	—	​	​	—	​	​	—
Diluted	​	​	34,530,398	​	​	21,192,714	​	​	18,442,234
​	​	​	​	​	​	​	​	​	​
Net loss attributable to common units	​	​	​	​	​	​	​	​	​
Basic	​	$	(4.85)	​	$	(3.92)	​	$	(3.08)
Diluted	​	$	(4.85)	​	$	(3.92)	​	$	(3.08)

​

The calculation of diluted net loss per share for the years ended December 31, 2020, 2019 and 2018 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 1,276,546, 739,479 and 1,157,924 shares of unvested restricted units, respectively, because their inclusion in the calculation would be anti-dilutive.

NOTE 12—UNIT-BASED COMPENSATION

On September 23, 2018, the General Partner entered into the First Amendment to the LTIP, which increased the number of common units eligible for issuance under the LTIP by 2,500,000 common units for a total of 4,541,600 common units. The Partnership’s LTIP authorizes grants to its employees, directors and consultants. The restricted units issued under the Partnership’s LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants is treated in the same manner as that of the employees and directors. F-23

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Distributions related to the restricted units are paid concurrently with the Partnership’s distributions for common units. The fair value of the Partnership’s restricted units issued under the LTIP to the Partnership’s employees, directors and consultants is determined by utilizing the market value of the Partnership’s common units on the respective grant date. The following table presents a summary of the Partnership’s unvested restricted units.

​

​	​	​	​	​	​	​	​
​	​	​	​	Weighted		****	Weighted
​	​	​	​	Average		​	Average
​	​	​	​	Grant-Date		​	Remaining
​	​	​	​	Fair Value		​	Contractual
​	​	Units	​	per Unit		​	Term
Unvested at December 31, 2019	​	739,479	​	$	18.059		1.335 years
Awarded	​	946,638	​	​	11.540	​	—
Vested	​	(392,834)	​	​	17.004	​	—
Forfeited	​	(16,737)	​	​	13.918	​	—
Unvested at December 31, 2020	​	1,276,546	​	$	13.604		1.788 years

​

​

NOTE 13—INCOME TAXES

As discussed further in Note 1, on May 28, 2018, the Board of Directors unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items.

On March 27, 2020, the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act “) was enacted. The CARES Act is an economic stimulus package designed to aid in offsetting the economic damage caused by the ongoing COVID-19 pandemic and includes various changes to U.S. income tax regulations. The CARES Act permits the carryback of certain net operating losses that under previous law were only available to be carried forward. As a result, the Partnership expects to receive an income tax refund of $0.2 million due to requested carrybacks of net operating losses to the 2018 calendar tax year.

​

The Partnership’s effective income tax rate was 0.34% for the year ended December 31, 2020. The Partnership incurred a book loss for the current year and is recording a current income tax benefit of $0.9 million due to the CARES Act carryback provisions and a change in estimates because of filing its 2019 federal and state income tax returns.

​

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Current	​	​	​	​	​	​	​	​
Federal	​	$	(812,913)	​	$	812,913	​	$	—
State	​	​	(72,280)	​	​	86,512	​	​	24,681
Total Current	​	​	(885,193)	​	​	899,425	​	​	24,681
Deferred	​	​	​	​	​	​	​	​	​
Federal	​	​	—	​	​	—	​	​	—
State	​	​	—	​	​	—	​	​	—
Total Deferred	​	​	—	​	​	—	​	​	—
(Benefit from) provision for income taxes	​	$	(885,193)	​	$	899,425	​	$	24,681

​

The Partnership’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items:

​

​	​	​	​	​	​	​	​	​	​	​	​	​

F-24

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

​	​	Year Ended December 31,
​	​	2020			​	2019			​	2018
Net loss before taxes	​	$	(256,975,963)	​	​	$	(157,308,520)	​	​	$	(52,257,542)	​
Statutory rate	​	​	21	%	​	​	21	%	​	​	21	%
Income tax benefit computed at statutory rate	​	​	(53,964,952)	​	​	​	(33,034,789)	​	​	​	(10,974,084)	​
Reconciling items:	​	​	​	​	​	​	​	​	​	​	​	​
State income taxes	​	​	(72,280)	​	​	​	72,280	​	​	​	(70,441)	​
Texas margins tax	​	​	—	​	​	​	—	​	​	​	24,681	​
Change in tax status	​	​	—	​	​	​	—	​	​	​	(20,038,820)	​
Non-controlling interest	​	​	20,294,890	​	​	​	18,721,170	​	​	​	(360,082)	​
Income at OpCo	​	​	33,670,062	​	​	​	15,130,685	​	​	​	10,598,375	​
Change in valuation allowance - federal	​	​	(749,866)	​	​	​	80,520	​	​	​	20,771,214	​
Change in valuation allowance - state	​	​	168,393	​	​	​	(70,441)	​	​	​	70,441	​
Other, net	​	​	(231,440)	​	​	​	—	​	​	​	3,397	​
(Benefit from) provision for income taxes	​	$	(885,193)	​	​	$	899,425	​	​	$	24,681	​

​

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Partnership’s deferred taxes are detailed in the table below.

​

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Deferred tax asset	​	​		​	​		​	​
Outside basis in OpCo	​	$	17,624,909	​	$	20,050,732	​	$	21,036,307
Federal tax loss carryforwards	​	​	1,675,957	​	​	—	​	​	622,775
State tax loss carryforwards	​	​	238,559	​	​	—	​	​	70,441
Deferred tax asset	​	​	19,539,425	​	​	20,050,732	​	​	21,729,523
Valuation allowance	​	​	(19,539,425)	​	​	(20,050,732)	​	​	(20,841,655)
Net deferred tax asset	​	$	—	​	$	—	​	$	887,868
Deferred tax liability	​	​	​	​	​	​	​	​	​
Derivative instruments and other	​	​	—	​	​	—	​	​	887,868
Net deferred tax liability	​	$	—	​	$	—	​	$	887,868
Reflected in the accompanying balance sheets as:	​	​	​	​	​	​	​	​	​
Net deferred tax asset	​	$	—	​	$	—	​	$	—
Net deferred tax liability	​	$	—	​	$	—	​	$	—

​

The tax years ended December 31, 2017 through 2020 remain open to examination under the applicable statute of limitations in the United States and other jurisdictions in which the Partnership and its subsidiaries file income tax returns. In some instances, state statutes of limitations are longer than those under United States federal tax law. The Partnership believes that it is more likely than not that the benefit from the outside basis differences in the Partnership’s investment in the Operating Company and its federal and state loss carryforward will not be realized. In recognition of this risk, the Partnership has provided a valuation allowance of $19.5 million on the deferred tax assets.

As of December 31, 2020, the Partnership has not recorded a reserve for any uncertain tax positions.

NOTE 14—RELATED PARTY TRANSACTIONS

The Partnership has entered into a management services agreement with Kimbell Operating, which has entered into separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”), pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the F-25

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

amount of cash available for distribution on common units to the Partnership’s unitholders. During the year ended December 31, 2020, no monthly services fee was paid to BJF Royalties. During the year ended December 31, 2020, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $120,000, $264,216 and $561,456, respectively. Certain consultants who provide services under the management services agreements are also granted restricted units under the Partnership’s LTIP.

John Wynne, the son of Mitch S. Wynne, acts as the Partnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne derived a commission of approximately $20,160 for the year ended December 31, 2020 and approximately $18,900 for the years ended December 31, 2019 and 2018 for the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $440,160, $350,000 and $320,000 for the years ended December 31, 2020, 2019 and 2018, respectively.

NOTE 15—ADMINISTRATIVE SERVICES

Management Services Agreement

The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business efforts. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the Board of Directors and their affiliated entities. See Note 14―Related Party Transactions.

Transition Services Agreement

In connection with the Springbok Acquisition, the Partnership entered into a Transition Services Agreement (the “Transition Services Agreement”) with Springbok Investment Management, LP (“SIM”). Pursuant to the Transition Services Agreement, SIM provided certain administrative services and accounting assistance on a transitional basis for total compensation of $300,000 from April 17, 2020 through June 17, 2020, at which point, the Transition Services Agreement terminated.

NOTE 16—COMMITMENTS AND CONTINGENCIES

Leases

The Partnership leases certain office space under non-cancelable operating leases with fixed payment terms and will terminate in June 2029. The Partnership recognizes operating lease expense on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statement of operations for the years ended December 31, 2020 and 2019. The total operating lease expense recorded for the years ended December 31, 2020, 2019 and 2018 was approximately $0.5 million, $0.3 million and $0.1 million, respectively. F-26

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2020:

​

​	​	​	​
Years Ending December 31,		****	​
2021	​	$	480,025
2022	​		478,837
2023	​		480,579
2024	​		486,323
2025	​	​	497,033
Thereafter	​	​	1,726,915
Total	​	$	4,149,712

​

Litigation

Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity as of December 31, 2020.

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to December 31, 2020 in the preparation of its consolidated financial statements.

Interest Rate Swaps

On January 27, 2021, the Partnership entered into an interest rate swap with Citi, which fixed the interest rate on $150.0 million of notional, or approximately 87% of the Partnership’s outstanding balance on its secured revolving credit facility, at approximately 3.9% for a period ending January 29, 2024.

Distributions

On February 3, 2021, the Partnership paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended December 31, 2020.

On February 4, 2021, the Partnership paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of $20,780 for the quarter ended December 31, 2020.

On January 22, 2021, the Board of Directors declared a quarterly cash distribution of $0.19 per common unit for the quarter ended December 31, 2020. The distribution was paid on February 8, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on February 1, 2021.

On February 25, 2021, the Conflicts and Compensation Committee of the Board of Directors approved short-term incentive cash bonuses for executive officers of $2.2 million and the issuance of 936,567 restricted units to its employees, directors and consultants.

NOTE 18—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The Partnership has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Partnership’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities. F-27

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

​

​	​	​	​	​	​	​
​	​	December 31,		​	December 31,
​		2020		​	2019
Oil, natural gas and NGL interests	​	​	​	​	​	​
Proved properties	​	$	923,413,606	​	$	758,313,233
Unevaluated properties	​	​	225,681,626	​	​	275,041,784
Total oil, natural gas and NGL interests	​		1,149,095,232	​		1,033,355,017
Accumulated depreciation, depletion, accretion and impairment	​		(628,102,279)	​		(328,913,425)
Net oil, natural gas and NGL interests capitalized	​	$	520,992,953	​	$	704,441,592

​

Costs incurred in oil and natural gas activities

Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows:

​

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Acquisition costs	​	​	​	​	​	​	​	​	​
Proved properties	​	$	41,476,733	​	$	104,199,579	​	$	243,227,632
Unevaluated properties	​	​	74,263,481	​	​	110,050,000	​	​	288,334,110
Total	​		115,740,214	​		214,249,579	​		531,561,742
Development costs	​			​			​
Proved properties	​		—	​		—	​		—
Total	​		—	​		—	​		—
Total costs incurred on oil, natural gas and NGL activities	​	$	115,740,214	​	$	214,249,579	​	$	531,561,742

​

Results of Operations from Oil, Natural Gas and NGL Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and NGL operations.

​

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Oil, natural gas and NGL revenues	​	$	92,586,685	​	$	107,480,446	​	$	65,713,112
Lease bonus and other income	​	​	345,771	​	​	2,477,145	​	​	1,213,550
Production and ad valorem taxes	​		(6,389,231)	​		(7,719,949)	​		(4,399,667)
Depreciation and depletion expense	​		(47,988,796)	​		(52,118,367)	​		(25,213,043)
Impairment of oil and natural gas properties	​		(251,558,557)	​		(169,150,255)	​		(67,311,501)
Marketing and other deductions	​		(9,376,375)	​		(8,145,397)	​		(4,652,313)
Results of operations from oil, natural gas and NGLs	​	$	(222,380,503)	​	$	(127,176,377)	​	$	(34,649,862)

​

The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves, and the estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2020, 2019 and 2018. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC. F-28

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Proved Oil, Natural Gas and NGL Reserve Quantities

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. PUD reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

A Boe conversion ratio of six thousand cubic feet per barrel (6mcf/Bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a price equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil. F-29

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

The Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below:

​

​	​	​	​	​	​	​	​	​
​	​	Crude Oil and	​	​	​	Natural Gas	​	​
​	​	Condensate	​	Natural Gas	​	Liquids	​	Total
​		(MBbls)		(MMcf)		(MBbls)		(MBOE)
Net proved reserves at January 1, 2018	​	7,463	​	63,916	​	2,838	​	20,954
Revisions of previous estimates (1)	​	194	​	1,754	​	952	​	1,437
Purchase of minerals in place (2)	​	3,729	​	69,465	​	2,166	​	17,473
Production	​	(591)	​	(7,874)	​	(310)	​	(2,213)
Net proved reserves at December 31, 2018	​	10,795	​	127,261	​	5,646	​	37,651
Revisions of previous estimates (1)	​	849	​	25,398	​	684	​	5,766
Purchase of minerals in place (3)	​	1,787	​	13,129	​	686	​	4,661
Production	​	(1,113)	​	(17,046)	​	(561)	​	(4,515)
Net proved reserves at December 31, 2019	​	12,318	​	148,742	​	6,455	​	43,563
Revisions of previous estimates (1)	​	18	​	(2,256)	​	(2)	​	(359)
Purchase of minerals in place (4)	​	1,367	​	15,637	​	313	​	4,286
Production	​	(1,409)	​	(17,890)	​	(681)	​	(5,072)
Net proved reserves at December 31, 2020	​	12,294	​	144,233	​	6,085	​	42,418
​	​	​	​	​	​	​	​	​
Net proved developed reserves	​	​	​	​	​	​	​	​
December 31, 2018	​	9,183	​	116,321	​	5,063	​	33,633
December 31, 2019	​	11,303	​	141,181	​	6,079	​	40,912
December 31, 2020	​	12,294	​	144,233	​	6,085	​	42,418
​	​	​	​	​	​	​	​	​
Net proved undeveloped reserves	​	​	​	​	​	​	​	​
December 31, 2018	​	1,612	​	10,940	​	583	​	4,018
December 31, 2019	​	1,015	​	7,561	​	376	​	2,651
December 31, 2020	​	—	​	—	​	—	​	—
(1)	Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.
---	---
(2)	Includes the acquisition of two packages of diverse mineral and royalty interests for a total of $243.2 million. The first acquisition totaling $155.7 million consists of mineral and royalty interests primarily in the Permian Basin, Haynesville Shale, Mid-Continent Area and Appalachia Region. The second acquisition totaling $87.5 million consists of mineral and royalty interests primarily in the Permian Basin, Eagle Ford Shale and Appalachia Region.
---	---
(3)	Includes the acquisition of three packages of mineral and royalty interests for a total of $103.8 million.  The first acquisition totaling $58.4 million consists of mineral and royalty interests primarily in the Eagle Ford Shale, Permian Basin, East Texas Region and Appalachia Region.  The second acquisition totaling $9.4 million consists of mineral and royalty interests in the Mid-Continent Region.  The third acquisition totaling $36.0 million consists of mineral and royalty interests in the Eagle Ford Shale.
---	---
(4)	Includes the acquisition of mineral and royalty interests for a total of $41.5 million. The acquisition consists of mineral and royalty interests primarily in the Delaware Basin, DJ Basin, Haynesville, STACK and Eagle Ford.
---	---

​

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. F-30

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

​

Standardized Measure

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties is as follows (in thousands):

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​		2020		​	2019		​	2018
Future cash inflows	​	$	705,356	​	$	1,025,430	​	$	1,056,464
Future production costs	​	​	(55,897)	​	​	(78,061)	​	​	(79,724)
Future state margin taxes	​	​	(22,688)	​	​	(32,377)	​	​	(32,885)
Future income tax expense	​	​	-	​	​	(33,235)	​	​	(41,241)
Future net cash flows	​	​	626,771	​	​	881,757	​	​	902,614
Less 10% annual discount to reflect timing of cash flows	​	​	(341,775)	​	​	(481,786)	​	​	(504,247)
Standard measure of discounted future net cash flows	​	$	284,996	​	$	399,971	​	$	398,367

​

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2020, 2019 and 2018 were $39.57, $55.69 and $65.56 per barrel for crude oil and $1.99, $2.58 and $3.10 per Mcf for natural gas, respectively.

Future production costs are computed primarily by the Partnership’s petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands):

​	​	​	​	​	​	​	​	​	​
​	​	Year Ended December 31,
​	​	2020		​	2019		​	2018
Standardized measure - beginning of year	​	$	399,971	​	$	398,367	​	$	215,552
Sales, net of production costs	​	​	(76,821)	​	​	(93,942)	​	​	(56,661)
Net changes of prices and production costs related to future production	​	​	(127,838)	​	​	(72,875)	​	​	11,355
Revisions of previous quantity estimates, net of related costs	​	​	(2,501)	​	​	56,666	​	​	16,385
Net changes in state margin taxes	​	​	4,314	​	​	191	​	​	(13,271)
Net changes in income taxes	​	​	13,480	​	​	3,752	​	​	(17,232)
Accretion of discount	​	​	38,927	​	​	42,808	​	​	21,555
Purchases of reserves in place	​	​	46,007	​	​	59,953	​	​	175,885
Timing differences and other	​	​	(10,543)	​	​	5,051	​	​	44,799
Standardized measure - end of year	​	$	284,996	​	$	399,971	​	$	398,367

​

​

​ F-31

Table of Contents KIMBELL ROYALTY PARTNERS, LP

SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED

Selected Quarterly Financial Information—Unaudited

Quarterly financial data was as follows for the periods indicated.

​

​	​	​	​	​	​	​	​	​	​	​	​	​
​		First Quarter		****	Second Quarter		****	Third Quarter		****	Fourth Quarter
2020	​	​	​	​	​	​	​	​	​	​	​	​
Total revenue	​	$	35,947,371	​	$	12,803,034	​	$	18,444,163	​	$	23,287,347
Net loss attributable to common units	​	$	(39,301,034)	​	$	(48,028,651)	​	$	(17,795,643)	​	$	(62,225,565)
Net loss attributable to common units	​	​	​	​	​	​	​	​	​	​	​	​
Basic	​	$	(1.29)	​	$	(1.39)	​	$	(0.50)	​	$	(1.66)
Diluted	​	$	(1.29)	​	$	(1.39)	​	$	(0.50)	​	$	(1.66)
Cash distributions declared and paid	​	$	0.17	​	$	0.13	​	$	0.19	​	$	0.19
Total assets	​	$	680,255,463	​	$	695,357,961	​	$	665,451,384	​	$	564,634,193
Long-term debt	​	$	101,223,602	​	$	171,723,602	​	$	169,700,653	​	$	171,550,142
Mezzanine equity	​	$	40,819,707	​	$	41,435,172	​	$	42,050,637	​	$	42,666,102
Unitholders' equity	​	$	368,296,195	​	$	329,836,312	​	$	326,087,159	​	$	258,632,296
Noncontrolling interest	​	$	162,679,661	​	$	143,141,215	​	$	114,163,481	​	$	77,002,442
​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	First Quarter		****	Second Quarter		****	Third Quarter		****	Fourth Quarter
2019	​	​	​	​	​	​	​	​	​	​	​	​
Total revenue	​	$	17,947,209	​	$	31,936,601	​	$	32,978,851	​	$	25,362,609
Net loss attributable to common units	​	$	(3,687,252)	​	$	(11,758,374)	​	$	(16,261,051)	​	$	(51,325,605)
Net loss attributable to common units	​	​	​	​	​	​	​	​	​	​	​	​
Basic	​	$	(0.21)	​	$	(0.54)	​	$	(0.73)	​	$	(2.27)
Diluted	​	$	(0.21)	​	$	(0.54)	​	$	(0.73)	​	$	(2.27)
Cash distributions declared and paid	​	$	0.37	​	$	0.39	​	$	0.42	​	$	0.38
Total assets	​	$	906,158,146	​	$	868,725,908	​	$	828,745,127	​	$	748,594,054
Long-term debt	​	$	87,309,544	​	$	87,309,544	​	$	91,261,477	​	$	100,135,477
Mezzanine equity	​	$	70,275,978	​	$	71,820,563	​	$	73,365,147	​	$	74,909,732
Unitholders' equity	​	$	314,985,017	​	$	360,133,072	​	$	343,138,843	​	$	283,827,721
Noncontrolling interest	​	$	427,617,585	​	$	343,165,767	​	$	310,744,268	​	$	281,157,393

​

​

​ F-32

​ Exhibit 10.11

Execution Version

AMENDMENT NO. 2 TO CREDIT AGREEMENT

This Amendment No. 2 to Credit Agreement (this “Amendment”), dated as of December 8, 2020, is among Kimbell Royalty Partners, LP, a Delaware limited partnership (the “Borrower”), each of the Guarantors party hereto (the “Guarantors”), the undersigned Continuing Lenders (as defined below), the Exiting Lenders (as defined below), Citibank, N.A., as Administrative Agent for the Lenders (in such capacity, the “Administrative Agent”), and, solely for purposes of Sections 4, 11, and 13 of this Amendment, the Original Administrative Agent (as defined below).

INTRODUCTION

A.        The Borrower, the financial institutions party thereto as lenders (the “Existing Lenders”), and Frost Bank, a Texas state bank, as administrative agent for the Existing Lenders (in such capacity, the “Original Administrative Agent”) have entered into the Credit Agreement dated as of January 11, 2017 (the “Original Credit Agreement”).

B.         The Borrower, the Existing Lenders party thereto and the Original Administrative Agent, as administrative agent, have entered into the Amendment No. 1 to the Credit Agreement dated as of July 12, 2018 (“Amendment No. 1”) which Amendment No. 1 amended the Original Credit Agreement (the Original Credit Agreement as amended  by Amendment No. 1 and as otherwise amended, supplemented or otherwise modified and in effect immediately prior to the effectiveness of this Amendment, the “Existing Credit Agreement”).

C.         In connection with the Existing Credit Agreement, the Borrower and the Guarantors (the “Existing Guarantors”) entered into the “Security Documents” (as defined in the Existing Credit Agreement, hereafter the “Existing Security Documents”) pursuant to which the Borrower and the Guarantors granted “Liens” (as defined in the Existing Credit Agreement, hereafter the “Existing Liens”) on the “Collateral” (as defined in the Existing Credit Agreement, hereinafter the “Existing Collateral”) for the benefit of the Secured Parties (as defined in the Existing Credit Agreement, hereinafter the “Existing Secured Parties”).

D.        In connection with this Amendment, the Borrower, Frost Bank, on behalf of itself and the Existing Lenders in its capacity as the Original Administrative Agent and on behalf of the Existing Secured Parties, and the Administrative Agent will enter into the Master Assignment Agreement (hereinafter defined) pursuant to which the Original Administrative Agent will assign to the Administrative Agent as successor administrative agent (the “Successor Administrative Agent”) the Existing Security Documents and the Existing Liens.

E.         On the Amendment No. 2 Effective Date (hereinafter defined), this Amendment shall amend in its entirety the Existing Credit Agreement and renew and extend the extensions of credit thereunder, such that all outstanding “Loans” (as defined in the Existing Credit Agreement) shall be refinanced and deemed made under the Credit Agreement (hereinafter defined) and shall constitute Loans for all purposes under the Credit Agreement, all “Letters of Credit” (as defined in the Existing Credit Agreement) shall be deemed issued under the Credit Agreement and all “Obligations” (as defined in the Existing Credit Agreement, hereafter the “Existing Obligations”)

​ ​

​ ​

under the Existing Credit Agreement shall constitute Obligations under the Credit Agreement, provided, however, that the execution and delivery of this Amendment or any of the Credit Documents pursuant hereto shall not constitute a novation of such the Existing Obligations.

F.         The Existing Guarantors are party to that certain Guarantee, dated as of February 8, 2017 (as amended, restated, supplemented or otherwise modified from time to time, including by this Amendment, the “Guarantee”), in favor of the Original Administrative Agent for the benefit of the Secured Parties.

G.        The Borrower and the Existing Guarantors are party to that certain Pledge and Security Agreement, dated as of February 8, 2017 (as amended, restated, supplemented or otherwise modified from time to time, including by this Amendment, the “Pledge and Security Agreement”), in favor of the Original Administrative Agent for the benefit of the Secured Parties.

H.        The Borrower has requested an increase in the Total Commitment, and in connection therewith, an allocation of Commitments as provided in the Credit Agreement.  On the Amendment No. 2 Effective Date (i) each of Wells Fargo Bank, National Association, Fifth Third Bank, and BOKF, N.A. dba Bank of Texas (each an “Exiting Lender” and collectively the “Exiting Lenders”), will cease to be Lenders and the Exiting Lenders shall have no Commitments under the Credit Agreement, and (ii) each of Citibank, N.A., BBVA USA, Truist Bank, KeyBank, N.A., Independent Financial, and UMB Bank, N.A. (each a “New Lender” and collectively the “New Lenders”, and the New Lenders, together with the Existing Lenders (other than the Exiting Lenders), the “Continuing Lenders”) will become Lenders (under and as defined in the Credit Agreement) such that after giving effect to the increase in the Total Commitment and the allocation of Commitments, the Commitments of the Continuing Lenders shall be as set forth on Schedule 13.2 of the Credit Agreement.

THEREFORE, in fulfillment of the foregoing, the Borrower, the Administrative Agent, (solely for purposes of Sections 4, 11 and 13 of this Amendment) the Original Administrative Agent, the undersigned Continuing Lenders and the undersigned Exiting Lenders hereby agree as follows:

Section 1.        Definitions; References.  Unless otherwise defined in this Amendment, each term used in this Amendment which is defined in the Credit Agreement has the meaning assigned to such term in the Credit Agreement after giving effect to this Amendment.

Section 2.        Agents.  On the Amendment No. 2 Effective Date, Citibank, N.A., will become Lead Arranger and Syndication Agent under the Credit Agreement; BBVA USA, Frost Bank and Truist Bank, will become Joint Lead Arrangers and BBVA USA, Frost Bank and Truist Bank will become Co-Documentation Agents under the Credit Agreement.

Section 3.       Amendment of Existing Credit Agreement.  Upon the satisfaction or waiver of the conditions specified in Section 8 of this Amendment, effective as of the Amendment No. 2 Effective Date, the Existing Credit Agreement (including its Exhibits and Schedules) is hereby amended to read in its entirety as set forth in Annex A attached hereto (such agreement as set forth in such Annex A (but without the Annex A designation on the cover page) as hereinafter amended, modified, supplemented, waived or amended and restated from time to time the “Credit

​ -2-

​ ​

Agreement”) and the terms and provisions of the Credit Agreement supersede the terms and provisions of the Existing Credit Agreement.  The Credit Agreement is not a new or substitute credit agreement or novation of the Existing Credit Agreement.  The Obligations of Borrower and the other Loan Parties evidenced under the Credit Agreement and the other Credit Documents are given in renewal, extension and modification, but not in extinguishment, novation or discharge, of the Existing Obligations. From and after the Amendment No. 2 Effective Date, (i) all references to the Existing Credit Agreement (or to any amendment, supplement, modification or amendment and restatement thereof) in the Credit Documents (other than in the Credit Agreement) shall be deemed to refer to the Existing Credit Agreement as amended hereby and (ii) all references to any section (or subsection) of the Existing Credit Agreement in any Credit Document (other than the Credit Agreement) shall be amended to be references to the corresponding provisions of the Credit Agreement.  Each Existing Lender hereby waives any requirements for notice of prepayment, minimum amounts of prepayments of the Loans thereunder, ratable reductions of the Commitments of Lenders under the Credit Documents (as defined in the Existing Credit Agreement, the “Existing Credit Documents”) and ratable payments on account of the principal or interest of any Loan under the Existing Credit Documents to the extent that any such prepayment, reductions or payments are required to ensure that, upon the effectiveness of the Credit Agreement, the Loans of the Lenders shall be outstanding on a ratable basis in accordance with their respective Commitment Percentages.

Section 4.        New Lenders, Existing Lenders and Allocation of the Commitments.

Each New Lender is hereby added to the Credit Agreement as a Lender and agrees to be bound by all the terms and provisions of the Credit Agreement binding on a Lender.  Each New Lender (i) confirms that it has received a copy of the Existing Credit Agreement together with copies of the financial statements referred to therein and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Amendment; (ii) agrees that it will, independently and without reliance upon the Original Administrative Agent, the Administrative Agent, any Issuing Bank, any Exiting Lender, any Existing Lender or any other Lender or agent and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in entering into and taking or not taking action under the Credit Agreement; (iii) appoints and authorizes the Original Administrative Agent and the Administrative Agent to take such action as agent on its behalf and to exercise such powers under the Credit Agreement and the other Credit Documents as are delegated to the Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto; and (iv) agrees that it will perform in accordance with their terms all of the obligations which by the terms of the Credit Agreement are required to be performed by it as a Lender.  By its execution of this Amendment, the Borrower, the Administrative Agent and the Issuing Banks hereby (i) consent to the addition of the New Lenders, as and to the extent required under Section 13.6 of the Credit Agreement, and (ii) agree that the Exiting Lenders shall cease to be Lenders under the Credit Agreement effective on the Amendment No. 2 Effective Date.

Each of the Existing Lenders, the Continuing Lenders and the Administrative Agent have agreed among themselves to effectuate an assignment and assumption with respect to the Existing Lenders’ (a) rights and obligations in their capacity as Existing Lenders under the Existing Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to all or any of such outstanding rights and obligations of such Existing Lenders under the Existing

​ -3-

​ ​

Credit Agreement (including any letters of credit and guarantees included in such facility) and (b) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other rights of the Existing Lenders (in their capacity as an Existing Lender) against any Person, whether known or unknown, arising under or in connection with the Existing Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (a) above (the rights and obligations sold and assigned pursuant to clauses (a) and (b) above being referred to herein collectively as the “Assigned Interests”) in order to, among other things, to reallocate the Commitments (as defined in the Existing Credit Agreement, the “Existing Commitments”) and the Loans (as defined in the Existing Credit Agreement, the “Existing Loans”) to the Continuing Lenders under the Credit Agreement.  The parties hereto hereby consent to the Existing Lenders’ assignment of the Assigned Interests to the Continuing Lenders and the assumption by the Continuing Lenders of such Assigned Interests and the reallocation of the Existing Commitments and the Existing Loans in accordance with this Section 4.  On the Amendment No. 2 Effective Date, after giving effect to the assignments and assumptions of the Assigned Interests and the reallocation of the Existing Loans and the Existing Commitments pursuant to this Section 4, the Commitment of each Continuing Lender shall be as set forth on Schedule 13.2 of the Credit Agreement.  With respect to such Commitment, each Continuing Lender shall be deemed to have acquired the Assigned Interests allocated to it from the Existing Lenders or assigned the Assigned Interests to the other Continuing Lenders pursuant to the terms of the Assignment and Assumption attached to the Existing Credit Agreement as Exhibit E as if each such Continuing Lender, each Existing Lender, the Administrative Agent, the Issuing Banks and the Borrower, as applicable, had executed an Assignment and Assumption Agreement with respect to such allocation.  In connection with the assignment and assumption of Assigned Interests contemplated in this Section 4 and for the purposes of such assignment and assumption only, the parties hereto, as applicable, hereby agree to waive the processing and recordation fees required under Section 13.6 of the Existing Credit Agreement.

Upon the occurrence of the Amendment No. 2 Effective Date, each of the Exiting Lenders shall automatically cease to be a Lender under the Credit Agreement (provided that those provisions of the Existing Credit Agreement and each other Existing Credit Document that, by their terms continue to apply to any Exiting Lender after such Exiting Lender no longer has a Commitment or is no longer a Lender party to the Existing Credit Agreement shall continue to apply to such Exiting Lender in accordance with the Existing Credit Agreement or such other Existing Credit Documents).  For the avoidance of doubt the parties hereto acknowledge and agree that the Liens created by the mortgages and deeds of trust securing the Existing Credit Agreement and the Existing Security Documents shall be carried forward to secure the Obligations and evidenced by the Security Documents and have not been released or impaired in any way.

Each of the Exiting Lenders that holds a Note agrees to promptly return such Note to the Borrower marked “cancelled”.

The parties hereto further agree that the Credit Agreement and the Notes shall serve to extend, renew and continue, but not extinguish or novate, the Notes under the Existing Credit

​ -4-

​ ​

Agreement and the corresponding Loans and to amend, but not to extinguish or cause to be novated the Indebtedness under, the Existing Credit Agreement.

The Existing Lenders hereby authorize and empower (i) the Original Administrative Agent to execute and deliver to the Administrative Agent assignments of Liens, including UCC-3 assignments, to effectuate the assignments contemplated hereby and by the Master Assignment Agreement and (ii) each of the Original Administrative Agent and the Administrative Agent to execute and deliver such amendments and modifications to the Existing Security Documents, and to make such filings as are reasonably necessary to make the assignments contemplated hereby and by the Master Assignment Agreement of record as they may reasonably determine are appropriate.

Section 5.        Reaffirmation of Liens and Guarantee.

(a)        The Borrower and the Guarantors (i) are parties to certain Security Documents securing and supporting the Obligations under the Credit Documents, (ii) represent and warrant that they have no defenses to the enforcement of the Security Documents and that according to their terms the Security Documents will continue in full force and effect to secure the Obligations under the Credit Documents, as the same may be amended, supplemented, or otherwise modified, and (iii) acknowledge, represent, and warrant that the liens and security interests created by the Security Documents are valid and subsisting and create a Lien on the Collateral to secure the Obligations under the Credit Documents, as the same may be amended, supplemented, or otherwise modified.

(b)        Each Guarantor hereby ratifies, confirms, and acknowledges that its obligations under the Guarantee are in full force and effect and that such Guarantor continues to unconditionally and irrevocably guarantee the full and punctual payment, when due, whether the stated maturity or earlier by acceleration or otherwise, of all of the Guaranteed Obligations (as defined in the Guarantee), as such Guaranteed Obligations may have been amended by this Amendment. Each such Guarantor hereby acknowledges that its execution and delivery of this Amendment does not indicate or establish an approval or consent requirement by such Guarantor under the Guarantee in connection with the execution and delivery of amendments, modifications, supplements, amendments and restatements or waivers to the Credit Agreement, the Notes or any of the other Credit Documents.

Section 6.        Representations and Warranties.  Each of the Borrower and the Guarantors represents and warrants to the Administrative Agent, the Lenders and the Issuing Banks that:

(a)        the representations and warranties set forth in the Credit Agreement and in the other Credit Documents are true and correct in all material respects (except to the extent any such representation is qualified by materiality or “material adverse effect”, in which case such representation shall be true and correct in all respects) on and as of the Amendment No. 2 Effective Date (except for any such representations and warranties that were made as of a specified date, in which case such representations and warranties were true and correct in all material respects as of such earlier date (except to the extent any such representation is qualified by materiality or “material adverse effect”, in which case such representation shall be true and correct in all respects as of such earlier date));

​ -5-

​ ​

(b)        (i) the execution, delivery, and performance of this Amendment are within its limited partnership or limited liability company power, as appropriate, and the authority of the Borrower and the Guarantors and have been duly authorized by appropriate proceedings and (ii) this Amendment constitutes a legal, valid and binding obligation of the Borrower and the Guarantors, enforceable against the Borrower and the Guarantors in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; and

(c)        as of the effectiveness of this Amendment and immediately after giving effect thereto, no Default or Event of Default has occurred and is continuing.

Section 7.        Effectiveness.  Subject to the last paragraph of this Section, and notwithstanding anything to the contrary in this Amendment (including the representations and warranties set forth in Section 6 and Section 7 hereof), this Amendment shall become effective (the date of effectiveness being the “Amendment No. 2 Effective Date”) and all outstanding “Loans” (as defined in the Existing Credit Agreement) shall be refinanced and deemed made under the Credit Agreement and shall constitute Loans for all purposes under the Credit Agreement and all “Letters of Credit” (as defined in the Existing Credit Agreement) shall be deemed issued by Frost Bank, as an Issuing Bank, under the Credit Agreement and the Existing Obligations shall constitute Obligations under the Credit Agreement, upon the satisfaction (or waiver by the Administrative Agent) of the following:

(a)        Documentation. The Administrative Agent shall have received the following:

(i)         Executed Amendment.  The Administrative Agent (or its counsel) shall have received from each party hereto either (i) a counterpart of this Amendment signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include electronic transmission of a signed signature page of this Amendment) that such party has signed a counterpart of this Amendment.

(ii)       Secretary’s Certificates of the Credit Parties.  The Administrative Agent shall have received, in the case of each Credit Party, each of the items referred to in subclauses (1), (2) and (3) below:

(1)        a certificate as to the good standing (to the extent such concept or a similar concept exists under the laws of such jurisdiction) of each such Credit Party as of a recent date from such Secretary of State (or other similar official) of the jurisdiction of its organization;

(2)        a certificate of the Secretary or Assistant Secretary or similar officer of each Credit Party dated the Amendment No. 2 Effective Date  and certifying:

(A)  that attached thereto is a true and complete copy of (i) the partnership agreement, limited liability company agreement or other equivalent governing documents of such Credit Party as in effect on the Amendment No. 2 Effective Date and at all times since a date prior

​ -6-

​ ​

to the date of the resolutions described in clause (B) below and (ii) the certificate of limited partnership, articles of incorporation or certificate of formation of such Credit Party,

(B)   that attached thereto is a true and complete copy of resolutions duly adopted by the board of directors (or managing general partner, managing member or equivalent) of such Credit Party authorizing the execution, delivery and performance of this Amendment and the other Credit Documents to which such Person is a party and, in the case of the Borrower, the Loans under the Credit Agreement, and that such resolutions have not been modified, rescinded or amended and are in full force and effect on the Amendment No. 2 Effective Date, that the certificate of limited partnership, articles of incorporation or certificate of formation of such Credit Party has not been amended since the date of the last amendment thereto disclosed pursuant to subclause (ii) above, and

(C)   as to the incumbency and specimen signature of each officer executing any Credit Document or any other document delivered in connection herewith on behalf of such Credit Party (or its general partner or equivalent), and

(3)        a certificate of a director or an officer as to the incumbency and specimen signature of the Secretary or Assistant Secretary or similar officer executing the certificate pursuant to subclause (2) above.

(iii)      Security Documents.  All of the Security Documents, including UCC-3 or other applicable personal property and financing statement amendments or assignments reasonably requested by the Administrative Agent to be filed, registered or recorded to effectuate the assignment contemplated by the Master Assignment Agreement shall have been duly executed and delivered to the Administrative Agent for filing, registration or recording and none of the Collateral shall be subject to any other pledges, security interests or mortgages, except for Permitted Liens.

(iv)       Legal Opinions.  A customary written opinion of Baker Botts L.L.P., counsel to the Credit Parties, (i) dated the Amendment No. 2 Effective Date, (ii) addressed to the Administrative Agent, the Lenders and each Issuing Bank and (ii) in form and substance reasonably satisfactory to the Administrative Agent. The Borrower and the other Credit Parties hereby instruct such counsel to deliver such legal opinion.

(v)        A certificate of an Authorized Officer of the Borrower certifying that the Borrower and the Restricted Subsidiaries, taken as a whole, immediately after giving effect to the consummation of the transactions contemplated by this Amendment, are, as of the Amendment No. 2 Effective Date, Solvent.

(vi)       A certificate of an Authorized Officer of the Borrower as to the matters set forth in Section 7(c) hereof.

​ -7-

​ ​

(vii)     Notes.  Duly executed Notes for each Continuing Lender that has requested a Note.

(viii)    Title Diligence.  Title information reasonably satisfactory to the Administrative Agent under the circumstances in light of the Borrower’s business and operations with respect to the Oil and Gas Properties evaluated in the Initial Reserve Report (as defined below) constituting not less than sixty percent (60%) of the PV-9 of PDP Reserves by value.

(ix)       Financial Statements.  The following:

(1)        with respect to the Borrower and the Subsidiaries, (i) audited consolidated Financial Statements for the three most recently completed fiscal years (provided, that such Financial Statements comprised of a balance sheet shall only be required for the two most recently completed fiscal years) ended at least 90 days prior to the Amendment No. 2 Effective Date and (ii)  unaudited Financial Statements for each interim fiscal quarter ended since the last audited Financial Statements and at least 45 days prior to the Amendment No. 2 Effective Date;

(2)        customary projections of the Borrower and the Restricted Subsidiaries in form and substance reasonably satisfactory to the Administrative Agent on a quarterly basis commencing with the fiscal quarter ending June 30, 2020 through the fiscal year ended December 31, 2022.

(x)        PATRIOT Act.  At least 3 Business Days prior to the Amendment No. 2 Effective Date (to the extent requested at least 5 Business Days prior thereto), all documentation and other information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including, without limitation, the PATRIOT Act and the requirements of 31 C.F.R. §1010.230.

(xi)       Copies of insurance certificates evidencing the insurance required to be maintained by the Borrower and the Restricted Subsidiaries by Section 9.3 of the Credit Agreement.

(xii)     Copies of the duly executed Master Assignment Agreement (the “Master Assignment Agreement”), in such number of copies as the Administrative Agent may specify, and in form and substance satisfactory to the Administrative Agent, among the Original Administrative Agent, the Administrative Agent and the Borrower pursuant to which the Original Administrative Agent assigns to the Administrative Agent the Existing Security Documents and the Existing Liens.

(xiii)    Copies for the Lenders of the reserve report (the “Initial Reserve Report”) with respect to the Borrower’s and its subsidiaries’ oil and gas properties, dated July 1, 2020 prepared by the Borrower, which the Administrative Agent confirms is in a form reasonably satisfactory to it.

​ -8-

​ ​

(xiv)     UCC and other lien searches for each of the Credit Parties reflecting the absence of liens and security interests other than those being continued in favor of the Administrative Agent or Permitted Liens.

(b)        Fees and Expenses.  The Administrative Agent shall have received all fees due and payable on or prior to the Amendment No. 2 Effective Date, including all fees then due pursuant to the Fee Letter (including the fees and expenses of a single outside counsel for the Administrative Agent to the extent invoiced at least two (2) Business Days prior to the Amendment No. 2 Effective Date) and, to the extent invoiced at least two (2) Business Days prior to the Amendment No. 2 Effective Date, all other amounts due and payable pursuant to the Credit Documents on or prior to the Amendment No. 2 Effective Date, including, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses (including reasonable fees, charges and disbursements of a single outside counsel and recording fee for the filing of the Security Documents) required to be reimbursed or paid by the Credit Parties hereunder or under any Credit Document.

(c)        On the Amendment No. 2 Effective Date, immediately after giving effect to the transactions contemplated by this Amendment, (a) no Default or Event of Default shall have occurred and be continuing and (b) all representations and warranties made by any Credit Party contained herein or in the other Credit Documents shall be true and correct in all material respects with the same effect as though such representations and warranties had been made on and as of the Amendment No. 2 Effective Date (except where such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct in all material respects as of such earlier date).

(d)        The Borrower shall have maintained and have in effect the hedging agreements set forth in Schedule 8.18 of the Credit Agreement.

(e)        Notwithstanding anything to the contrary in this Amendment, the Credit Agreement or in any other Credit Document, to the extent that any security interest in the Collateral (other than any Collateral the security interest in which may be perfected by (x) the filing of a UCC financing statement under the Uniform Commercial Code or (y) the delivery of certificated equity interests constituting Collateral), is not or cannot be perfected on the Amendment No. 2 Effective Date after the Borrower’s use of commercially reasonable efforts to do so (without undue burden or cost), then the perfection of such security interest will not constitute a condition precedent to the effectiveness of this Amendment and the availability of the Loans and Letters of Credit under the Credit Agreement on the Amendment No. 2 Effective Date, but such security interest will be required to be perfected in accordance with Section 8(a) hereof.

The Administrative Agent shall promptly notify the Continuing Lenders, the Exiting Lenders and the Borrower when the Amendment No. 2 Effective Date shall have occurred and such notice shall be binding on the parties hereto.

Section 8.        Post-Closing Requirements.

(a)        Within ninety (90) days after the Amendment No. 2 Effective Date (or such later date as the Administrative Agent may agree in its sole discretion), the Restricted Subsidiaries

​ -9-

​ ​

shall have executed and delivered to the Administrative Agent such additional Security Documents that, together with existing Security Documents granting a Lien on the Borrower’s and Restricted Subsidiaries’ Oil and Gas Properties will cause the Borrower to be in compliance with the Minimum Collateral Coverage.

(b)        Within thirty (30) days after the Amendment No. 2 Effective Date (or such later date as the Administrative Agent may agree in its sole discretion), the Credit Parties shall have delivered account control agreements, duly and validly executed by the Credit Parties, the Administrative Agent, and the applicable depositary bank or securities intermediary, and reflecting compliance with Section 9.17 of the Credit Agreement.

(c)        Within ninety (90) days after the Amendment No. 2 Effective Date (or such later date as the Administrative Agent may agree in its sole discretion), a customary favorable opinion of local counsel in those jurisdictions reasonably requested by the Administrative Agent in its discretion where a Security Document will be filed in such form and covering such matters as the Administrative Agent may reasonably request.

Section 9.        Amendment to Pledge and Security Agreement.  The Pledge and Security Agreement in effect immediately prior to the Amendment No. 2 Effective Date is hereby amended effective as of the Amendment No. 2 Effective Date as follows:

(a)        Citibank, N.A. in its capacity as Administrative Agent is substituted for Frost Bank as Administrative Agent under the Pledge and Security Agreement and all references in the Pledge and Security Agreement to the Administrative Agent shall be references to Citibank, N.A. as Administrative Agent.

(b)        The definition of Credit Agreement in the Pledge and Security Agreement is amended to refer to the Credit Agreement as defined in this Amendment, as such Credit Agreement may be amended, modified, amended and restated or supplemented from time to time.

Section 10.     Amendment to Guarantee.  The Guarantee as in effective immediately prior to the Amendment No. 2 Effective Date is hereby amended effective as of the Amendment No. 2 Effective Date as follows:

(a)        Citibank, N.A. in its capacity as Administrative Agent is substituted for Frost Bank as Administrative Agent under the Guarantee and all references in the Guarantee to the Administrative Agent shall be references to Citibank N.A. as Administrative Agent.

(b)        The definition of Credit Agreement in the Guarantee is amended to be a reference to the Credit Agreement as defined in this Amendment, as such Credit Agreement may be amended, modified, amended and restated or supplemented from time to time.

(c)        The following clause (d) is added to the end of Section 5 of the Guarantee: (d) Each Guarantor agrees it will permit officers and designated representatives of the Administrative Agent or officers and designated representatives of the Majority Lenders (as accompanied by the Administrative Agent) to visit and inspect any of the properties or assets of such Guarantor in whomsoever’s possession to the extent that it is within such party’s control to permit such inspection (and shall use commercially reasonable efforts to cause such inspection to

​ -10-

​ ​

be permitted to the extent that it is not within such party’s control to permit such inspection), and to examine the financial records of such Guarantor and discuss the affairs, finances, accounts and condition of such Guarantor with its officers and independent accountants therefor, in each case of the foregoing upon reasonable advance notice to such Guarantor, all at such reasonable times and intervals during normal business hours and to such reasonable extent as the Administrative Agent or the Majority Lenders may desire (and subject, in the case of any such meetings or advice from such independent accountants, to such accountants’ customary policies and procedures); provided that, excluding any such visits and inspections during the continuation of an Event of Default only one such visit per fiscal year shall be at such Guarantor’s expense; provided, further, that when an Event of Default exists, the Administrative Agent (or any of its representatives or independent contractors) or any representative of the Majority Lenders may do any of the foregoing at the expense of such Guarantor at any time during normal business hours and upon reasonable advance notice.

Section 11.    Resignation of Agents Under the Existing Credit Agreement; Appointment of Administrative Agent.

(a)        On the Amendment No. 2 Effective Date, the Original Administrative Agent hereby resigns as Administrative Agent under the Existing Credit Agreement and the Borrower and the Continuing Lenders agree that Citibank, N.A. is Administrative Agent and an Issuing Bank under the Credit Agreement and the Security Documents.

(b)        As of the Amendment No. 2 Effective Date (i) the Original Administrative Agent has resigned as the Administrative Agent under the Existing Credit Agreement; (ii) the Continuing Lenders hereby appoint the Administrative Agent as successor administrative agent under the Credit Agreement and the other Existing Credit Documents, as amended, and the Borrower hereby consents to such appointment; (iii) the Administrative Agent hereby accepts its appointment as Administrative Agent; and (iv) the parties hereto, including the Continuing Lenders, authorize and direct each of the Original Administrative Agent and the Administrative Agent to prepare, enter into, execute, record, and/or file any and all notices, certificates, instruments, UCC financing statements, and/or other documents or agreements (including the Master Assignment Agreement) filings in respect of any collateral, and assignments, amendments, or supplements to any UCC financing statements, mortgages, deeds of trust, security agreements, pledge agreements, certificates of title, stock powers, account control agreements, or other Credit Documents), as the Administrative Agent deems reasonably necessary or desirable to effect or evidence (of public record or otherwise) the transactions contemplated by this Section 11 and the Master Assignment Agreement or as otherwise reasonably requested by the Original Administrative Agent.

(c)        The parties hereto hereby confirm that the Administrative Agent succeeds to the rights and obligations of the Original Administrative Agent under the Existing Credit Agreement and the other Existing Credit Documents and becomes vested with all of the rights, powers, privileges, and duties of the Administrative Agent under the Credit Agreement and the Existing Credit Documents as amended hereby, and the Original Administrative Agent is discharged from all of its respective duties and obligations as administrative agent under the Existing Credit Agreement and the other Existing Credit Documents (except as provided in the Master Assignment Agreement and except to the extent of any obligation expressly stated in the Existing Credit

​ -11-

​ ​

Agreement or other Existing Credit Document as surviving any such resignation), as of the Amendment No. 2 Effective Date.

(d)        The Original Administrative Agent agrees that the Fee Letter (as defined in the Existing Credit Agreement) is hereby terminated in all respects, other than with respect to any provisions which expressly survive such termination, and relinquishes its rights to receive any further agency fees for acting as Administrative Agent under and as defined therein.

Section 12.      Effect on Credit Documents.  Except as amended or modified herein, the Existing Credit Agreement and the Existing Credit Documents remain in full force and effect as originally executed and are hereby in all respects ratified and confirmed, and nothing herein shall act as a waiver of any of the Administrative Agent’s, the Issuing Banks’ or the Lenders’ rights under the Credit Documents, as amended.  On and after the effectiveness of this Amendment, any reference to the Credit Agreement in any Credit Document shall be deemed to be a reference to the Credit Agreement as defined in this Amendment.  This Amendment is a Credit Document for the purposes of the provisions of the other Credit Documents.  Without limiting the foregoing, any breach of representations, warranties, and covenants under this Amendment shall be a Default or Event of Default under the other Credit Documents in accordance with the terms set forth therein.

Section 13.      Choice of Law.  This Amendment and any claim, controversy, dispute or cause of action (whether in contract or tort or otherwise) based upon, arising out of or relating to this Amendment and the transactions contemplated hereby shall be governed by, and construed in accordance with, the law of the State of Texas.

Section 14.      Counterparts.  This Amendment may be executed in counterparts (and by different parties hereto in different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.  Delivery of an executed counterpart of a signature page of this Amendment by facsimile or in electronic (i.e., “pdf” or “tif” format) shall be effective as delivery of a manually executed counterpart of this Amendment.

THIS WRITTEN AMENDMENT AND THE CREDIT DOCUMENTS, AS DEFINED IN THE CREDIT AGREEMENT, REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.  THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

[The remainder of this page has been left blank intentionally.]

​ -12-

​ EXECUTED as of the date first set forth above.

BORROWER :
​
KIMBELL ROYALTY PARTNERS, LP
​
By:	Kimbell Royalty GP, LLC, its general partner
​	​
By:	/s/ Matthew S. Daly
Name:	Matthew S. Daly
Title:	Chief Operating Officer and Secretary

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​

GUARANTORS:
​
KIMBELL INTERMEDIATE HOLDINGS, LLC,
a Delaware limited liability company
KIMBELL INTERMEDIATE GP, LLC,
a Delaware limited liability company
KIMBELL ROYALTY HOLDINGS, LLC,
a Delaware limited liability company
KIMBELL ROYALTY OPERATING, LLC,
a Delaware limited liability company
RIVERCREST ROYALTIES, LLC,
a Delaware limited liability company
RIVERCREST ROYALTIES II, LLC,
a Delaware limited liability company
HAYMAKER GREENFIELD, LLC,
a Delaware limited liability company
HAYMAKER HOLDING COMPANY, LLC,
a Delaware limited liability company
HAYMAKER PROPERTIES GP, LLC,
a Delaware limited liability company
PHILLIPS ENERGY PARTNERS, LLC,
a Delaware limited liability company
PHILLIPS ENERGY PARTNERS II, LLC,
a Delaware limited liability company
PHILLIPS ENERGY PARTNERS III, LLC,
a Delaware limited liability company
CIRRUS MINERALS, LLC,
a Delaware limited liability company
MUSTANG MINERALS, LLC,
a Delaware limited liability company
SPRINGBOK ENERGY PARTNERS, LLC,
a Delaware limited liability company
SPRINGBOK ENERGY PARTNERS II, LLC,
a Delaware limited liability company
​
By:	/s/ Matthew S. Daly
Name:	Matthew S. Daly
Title:	Chief Operating Officer and Secretary

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

ROCHESTER MINERALS, L.P.,
a Texas limited partnership
​
By:	Kimbell Intermediate GP, LLC, a Delaware limited liability company, its general partner
​	​
By:	/s/ Matthew S. Daly
Name:	Matthew S. Daly
Title:	Chief Operating Officer and Secretary
​
HOCHSTETTER, L.P.,
a Texas limited partnership
​
By:	Kimbell Intermediate GP, LLC, a Delaware limited liability company, its general partner
​	​
By:	/s/ Matthew S. Daly
Name:	Matthew S. Daly
Title:	Chief Operating Officer and Secretary
​
HAYMAKER PROPERTIES, LP,
a Delaware limited partnership
​
By:	Haymaker Properties GP, LLC, a Delaware limited liability company, its general partner
​	​
By:	/s/ Matthew S. Daly
Name:	Matthew S. Daly
Title:	Chief Operating Officer and Secretary

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

ADMINISTRATIVE AGENT / CONTINUING LENDER / ISSUING BANK / LEAD ARRANGER / SYNDICATION AGENT:
​
Citibank, N.A.,<br><br>as Administrative Agent, Issuing Bank, Continuing Lender, Lead Arranger and Syndication Agent
​
By:	/s/ Jeff Ard
Name:	Jeff Ard
Title:	Vice President

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

BBVA USA, as a Continuing Lender, Joint Lead Arranger and Co-Documentation Agent
​
By:	/s/ Gabriela Azcarate
Name:	Gabriela Azcarate
Title:	Senior Vice President

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

Frost Bank, as a Continuing Lender, as Original Administrative Agent, Issuing Bank, Joint Lead Arranger and Co-Documentation Agent
​
By:	/s/ Justin Armstrong
Name:	Justin Armstrong
Title:	Senior Vice President

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

Truist Bank, as a Continuing Lender, Joint Lead Arranger and Co-Documentation Agent
​
By:	/s/ Greg Krablin
Name:	Greg Krablin
Title:	Senior Vice President

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

Credit Suisse AG, Cayman Islands Branch,<br><br>as a Continuing Lender
​
By:	/s/ Nupur Kumar
Name:	Nupur Kumar
Title:	Authorized Signatory
​
By:	/s/ Christopher Zybrick
Name:	Christopher Zybrick
Title:	Authorized Signatory

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

JPMorgan Chase Bank, N.A., as a Continuing Lender
​
By:	/s/ Michael Kamauf
Name:	Michael Kamauf
Title:	Authorized Officer

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

KeyBank, N.A., as a Continuing Lender
​
By:	/s/ George E. McKean
Name:	George E. McKean
Title:	Senior Vice President

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

Royal Bank of Canada, as a Continuing Lender
​
By:	/s/ Don J. McKinnerney
Name:	Don J. McKinnerney
Title:	Authorized Signatory

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

Independent Financial, as a Continuing Lender
​
By:	/s/ Alex Zemkoski
Name:	Alex Zemkoski
Title:	Senior Vice President

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

UMB Bank, N.A., as a Continuing Lender
​
By:	/s/ Erica Spencer
Name:	Erica Spencer
Title:	VP – Energy Division

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

Wells Fargo Bank, National Association,<br><br>as Exiting Lender
​
By:	/s/ Courtney Kubesch
Name:	Courtney Kubesch
Title:	Director

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

Fifth Third Bank, as Exiting Lender
​
By:	/s/ Jonathan H Lee
Name:	Jonathan H Lee
Title:	Director

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ ​

BOKF, N.A. dba Bank of Texas, as Exiting Lender
​
By:	/s/ Blair Schrodel
Name:	Blair Schrodel
Title:	Senior Vice President

​

​ [SIGNATURE PAGE TO AMENDMENT NO. 2 TO CREDIT AGREEMENT – KIMBELL]

​ Annex A

Amended Credit Agreement

​ ​

​ Execution Version

Annex A to Amendment No. 2

to Credit Agreement

CREDIT AGREEMENT

​

dated as of January 11, 2017,

as amended through July 12, 2018

among

KIMBELL ROYALTY PARTNERS, LP,

as the Borrower,

AND

The Several Lenders

from Time to Time Parties Hereto,

AND

CITIBANK, N.A.,

as Administrative Agent

AND

BBVA USA, Frost Bank and Truist Bank

as Joint Lead Arrangers and Co-Documentation Agents

$500,000,000 Senior Secured Facility

_____________________________

CITIBANK, N.A.

​

as Lead Arranger and Syndication Agent

​

​ ii

​ TABLE OF CONTENTS

​	​	​
​	​	Page No.
ARTICLE I         DEFINITIONS		1
Section 1.1	Defined Terms	1
Section 1.2	Other Interpretive Provisions	43
Section 1.3	Accounting Terms	44
Section 1.4	References to Agreements, Laws, Etc	45
Section 1.5	Times of Day	45
ARTICLE II        AMOUNT AND TERMS OF CREDIT		45
Section 2.1	The Facility and Commitments	45
Section 2.2	Maximum Number of Advances	46
Section 2.3	Disbursement of Funds	46
Section 2.4	Repayment of Loans; Evidence of Debt	47
Section 2.5	Conversions and Continuations	48
Section 2.6	Pro Rata Borrowings	49
Section 2.7	Interest	49
Section 2.8	Interest Periods	50
Section 2.9	Increased Costs, Illegality, Benchmark Replacement Setting, Etc	51
Section 2.10	Compensation	55
Section 2.11	Change of Lending Office	56
Section 2.12	Notice of Certain Costs	56
Section 2.13	The Borrowing Base	56
Section 2.14	Scheduled Determinations of Borrowing Base	56
Section 2.15	Unscheduled Redeterminations of the Borrowing Base	57
Section 2.16	Procedure	57
Section 2.17	Reduction of Borrowing Base upon Sale of Borrowing Base Properties or Equity Interests in Restricted Subsidiaries, Hedge Terminations and Issuance of Permitted Additional Debt	58
Section 2.18	Defaulting Lenders	59
ARTICLE III       LETTERS OF CREDIT		61
Section 3.1	Letters of Credit	61
Section 3.2	Letter of Credit Applications	63
Section 3.3	Letter of Credit Participations	64
Section 3.4	Agreement to Repay Letter of Credit Drawings	66
Section 3.5	Increased Costs	68
Section 3.6	New or Successor Issuing Bank	68
Section 3.7	Role of Issuing Bank	70
Section 3.8	Cash Collateral	70
Section 3.9	Applicability of ISP and UCP	71
Section 3.10	Conflict with Issuer Documents	71

​

​ i

​ ​

​	​	​
ARTICLE IV       FEES; COMMITMENTS		71
Section 4.1	Fees	71
Section 4.2	Voluntary Reduction of Commitment Amount	72
Section 4.3	Mandatory Termination of Commitments	72
Section 4.4	Increases, Reductions and Terminations of Aggregate Elected Commitment Amount	73
ARTICLE V        PAYMENTS		76
Section 5.1	Voluntary Prepayments	76
Section 5.2	Mandatory Prepayments	76
Section 5.3	Method and Place of Payment	78
Section 5.4	Net Payments	79
Section 5.5	Computations of Interest and Fees	83
Section 5.6	Limit on Rate of Interest	83
ARTICLE VI       CONDITIONS PRECEDENT TO EFFECTIVE DATE		84
Section 6.1	Effective Date	84
ARTICLE VII      CONDITIONS PRECEDENT TO THE FUNDING DATE AND ALL SUBSEQUENT CREDIT EVENTS		86
Section 7.1	Funding Date	86
Section 7.2	All Credit Events	88
ARTICLE VIII     REPRESENTATIONS, WARRANTIES AND AGREEMENTS		89
Section 8.1	Organizational Status	89
Section 8.2	Organizational Power and Authority; Enforceability	89
Section 8.3	No Violation	89
Section 8.4	Litigation	89
Section 8.5	Margin Regulations	90
Section 8.6	Governmental Approvals	90
Section 8.7	Investment Company Act	90
Section 8.8	True and Complete Disclosure	90
Section 8.9	Financial Condition; Financial Statements	90
Section 8.10	Tax Matters	91
Section 8.11	Compliance with ERISA	91
Section 8.12	Subsidiaries	92
Section 8.13	Intellectual Property	92
Section 8.14	Environmental Laws	92
Section 8.15	Properties	92
Section 8.16	Solvency	93
Section 8.17	Insurance	93
Section 8.18	Hedge Transactions; Qualified EPC Counterparty	93
Section 8.19	Patriot Act; OFAC	93

​

​ ii

​ ​

​	​	​
Section 8.20	No Material Adverse Effect	94
Section 8.21	Foreign Corrupt Practices Act	94
Section 8.22	Security Interests	94
Section 8.23	Accounts	94
Section 8.24	Gas Imbalances; Prepayments	94
Section 8.25	Marketing of Production	94
ARTICLE IX       AFFIRMATIVE COVENANTS		95
Section 9.1	Information Covenants	95
Section 9.2	Books, Records and Inspections	98
Section 9.3	Maintenance of Insurance	99
Section 9.4	Payment of Taxes	99
Section 9.5	Maintenance of Existence	99
Section 9.6	Compliance with Statutes, Regulations, Etc	100
Section 9.7	ERISA	100
Section 9.8	Maintenance of Properties	101
Section 9.9	Transactions with Affiliates	101
Section 9.10	End of Fiscal Years; Fiscal Quarters	103
Section 9.11	Additional Guarantors, Grantors and Collateral	103
Section 9.12	Use of Proceeds	104
Section 9.13	Further Assurances	105
Section 9.14	Reserve Reports	105
Section 9.15	Title Information	106
Section 9.16	Consolidated Cash Balance Information	106
Section 9.17	Control Agreements	107
Section 9.18	Unrestricted Subsidiaries	107
Section 9.19	Compliance with Anti-Corruption Laws, Anti-Money Laundering Laws and Sanctions	108
ARTICLE X        NEGATIVE COVENANTS		108
Section 10.1	Liens	108
Section 10.2	Sale of Assets	108
Section 10.3	Debt to EBITDAX Ratio	109
Section 10.4	Current Ratio	109
Section 10.5	Consolidations and Mergers	110
Section 10.6	[Reserved]	110
Section 10.7	Indebtedness	110
Section 10.8	Restricted Payments	111
Section 10.9	Preferred Equity Units	113
Section 10.10	Hedge Transactions	113
Section 10.11	Passive Status of Borrower/OpCo	114
Section 10.12	Amendment of Organizational Documents	115
Section 10.13	Sanctions	116
Section 10.14	New Accounts	116
Section 10.15	Limitation on Investments	116
Section 10.16	Change in Business	118

​

​ iii

​ ​

​	​	​
Section 10.17	Designation of Restricted and Unrestricted Subsidiaries	118
ARTICLE XI       EVENTS OF DEFAULT		120
Section 11.1	Payments	120
Section 11.2	Representations, Etc	120
Section 11.3	Covenants	120
Section 11.4	Default Under Other Agreements	120
Section 11.5	Bankruptcy, Etc	121
Section 11.6	ERISA	121
Section 11.7	Guarantee	121
Section 11.8	Security Documents	122
Section 11.9	Judgments	122
Section 11.10	Change of Control	122
Section 11.11	Application of Proceeds	122
ARTICLE XII      THE ADMINISTRATIVE AGENT		124
Section 12.1	Appointment	124
Section 12.2	Exculpatory Provisions	125
Section 12.3	Reliance by the Administrative Agent	126
Section 12.4	Notice of Default	126
Section 12.5	Non-Reliance on the Administrative Agent and Other Lenders	126
Section 12.6	Indemnification	127
Section 12.7	The Administrative Agent in Its Individual Capacity	128
Section 12.8	Successor Agents	128
Section 12.9	Withholding Tax	129
Section 12.10	Security Documents and Guarantee	130
Section 12.11	Right to Realize on Collateral and Enforce Guarantee	130
Section 12.12	The Administrative Agent May File Proofs of Claim	130
Section 12.13	Credit Bidding	131
Section 12.14	Sub-agents	132
ARTICLE XIII     MISCELLANEOUS		132
Section 13.1	Amendments, Waivers and Releases	132
Section 13.2	Notices	134
Section 13.3	No Waiver; Cumulative Remedies	135
Section 13.4	Survival of Representations and Warranties	135
Section 13.5	Payment of Expenses; Indemnification	135
Section 13.6	Successors and Assigns; Participations and Assignments	137
Section 13.7	Replacements of Lenders under Certain Circumstances	142
Section 13.8	Adjustments; Set-off	142
Section 13.9	Counterparts	143
Section 13.10	Severability	144
Section 13.11	Integration	145
Section 13.12	GOVERNING LAW	145
Section 13.13	Submission to Jurisdiction; Waivers	145

​

​ iv

​ ​

Section 13.14	Acknowledgments	145
Section 13.15	WAIVERS OF JURY TRIAL	147
Section 13.16	Confidentiality	147
Section 13.17	Release of Collateral and Guarantee Obligations	148
Section 13.18	USA PATRIOT Act	149
Section 13.19	Payments Set Aside	149
Section 13.20	Reinstatement	149
Section 13.21	Disposition of Proceeds	149
Section 13.22	Collateral Matters; Hedge Transactions	150
Section 13.23	Agency of the Borrower for the Other Credit Parties	150
Section 13.24	Acknowledgement and Consent to Bail-In of Affected Financial Institutions	150
Section 13.25	Acknowledgement Regarding Any Supported QFCs	151
Section 13.26	Amendment	151

​

​ v

​ ​

​	​
​	EXHIBITS
Exhibit A	Form of Notice of Borrowing
Exhibit B	Form of Guarantee
Exhibit C	Form of Promissory Note
Exhibit D	Form of Compliance Certificate
Exhibit E	Form of Assignment and Acceptance
Exhibit F-1	Form of U.S. Tax Compliance Certificate (For Foreign Lenders That Are Not Partnerships For U.S. Federal Income Tax Purposes)
Exhibit F-2	Form of U.S. Tax Compliance Certificate (For Foreign Participants That Are Not Partnerships For U.S. Federal Income Tax Purposes)
Exhibit F-3	Form of U.S. Tax Compliance Certificate (For Foreign Participants That Are Partnerships For U.S. Federal Income Tax Purposes)
Exhibit F-4	Form of U.S. Tax Compliance Certificate (For Foreign Lenders That Are Partnerships For U.S. Federal Income Tax Purposes)
Exhibit G-1	Form of Elected Commitment Increase Certificate
Exhibit G-2	Form of Additional Lender Agreement
Exhibit H	Form of Intercompany Note
​	​
​	SCHEDULES
​	​
Schedule 1.1(a)	L/C Sublimit
Schedule 8.4	Litigation
Schedule 8.9	Financial Disclosures
Schedule 8.12	Subsidiaries
Schedule 8.18	Amendment No. 2 Effective Date Hedge Transactions
Schedule 8.23	Amendment No. 2 Effective Date Accounts
Schedule 10.15	Investments
Schedule 13.2	Notice Addresses and Commitments

​

​

​ vi

​ THIS CREDIT AGREEMENT is dated as of January 11, 2017, as amended through December 8, 2020, among KIMBELL ROYALTY PARTNERS, LP, a Delaware limited partnership (the “Borrower”), each of the banks, financial institutions and other lending institutions from time to time parties as lenders hereto (each a “Lender” and, collectively, the “Lenders”), and CITIBANK, N.A., as administrative agent for the Lenders (the “Administrative Agent”) and the other Persons party hereto.

WHEREAS, the Borrower has requested that the Lenders provide revolving credit and letter of credit facilities; and

WHEREAS, the Lenders are willing to make available to the Borrower such revolving credit and letter of credit facilities upon the terms and subject to the conditions set forth herein.

NOW, THEREFORE, in consideration of the premises and the covenants and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1      Defined Terms.

As used herein, the following terms shall have the meanings specified below:

“ABR” means, for any day, a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus ½ of 1% and (c) the Adjusted LIBOR Rate for a one (1) month interest period on such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1%; provided that ABR shall not be less than 0%.  Any change in ABR due to a change in the Prime Rate, the Federal Funds Effective Rate or the Adjusted LIBOR Rate shall be effective from and including the effective date of such change in the Prime Rate, the Federal Funds Effective Rate or the Adjust LIBOR Rate, respectively.

“ABR Loan” shall mean each Loan bearing interest based on the ABR.

“Additional Lender” has the meaning assigned to such term in Section 4.4(a).

“Additional Lender Certificate” has the meaning assigned to such term in Section 4.4(b)(v).

“Adjusted ABR Rate” shall mean, with respect to any ABR Advance and interest rate per annum equal to the ABR for any day, plus the Applicable Margin.

“Adjusted LIBOR Rate” shall mean, with respect to any LIBOR Advance for any Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/100 of 1%) equal to the LIBOR for such Interest Period, plus the Applicable Margin.

“Adjusted Total Commitment” shall mean, at any time, the Total Commitment less the aggregate amount of Commitments of all Defaulting Lenders.

​ 1

​ “Administrative Agent” shall mean Citibank, N.A., as the administrative agent for the Lenders under this Agreement and the other Credit Documents, or any successor administrative agent appointed in accordance with the provisions of Section 12.8

“Administrative Agent’s Office” shall mean the Administrative Agent’s address and, as appropriate, account as set forth on Schedule 13.2, or such other address or account as the Administrative Agent may from time to time notify in writing to the Borrower and the Lenders.

“Administrative Questionnaire” shall mean, for each Lender, an administrative questionnaire in a form approved by the Administrative Agent.

“Advance” shall mean a borrowing hereunder (i) made by the Lenders on the same Borrowing Date or (ii) converted or continued by Lenders on the same date of continuation or conversion of a previous Advance consisting in either case, of the aggregate amount of the several Loans of the same type and, in the case of LIBOR Loans, for the same Interest Period.  For purposes of this Agreement, Loans may be classified and referred to by Type (e.g., a “LIBOR Loan” for Loans that bear interest at the Adjusted LIBOR Rate or an “ABR Loan” for Loans that bear interest at the Adjusted ABR Rate) and Advances may also be classified and referred to by Type (e.g., a “LIBOR Advance” for Advances that bear interest at the Adjusted LIBOR Rate or an “ABR Advance” for Advances that bear interest at the Adjusted ABR Rate).

“Affected Financial Institution” means (a) any EEA Financial Institution or (b) any UK Financial Institution.

“Affiliate” shall mean, with respect to any Person, any other Person directly or indirectly controlling, controlled by or under direct or indirect common control with such Person. A Person shall be deemed to control another Person if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such other Person, whether through the ownership of voting securities, by contract or otherwise.

“Affiliated Lender” shall mean a Lender that is (i) part of the Apollo Group, (ii) a Permitted Holder or (iii) another Person that is an Affiliate of the Borrower or a Permitted Holder.

“Agreement” shall mean this Credit Agreement, as the same may from time to time be amended, restated, supplemented or otherwise modified.

“Aggregate Elected Commitment Amount” at any time shall equal the sum of the Elected Commitments, as the same may be increased, reduced or terminated pursuant to Section 4.4.  As of the Amendment No. 2 Effective Date, the Aggregate Elected Commitment Amount is $265,000,000.

“Amendment No. 1” shall mean that certain Amendment No.1 to Credit Agreement, dated as of July 12, 2018, by and among, the Borrower, the Guarantors party thereto, the Lenders party thereto and the Administrative Agent.

“Amendment No. 1 Effective Date” shall have the meaning assigned to the term “Amendment Effective Date” as defined in Amendment No. 1.

​ 2

​ “Amendment No. 2” shall mean that certain Amendment No.2 to Credit Agreement, dated as of December 8, 2020, by and among, the Borrower, the Guarantors party thereto, the Lenders party thereto and the Administrative Agent.

“Amendment No. 2 Effective Date” shall have the meaning assigned to the term “Amendment Effective Date” as defined in Amendment No. 2.

“Anti-Corruption Laws” shall mean all laws, rules, and regulations of any jurisdiction applicable to the Borrower or any of its Subsidiaries from time to time concerning or relating to bribery or corruption, including without limitation the United Kingdom Bribery Act of 2010, as amended, and the FCPA.

“Anti-Money Laundering Laws” shall mean any Requirements of Law relating to money laundering or terrorist financing, including, without limitation, the Bank Secrecy Act, 31 U.S.C. sections 5301 et seq.; the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, Pub. L. 107-56 (a/k/a the USA Patriot Act); Laundering of Monetary Instruments, 18 U.S.C. section 1956; Engaging in Monetary Transactions in Property Derived from Specified Unlawful Activity, 18 U.S.C. section 1957; the Financial Recordkeeping and Reporting of Currency and Foreign Transactions Regulations, 31 C.F.R. Part 103.

“Apollo Group” shall mean Apollo Group AP KRP Holdings, L.P., AA Direct, L.P., AIE III Investments, L.P., Apollo Kings Alley Credit SPV, L.P., Apollo SPN Investments I (Credit), LLC, Apollo Thunder Partners, L.P., ATCF Subsidiary (DC), LLC, Apollo Union Street SP, L.P., Zeus Strategic US Holdings, L.P. , Apollo Lincoln Fixed Income Fund, L.P. or Affiliates thereof.

“Apollo Group Preferred Units” shall mean, collectively, (i) the 110,000 Series A Cumulative Convertible Preferred Units of the Borrower purchased and acquired by the Apollo Group pursuant to the Preferred Equity Purchase Agreement and (ii) preferred units in the Borrower with terms identical to the Series A Cumulative Convertible Preferred Units referenced in clause (i) of this definition issued in connection with the Blocker Mergers.

“Applicable Margin” shall mean, for any day, with respect to any ABR Loan or LIBOR Loan, or with respect to the Unused Commitment Fees payable hereunder, as the case may be, the applicable rate per annum set forth in the grid below based upon the Borrowing Base Utilization Percentage in effect on such day:

​ 3

​ Borrowing Base Utilization Grid

Borrowing Base Utilization	LIBOR Margin	ABR<br>Margin	Unused<br>Commitment Fee
˃90% ≤ 100%	400 bps	300 bps	50 bps
˃75%  ≤ 90%	375 bps	275 bps	50 bps
˃50%  ≤ 75%	350 bps	250 bps	50 bps
˃25%  ≤ 50%	325 bps	225 bps	50 bps
≤ 25%	300 bps	200 bps	50 bps

​

Each change in the Unused Commitment Fee Rate or Applicable Margin shall apply during the period commencing on the effective date of such change and ending on the date immediately preceding the effective date of the next such change. Notwithstanding the rates per annum set forth opposite each tier of Borrowing Base Utilization as set forth above, Lenders have no obligation to make any Advances or issue any Letters of Credit if, after giving effect to such Advance or Letter of Credit, the Total Outstandings would exceed the Borrowing Base then in effect.

“Approved Fund” shall mean any fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

“Approved Petroleum Engineer” shall mean (a) Netherland, Sewell & Associates, Inc., (b) W. D. Van Gonten & Co. Petroleum Engineering, (c) Ryder Scott Company, L.P., (d) DeGolyer and MacNaughton, and (e) at the Borrower’s option, any other independent petroleum engineers selected by the Borrower and approved by the Administrative Agent.

“Assignment and Acceptance” shall mean an assignment and acceptance substantially in the form of Exhibit E or such other form as may be approved by the Administrative Agent and the Borrower.

“Authorized Officer” shall mean as to any Person, the President, the Chief Executive Officer, the Chief Financial Officer, the Chief Operating Officer, the Treasurer, the Assistant or Vice Treasurer, the Vice President-Finance and any manager, managing member or general partner, in each case, of such Person, and any other senior officer designated as such in writing to the Administrative Agent by such Person. Any document delivered hereunder that is signed by an Authorized Officer shall be conclusively presumed to have been authorized by all necessary corporate, limited liability company, partnership and/or other action on the part of the Borrower or any other Credit Party and such Authorized Officer shall be conclusively presumed to have acted on behalf of such Person.

“Available Commitment” shall mean, at any time, (a) the Loan Limit in effect at such time minus (b) the Total Outstandings at such time.

“Available Tenor” means, as of any date of determination and with respect to the then-current Benchmark, as applicable, any tenor for such Benchmark or payment period for interest

​ 4

​ calculated with reference to such Benchmark, as applicable, that is or may be used for determining the length of an Interest Period pursuant to this Agreement as of such date and not including, for the avoidance of doubt, any tenor for such Benchmark that is then-removed from the definition of “Interest Period” pursuant to clause (iv) of Section 2.9(d).

“Bail-In Action” shall mean the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an Affected Financial Institution.

“Bail-In Legislation” shall mean, (a) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation rule or requirement for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule and (b) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation or rule applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).

“Bankruptcy Code” shall have the meaning provided in Section 11.5.

“Benchmark” means, initially, USD LIBOR; provided that if a Benchmark Transition Event or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date have occurred with respect to USD LIBOR or the then-current Benchmark, then “Benchmark” means the applicable Benchmark Replacement to the extent that such Benchmark Replacement has replaced such prior benchmark rate pursuant to clause (a) of Section 2.9(d).

“Benchmark Replacement” means, for any Available Tenor, the first alternative set forth in the order below that can be determined by the Administrative Agent for the applicable Benchmark Replacement Date:

(1)        the sum of: (a) Term SOFR and (b) the related Benchmark Replacement Adjustment;

(2)        the sum of: (a) Daily Simple SOFR and (b) the related Benchmark Replacement Adjustment;

(3)        the sum of: (a) the alternate benchmark rate that has been selected by the Administrative Agent and the Borrower as the replacement for the then-current Benchmark for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a replacement benchmark rate or the mechanism for determining such a rate by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention for determining a benchmark rate as a replacement for the then-current Benchmark for U.S. dollar-denominated syndicated credit facilities at such time and (b) the related Benchmark Replacement Adjustment; provided that, in the case of clause (1), such Unadjusted Benchmark Replacement is displayed on a screen or other information service that publishes

​ 5

​ such rate from time to time as selected by the Administrative Agent in its reasonable discretion.

If the Benchmark Replacement as determined pursuant to clause (1), (2) or (3) above would be less than the Floor, the Benchmark Replacement will be deemed to be the Floor for the purposes of this Agreement and the other Credit Documents.

“Benchmark Replacement Adjustment” means, with respect to any replacement of the then current Benchmark with an Unadjusted Benchmark Replacement for any applicable Interest Period and Available Tenor for any setting of such Unadjusted Benchmark Replacement:

(1)        for purposes of clauses (1) and (2) of the definition of “Benchmark Replacement,” the first alternative set forth in the order below that can be determined by the Administrative Agent: (a) the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) as of the Reference Time such Benchmark Replacement is first set for such Interest Period that has been selected or recommended by the Relevant Governmental Body for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement for the applicable Corresponding Tenor; (b) the spread adjustment (which may be a positive or negative value or zero) as of the Reference Time such Benchmark Replacement is first set for such Interest Period that would apply to the fallback rate for a derivative transaction referencing the ISDA Definitions to be effective upon an index cessation event with respect to such Benchmark for the applicable Corresponding Tenor; and

(2)        for purposes of clause (3) of the definition of “Benchmark Replacement,” the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body on the applicable Benchmark Replacement Date or (ii) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement for U.S. dollar denominated syndicated credit facilities at such time;

provided that, in the case of clause (1) above, such adjustment is displayed on a screen or other information service that publishes such Benchmark Replacement Adjustment from time to time as selected by the Administrative Agent in its reasonable discretion.

“Benchmark Replacement Conforming Changes” means, with respect to any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “ABR,” the definition of “Business Day,” the definition of “Interest Period,” timing and frequency of determining rates and making payments of interest, timing of borrowing

​ 6

​ requests or prepayment, conversion or continuation notices, length of lookback periods, the applicability of breakage provisions, the formula for calculating any successor rates identified pursuant to the definition of “Benchmark Replacement”, the formula, methodology or convention for applying the successor Floor to the successor Benchmark Replacement and other technical, administrative or operational matters) that the Administrative Agent decides after consultation with the Borrower may be appropriate to reflect the adoption and implementation of such Benchmark Replacement and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of such Benchmark Replacement exists, in such other manner of administration as the Administrative Agent decides after consultation with the Borrower is reasonably necessary in connection with the administration of this Agreement and the other Credit Documents).

“Benchmark Replacement Date” means the earliest to occur of the following events with respect to the then-current Benchmark:

(1)        in the case of clause (1) or (2) of the definition of “Benchmark Transition Event,” the later of (a) the date of the public statement or publication of information referenced therein and (b) the date on which the administrator of such Benchmark (or the published component used in the calculation thereof) permanently or indefinitely ceases to provide all Available Tenors of such Benchmark (or such component thereof);

(2)        in the case of clause (3) of the definition of “Benchmark Transition Event,” the date of the public statement or publication of information referenced therein; or

(3)        in the case of an Early Opt-in Election, the sixth (6th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, so long as the Administrative Agent has not received, by 4:00 p.m. (New York, New York time) on the fifth (5th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, written notice of objection to such Early Opt-in Election from Lenders comprising the Majority Lenders.

For the avoidance of doubt, (i) if the event giving rise to the Benchmark Replacement Date occurs on the same day as, but earlier than, the Reference Time in respect of any determination, the Benchmark Replacement Date will be deemed to have occurred prior to the Reference Time for such determination and (ii) the “Benchmark Replacement Date” will be deemed to have occurred in the case of clause (1) or (2) with respect to any Benchmark upon the occurrence of the applicable event or events set forth therein with respect to all then-current Available Tenors of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Transition Event” means the occurrence of one or more of the following events with respect to the then-current Benchmark:

(1)        a public statement or publication of information by or on behalf of the administrator of such Benchmark (or the published component used in the calculation thereof)

​ 7

​ announcing that such administrator has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof), permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof);

(2)       a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof), the Board of Governors of the Federal Reserve System, the Federal Reserve Bank of New York, an insolvency official with jurisdiction over the administrator for such Benchmark (or such component), a resolution authority with jurisdiction over the administrator for such Benchmark (or such component) or a court or an entity with similar insolvency or resolution authority over the administrator for such Benchmark (or such component), which states that the administrator of such Benchmark (or such component) has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof) permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof); or

(3)       a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that all Available Tenors of such Benchmark (or such component thereof) are no longer representative.

For the avoidance of doubt, a “Benchmark Transition Event” will be deemed to have occurred with respect to any Benchmark if a public statement or publication of information set forth above has occurred with respect to each then-current Available Tenor of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Unavailability Period” means the period (if any) (x) beginning at the time that a Benchmark Replacement Date pursuant to clauses (1) or (2) of that definition has occurred if, at such time, no Benchmark Replacement has replaced the then-current Benchmark for all purposes hereunder and under any Credit Document in accordance with Section 2.9(d) and (y) ending at the time that a Benchmark Replacement has replaced the then- current Benchmark for all purposes hereunder and under any Credit Document in accordance with this Section titled “Benchmark Replacement Setting.”

“Beneficial Ownership Certification” means a certification regarding beneficial ownership as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation” means 31 C.F.R. § 1010.230.

“Benefited Lender” shall have the meaning provided in Section 13.8.

“Blocker Mergers” shall mean the merger of Merger Sub with certain holders of the Apollo Group Preferred Units.

​ 8

​ “Board” shall mean the Board of Governors of the Federal Reserve System of the United States (or any successor).

“Borrower” shall have the meaning provided in the introductory paragraph hereto.

“Borrowing Base” shall mean, as of any date, the value assigned by the Lenders from time to time to the Borrowing Base Properties, which as of the Amendment No. 2 Effective Date, is $265,000,000, and which shall be maintained, reduced or increased from time to time pursuant to Sections 2.14, 2.15, 2.16 and 2.17 hereof.

“Borrowing Base Deficiency” shall mean, at any time, the amount by which the Total Outstandings exceed the Borrowing Base then in effect.

“Borrowing Base Properties” shall mean the Oil and Gas Properties of the Credit Parties to which Proved Reserves are attributed as evaluated by the Administrative Agent and the Lenders for purposes of establishing the Borrowing Base.

“Borrowing Base Utilization Percentage” shall mean, as of any day, the fraction expressed as a percentage, the numerator of which is the Total Outstandings on such day, and the denominator of which is the Borrowing Base in effect on such day.

“Borrowing Date” shall mean the date elected by Borrower pursuant to Section 2.1 for the making of a Loan.

“Business Day” shall mean any day excluding Saturday, Sunday and any other day on which banking institutions in New York, New York are authorized by law or other governmental actions to close, and, if such day relates to (a) any interest rate settings as to a LIBOR Loan, (b) any fundings, disbursements, settlements and payments in respect of any such LIBOR Loan, or (c) any other dealings pursuant to this Agreement in respect of any such LIBOR Loan, such day shall be a day on which dealings in deposits in Dollars are conducted by and between banks in the London interbank eurodollar market.

“Capital Lease” shall mean any lease of property, real or personal, which would be capitalized on a balance sheet of the lessee prepared in accordance with GAAP.

“Cash Available For Distribution” shall mean, with respect to any fiscal quarter of the Borrower, its cash available for distribution on Kimbell Common Units, calculated by a Financial Officer of the Borrower in a manner materially consistent with past practice and as set forth in public disclosures and in certificates delivered by the Borrower pursuant to this Agreement.

“Cash Balance” shall mean, at any time, the aggregate amount of cash and Liquid Investments, in each case, held and owned by (whether directly or indirectly), credited to the account of, or otherwise reflected as an asset on the balance sheet of, the Credit Parties; provided that any Liquid Investments consisting of Equity Interests issued by an unaffiliated third party received by any Credit Party as consideration for any disposition of assets or property permitted hereunder shall not constitute a portion of the Cash Balance.

“Cash Balance Threshold” shall mean $30,000,000.

​ 9

​ “Cash Collateralize” shall have the meaning provided in Section 3.8(c).

“Cash Management Agreement” shall mean any agreement related to Cash Management Services by and between the Borrower, any Restricted Subsidiary and any Cash Management Bank.

“Cash Management Bank” shall mean any Person that either (a) at the time it provides Cash Management Services, (b) on the Amendment No. 2 Effective Date or (c) at any time after it has provided any Cash Management Services, is a Lender or the Administrative Agent or an Affiliate of a Lender or the Administrative Agent.  For the avoidance of doubt, if any Cash Management Bank ceases to be a Lender or an Affiliate of a Lender, such Person shall not be a Cash Management Bank in respect of any Cash Management Services provided after the date it ceases to be a Lender or Affiliate of a Lender.

“Cash Management Obligations” shall mean the obligations of Borrower or any Restricted Subsidiary to any Lender (or Affiliate of any Lender) in connection with cash management services for collections, other Cash Management Services and for operating, payroll and trust accounts of such Person, including automatic clearing house services, controlled disbursement services, electronic funds transfer services, lockbox services, stop payment services and wire transfer services.

“Cash Management Services” shall mean (a) commercial credit cards, merchant card services, purchase or debit cards, including non-card e-payables services, (b) treasury management services (including controlled disbursement, overdraft, automated clearing house fund transfer services, return items and interstate depository network services) and (c) any other demand deposit or operating account relationships or other cash management services.

“Cash Receipts” shall mean all cash received by or on behalf of the Credit Parties, including without limitation: (a) amounts payable under or in connection with any Oil and Gas Properties; (b) proceeds from Loans; and (c) any other cash received by any of the Credit Parties from whatever source (including amounts received in respect of the liquidation of any Hedge Transaction and amounts received in respect of any disposition of assets), other than amounts described in the definition of “Excluded Accounts” which are deposited in Excluded Accounts.

“Change in Law” shall mean (a) the adoption or implementation of any law, treaty, order, policy, rule or regulation after the Effective Date, (b) any change in any law, treaty, order, policy, rule or regulation or in the interpretation or application thereof by any Governmental Authority after the Effective Date or (c) compliance by any Lender with any guideline, request, directive or order enacted or promulgated after the Effective Date by any central bank or other governmental or quasi-governmental authority (whether or not having the force of law); provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith, and (y) all requests, rules, guidelines, or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Regulations and Supervisory Practices (or any successor or similar authority) or United States or foreign regulatory authorities, in each case pursuant to Basel III, and all guidelines, requests, directives, orders, rules and regulations adopted, implemented, enacted or promulgated in connection therewith shall be

​ 10

​ deemed to have gone into effect after the Effective Date regardless of the date adopted, implemented, enacted or promulgated and shall be included as a Change in Law but only to the extent a Lender is imposing applicable increased costs or costs in connection with capital adequacy or liquidity requirements similar to those described in clauses (a)(ii) and (c) of Section 2.9 generally on other borrowers of loans under United States reserve-based credit facilities.

“Change of Control” shall mean (a) the acquisition of ownership, directly or indirectly, by any Person or group (within the meaning of the Exchange Act as in effect on the date hereof) other than a Permitted Holder (or any intermediate companies owned directly or indirectly by one or more Permitted Holders), of Equity Interests representing more than 50% of the aggregate ordinary voting power represented by the issued and outstanding Equity Interests of the General Partner; (b) the General Partner shall cease to be the general partner of the Borrower; or (c) the Borrower shall cease to possess, directly or indirectly, the power to direct or cause the direction of the management or policies of OpCo, whether through the ability to exercise voting power, by contract or otherwise.

“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time, and any successor statute.

“Co-Documentation Agents” shall mean BBVA USA, Frost Bank and Truist Bank.

“Collateral” shall have the meaning provided for such term in each of the Security Documents and shall include any and all assets securing any or all of the Obligations; provided that with respect to any mortgages, “Collateral,” as defined herein, shall include the “Mortgaged Properties” as defined therein.

“Collateral Coverage Minimum” shall mean that the Mortgaged Properties shall represent, (a) if no Permitted Additional Debt is outstanding, on the Amendment No. 2 Effective Date, at least 60% of the PV-9 of the Credit Parties’ total PDP Reserves, and within 90 days following the Amendment No. 2 Effective Date (or such later date as the Administrative Agent may reasonably agree) 75% of the PV-9 of the Credit Parties’ total PDP Reserves, in each case, included either in the Initial Reserve Report or in the most recent Reserve Report delivered to the Administrative Agent hereunder; and (b) within 15 days (or such later date as the Administrative Agent may reasonably agree) and at all times thereafter that any Permitted Additional Debt has been incurred and remains outstanding, at least 85% of the PV-9 of the Credit Parties’ total PDP Reserves.

“Commitment” shall mean, with respect to each Lender, the amount set forth opposite such Lender’s name on Schedule 13.2 (as such Schedule 13.2 may be amended from time to time in connection with any modification to any Commitment or Total Commitment pursuant to this Agreement) under the caption “Commitment”, as the same may be (a) reduced or terminated from time to time in connection with a reduction or termination of the Total Commitment pursuant to Section 4.2 or Section 4.3, (b) increased from time to time in connection with an increase of the Total Commitment pursuant to Section 4.4, or (c) modified from time to time pursuant to any assignment permitted by Section 13.2.

​ 11

​ “Commitment Percentage” shall mean, at any time, for each Lender, the percentage obtained by dividing (a) such Lender’s Commitment at such time by (b) the amount of the Total Commitment at such time; provided that at any time when the Total Commitment shall have been terminated, each Lender’s Commitment Percentage shall be the percentage obtained by dividing (i) such Lender’s Total Exposure at such time by (ii) the Total Outstandings at such time.  The Commitment Percentage of each Lender as of the Amendment No. 2 Effective Date is set forth opposite such Lender’s name on Schedule 13.2 hereto.

“Commodity Account” has the meaning assigned to such term in the UCC.

“Commodity Exchange Act” shall mean the Commodity Exchange Act (7 U.S.C. § 1 et seq.), as amended from time to time, and any successor statute, or any rule, regulation or order of the U.S. Commodity Futures Trading Commission (or the application or official interpretation of any thereof).

“Compliance Certificate” shall mean a compliance certificate substantially in the form of attached Exhibit “D” signed by an Authorized Officer of Borrower.

“Confidential Information” shall have the meaning provided in Section 13.16.

“Contractual Requirement” shall have the meaning provided in Section 8.3.

“Corresponding Tenor” with respect to any Available Tenor means, as applicable, either a tenor (including overnight) or an interest payment period having approximately the same length (disregarding any Business Day adjustment) as such Available Tenor.

“Credit Documents” shall mean this Agreement, the Guarantee, the Security Documents, each Letter of Credit, any promissory notes issued by the Borrower under this Agreement, and any intercreditor agreement with respect to the Facility entered into on or after the Effective Date to which the Administrative Agent and the Borrower are parties.

“Credit Event” shall mean and include the making (but not the conversion or continuation) of a Loan and the issuance of a Letter of Credit.

“Credit Party” shall mean each of the Borrower and the Guarantors.

“Current Assets” shall mean, as of any date, the current assets which would be reflected on the consolidated balance sheet of Borrower and the Restricted Subsidiaries prepared as of such date in accordance with GAAP; provided that the Borrower’s Current Assets shall include an amount equal to the Available Commitment, and Current Assets shall not include the amount of any non-cash items as a result of the application of FASB ASC 815 and any subsequent amendments thereto or the fair value of any Hedge Transaction or any non-hedge derivative contract (whether deemed effective or non-effective).

“Current Liabilities” shall mean, as of any date of determination, the current liabilities which would be reflected on the consolidated balance sheet of the Borrower and the Restricted Subsidiaries prepared as of such date in accordance with GAAP, but excluding any liabilities as a result of the application of FASB ASC 815 and any subsequent amendments thereto or the fair

​ 12

​ value of any Hedge Transaction or any non-hedge derivative contract (whether deemed effective or non-effective) and excluding the current portion of long-term Indebtedness outstanding under this Agreement.

“Daily Simple SOFR” means, for any day, SOFR, with the conventions for this rate (which will include a lookback) being established by the Administrative Agent and the Borrower in accordance with the conventions for this rate selected or recommended by the Relevant Governmental Body for determining “Daily Simple SOFR” for syndicated business loans; provided, that if the Administrative Agent decides that any such convention is not administratively feasible for the Administrative Agent, then the Administrative Agent, may establish another convention in its reasonable discretion.

“Debt to EBITDAX Ratio” shall mean, as of the last day of any fiscal quarter, the ratio of (i) the Total Net Debt of the Borrower and the Restricted Subsidiaries on a consolidated basis at such date to (ii) EBITDAX for the four fiscal quarter period ended on such date.

“Debtor Relief Laws” shall mean the United States Bankruptcy Code and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization or similar debtor relief laws of the United States or other applicable jurisdiction from time to time in effect.

“Default” shall mean any event, act or condition that with notice or lapse of time, or both, would constitute an Event of Default.

“Default Rate” shall have the meaning provided in Section 2.7(c).

“Defaulting Lender” shall mean any Lender whose acts or failures to act, whether directly or indirectly, cause it to meet any part of the definition of “Lender Default”.

“Deposit Account” has the meaning assigned to such term in the UCC.

“Designated Jurisdiction” shall mean any country, region or territory to the extent that such country, region or territory itself is the subject of any Sanction.

“Designated Person” shall mean a person or entity:

(i)         listed in the annex to, or otherwise the subject of the provisions of any executive order (including but not limited to the Executive Order);

(ii)       named as a “Specially Designated National and Blocked Person” (“SDN”) on the most current list published by OFAC at its official website or any replacement website or other replacement official publication of such list; or is otherwise the subject of any Sanctions Laws and Regulations; or

(iii)      in which an entity or person on the SDN List has 50% or greater ownership interest or that is otherwise controlled by an SDN.

“Determination Date” shall have the meaning provided in Section 2.15.

​ 13

​ “Disposition” shall have the meaning provided in Section 10.2.

“Dispose” or “Disposed of” shall have a correlative meaning to the defined term of “Disposition”.

“Disqualified Capital Stock” shall mean any Equity Interest that, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event, matures or is mandatorily redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock), pursuant to a sinking fund obligation or otherwise, or is convertible or exchangeable for Indebtedness or redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock) at the option of the holder thereof, in whole or in part, on or prior to the date that is 91 days after the earlier of (a) the Maturity Date and (b) the date on which there are no Loans, Letter of Credit Exposure or other Obligations hereunder outstanding and all of the Commitments are terminated. Notwithstanding the foregoing, any Equity Interest that would constitute Disqualified Capital Stock solely because the holders of the Equity Interest have the right to require the Borrower to repurchase or redeem such Equity Interest upon or following the occurrence of a change of control or an asset sale will not constitute Disqualified Capital Stock if the terms of such Equity Interest provide that the Borrower may not repurchase or redeem any such Equity Interest pursuant to such provisions unless such repurchase or redemption complies with Section 10.8 hereof.

“Distressed Person” shall have the meaning provided in the definition of “Lender-Related Distress Event”.

“Dollars” and “$” shall mean dollars in lawful currency of the United States.

“Drawing” shall have the meaning provided in Section 3.4(b).

“Drop-Down Acquisition” shall mean the acquisition by the Borrower or one or more of its Restricted Subsidiaries, in a single transaction or in a series of related transactions, of property or assets from another Person (other than the Borrower or any of its Restricted Subsidiaries), so long as the property or assets being acquired is Oil and Gas Properties (or Equity Interests in Persons owning Oil and Gas Properties) which are used (or intended to be used), as applicable, primarily in its business as a master limited partnership.

“Early Opt-in Election” means, if the then-current Benchmark is USD LIBOR, the occurrence of the following on or after December 31, 2020:

(1)        a notification by the Administrative Agent to (or the request by the Borrower to the Administrative Agent to notify) each of the other parties hereto that at least ten currently outstanding U.S. dollar-denominated syndicated credit facilities in the U.S. syndicated loan market at such time contain (as a result of amendment or as originally executed) a SOFR-based rate (including SOFR, a term SOFR or any other rate based upon SOFR) as a benchmark rate in lieu of USD LIBOR (and such syndicated credit facilities are identified in such notice and are publicly available for review), and

​ 14

​ (2)        the joint election by the Administrative Agent and the Borrower to trigger a fallback from USD LIBOR and the provision by the Administrative Agent of written notice of such election to the Lenders.

“EBITDAX” shall mean, for any period, the Net Income of the Borrower and the Restricted Subsidiaries on a consolidated basis for such period plus, (X) without duplication and to the extent deducted in the calculation of Net Income for such period, (1) income, franchise and similar taxes for such period, (2) interest expense for such period, (3) depletion, depreciation, amortization and other non-cash charges for such period, (4) workover expense for such period, (5) oil and gas exploration expense, including intangible drilling costs and dry hole and abandonment expense, for such period, (6) non-cash losses and charges for such period, (7) extraordinary or non-recurring losses for such period, (8) costs associated with the Transactions and the Borrower’s public company compliance and (9) any reasonable expenses and charges related to any Investment, acquisition, disposition, offering of Equity Interests and any issuance or incurrence of Indebtedness not prohibited hereunder and minus to the extent included in the calculation of Net Income for such period (Y) non-cash gains and extraordinary or non-recurring gains for such period. EBITDAX for any period of measurement may be calculated by the Borrower on a Pro Forma Basis, giving effect to, without duplication, any acquisition of oil and gas properties as if such acquisition occurred on the first day of such period.

“EEA Financial Institution” shall mean (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country” shall mean any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” shall mean any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Effective Date” shall mean January 11, 2017.

“Elected Commitment” means, as to each Lender, the amount set forth opposite such Lender’s name on Schedule 13.2 under the caption “Elected Commitment”, as the same may be increased, reduced or terminated from time to time in connection with an increase, reduction or termination of the Aggregate Elected Commitment Amount pursuant to Section 4.4.

“Elected Commitment Increase Certificate” has the meaning assigned to such term in Section 4.4(b)(iv).

“Electronic Signature” means an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record.

​ 15

​ “Eligible Assignee” shall mean any of (i) a Lender or any Affiliate of a Lender; (ii) a commercial bank organized under the laws of the United States, or any state thereof, and having a combined capital and surplus of at least $100,000,000.00; (iii) a commercial bank organized under the laws of any other country which is a member of the Organization for Economic Cooperation and Development, or a political subdivision of any such country, and having a combined capital and surplus of at least $100,000,000.00, provided that such bank is acting through a branch or agency located in the United States; (iv) a Person that is primarily engaged in the business of commercial lending and that (A) is a subsidiary of a Lender, (B) a subsidiary of a Person of which a Lender is a subsidiary, or (C) a Person of which a Lender is a subsidiary; (v) any other entity (other than a natural person) which is an “accredited investor” (as defined in Regulation D under the Securities Act) which extends credit or buys loans as one of its businesses, including, but not limited to, insurance companies, mutual funds, investments funds and lease financing companies; and (vi) with respect to any Lender that is a fund that invests in loans, any other fund that invests in loans and is managed by the same investment advisor of such Lender or by an Affiliate of such investment advisor (and treating all such funds so managed as a single Eligible Assignee); provided, however, that no Affiliate of Borrower shall be an Eligible Assignee.

“Environmental Claims” shall mean any and all actions, suits, orders, decrees, demands, demand letters, claims, liens, notices of noncompliance, restrictions on use, operations or transferability, violation or potential responsibility or investigation (other than internal reports prepared by or on behalf of the Borrower or any of the Restricted Subsidiaries (a) in the ordinary course of such Person’s business or (b) as required in connection with a financing transaction or an acquisition or disposition of real estate) or proceedings arising under or based upon any Environmental Law or any permit issued, or any approval given, under any such Environmental Law (hereinafter, “Claims”), including, without limitation, (i) any and all Claims by governmental or regulatory authorities for enforcement, cleanup, removal, response, remedial or other actions or damages pursuant to any applicable Environmental Law and (ii) any and all Claims by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief relating to the presence, release or threatened release of Hazardous Materials or arising from alleged injury or threat of injury to health or safety (to the extent relating to human exposure to Hazardous Materials) or the environment including, without limitation, ambient air, surface water, groundwater, land surface and subsurface strata and natural resources such as wetlands.

“Environmental Law” shall mean any applicable Federal, state, foreign or local statute, law, rule, regulation, ordinance, code and rule of common law now or hereafter in effect and in each case as amended, and any binding judicial or administrative interpretation thereof, including any binding judicial or administrative order, consent decree or judgment, relating to the protection of the environment, including, without limitation, ambient air, surface water, groundwater, land surface and subsurface strata and natural resources such as wetlands, or human health or safety (to the extent relating to human exposure to Hazardous Materials), or Hazardous Materials.

“Equity Interests” of any Person shall mean any and all shares, interests, rights to purchase or otherwise acquire, warrants, options, participations or other equivalents of or interests in (however designated) equity or ownership of such Person, including any preferred stock, any limited or general partnership interest and any limited liability company membership interest, and any securities or other rights or interests convertible into or exchangeable for any of the foregoing.

​ 16

​ “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time. Section references to ERISA are to ERISA as in effect on the Effective Date and any subsequent provisions of ERISA amendatory thereof, supplemental thereto or substituted therefor.

“ERISA Affiliate” shall mean each person (as defined in Section 3(9) of ERISA) that together with the Borrower would be deemed to be a “single employer” within the meaning of Section 414(b) or (c) of the Code or, solely for purposes of Section 302 of ERISA and Section 412 of the Code, is treated as a single employer under Section 414 of the Code.

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Event of Default” shall have the meaning provided in Article XI.

“Excess Cash” shall mean, at any time, the amount of the Cash Balance in excess of the Cash Balance Threshold (other than (i) any cash set aside to pay royalty obligations, working interest obligations, production payments, severance taxes and similar obligations of any Credit Party then due and owing to third parties and for which any Credit Party has issued checks or has initiated wires or ACH transfers (or will issue checks or initiate wires or ACH transfers within three (3) Business Days) in order to pay such obligations, (ii) any cash set aside to pay in the ordinary course of business amounts (other than obligations described in clause (i) above) of any Credit Party then due and owing to unaffiliated third parties and for which such Credit Party has issued checks or has initiated wires or ACH transfers in order to pay such amounts), (iii) any cash or Permitted Investments of any Credit Party constituting purchase price deposits held in escrow by an unaffiliated third party pursuant to a binding and enforceable purchase and sale agreement with an unaffiliated third party containing customary provisions regarding the payment and refunding of such deposits, (iv) cash of any Credit Party to be used by any Credit Party within three (3) Business Days to pay the purchase price for any acquisition of any assets or property by any Credit Party pursuant to (A) a binding and enforceable purchase and sale agreement, (B) a signed letter of intent or (C) any unsigned “purchase agreement” or similar documentation which is then being negotiated and will be executed prior to or simultaneously with the closing of such acquisition, (v) any Excluded Equity Proceeds or Excluded Asset Disposition Proceeds held in the Excluded Proceeds Account, (vi) the amount of any Cash Collateral and (vi) the amount of cash set aside to pay any dividend or distribution that has been declared and is unpaid by the Borrower and permitted to be paid under Section 10.8.

“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

“Excluded Accounts” shall mean (i) segregated Deposit Accounts consisting of (and the balance of which consists solely of funds set aside in connection with) payroll accounts and accounts dedicated to the payment of accrued employee benefits, medical, dental and employee benefits claims to employees of the Borrower or its Restricted Subsidiaries, (ii) Deposit Accounts and Securities Accounts containing cash or other property with an aggregate value for all such Deposit Accounts and Securities Accounts of less than $2,000,000, (iii) Deposit Accounts and Securities Accounts containing cash or other property with an aggregate value for all such Deposit

​ 17

​ Accounts and Securities Accounts of greater than $2,000,000 and less than $5,000,000 for a continuous period of up to 60 days and (iv) Deposit Accounts which are used solely as an escrow account or as a fiduciary or trust account or other account that is contractually obligated to be segregated from the other assets of the Borrower and its Restricted Subsidiaries, in each case, for the benefit of unaffiliated third parties.

“Excluded Asset Disposition Proceeds” shall mean cash proceeds and/or marketable securities received by any Credit Party pursuant to a Disposition permitted hereunder, less the amount of any unpaid Borrowing Base Deficiency that results from such Disposition pursuant to the terms hereof.

“Excluded Equity Interests” shall mean (a) any Equity Interests with respect to which, in the reasonable judgment of the Administrative Agent and the Borrower evidenced in writing delivered to the Administrative Agent, the cost or other consequences of pledging such Equity Interests in favor of the Secured Parties under the Security Documents shall be excessive in view of the benefits to be obtained by the Secured Parties therefrom, (b) any Equity Interests to the extent the pledge thereof would be prohibited by any Requirement of Law, (c) any Equity Interests of any Unrestricted Subsidiary, (d) any Equity Interests of any Subsidiary that is not a wholly-owned Subsidiary at the time such Subsidiary becomes a Subsidiary to the extent (A) that a pledge thereof to secure the Obligations is prohibited by any applicable Contractual Requirement (other than customary non-assignment provisions which are ineffective under the UCC or other applicable Requirements of Law), (B) any Contractual Requirement prohibits such a pledge without the consent of any other party; provided that this clause (B) shall not apply if (1) such other party is a Credit Party or a wholly-owned Subsidiary or (2) consent has been obtained to consummate such pledge (it being understood that the foregoing shall not be deemed to obligate the Borrower or any Subsidiary to obtain any such consent) and for so long as such Contractual Requirement or replacement or renewal thereof is in effect, or (C) a pledge thereof to secure the Obligations would give any other party (other than a Credit Party or a wholly-owned Subsidiary) to any Contractual Requirement governing such Equity Interests the right to terminate its obligations thereunder (other than customary non-assignment provisions that are ineffective under the UCC or other applicable Requirement of Law), (e) any Equity Interests of any Subsidiary to the extent that the pledge of such Equity Interests would result in material adverse tax consequences to the Borrower or any Subsidiary as reasonably determined by the Borrower in a writing delivered to the Administrative Agent, and (f) any “Margin Stock” as defined in Regulation U.; provided that, notwithstanding the foregoing, in no event shall the Equity Interests in any Subsidiary that owns any Borrowing Base Properties be Excluded Equity Interests.

“Excluded Equity Proceeds” shall mean cash proceeds from an equity contribution made to, and received by, or an equity issuance by, the Borrower.

“Excluded Proceeds Account” shall mean a segregated Deposit Account established and maintained with the Administrative Agent, which Deposit Account contains only Excluded Equity Proceeds and/or Excluded Asset Disposition Proceeds. Notwithstanding anything herein to the contrary, any use of funds held in the Excluded Proceeds Account: (a) in the case of any such funds that are used, directly or indirectly, to fund a Restricted Payment, shall be deemed to be a utilization of Excluded Equity Proceeds until no Excluded Equity Proceeds remain in such Excluded Proceeds Account, and thereafter shall be deemed to be a utilization of Excluded Asset Disposition Proceeds

​ 18

​ and (b) in the case of any such funds that are used, directly or indirectly, for any purpose other than to fund a Restricted Payment, shall be deemed to be a utilization of Excluded Asset Disposition Proceeds until no Excluded Asset Disposition Proceeds remain in such Excluded Proceeds Account, and thereafter shall be deemed to be a utilization of Excluded Equity Proceeds.

“Excluded Subsidiary” shall mean (a) each Restricted Subsidiary that does not constitute a Material Subsidiary (but only for so long as such Subsidiary does not constitute a Material Subsidiary), (b) each Restricted Subsidiary that is not a wholly owned Subsidiary (other than OpCo and any of its Subsidiaries) on any date such Subsidiary would otherwise be required to become a Guarantor pursuant to the requirements of Section 9.11 (for so long as such Subsidiary remains a non-wholly owned Restricted Subsidiary), (c) each Restricted Subsidiary that is prohibited by any applicable Contractual Requirement or Requirement of Law from guaranteeing or granting Liens to secure the Obligations at the time such Subsidiary becomes a Restricted Subsidiary (and for so long as such restriction or any replacement or renewal thereof is in effect) or that would require consent, approval, license or authorization of a Governmental Authority to guarantee or grant Liens to secure the Obligations at the time such Subsidiary becomes a Restricted Subsidiary (unless such consent, approval, license or authorization has been received), (d) any Unrestricted Subsidiary and (e) any other Restricted Subsidiary with respect to which in the reasonable judgment of the Administrative Agent and the Borrower, the cost or other consequences of providing a Guarantee of the Obligations shall be excessive in view of the benefits to be obtained by the Lenders therefrom.  Notwithstanding anything herein to the contrary, in no event shall OpCo or any Restricted Subsidiary owning Borrowing Base Properties be an Excluded Subsidiary.

“Excluded Swap Obligation” shall mean, with respect to any Guarantor, any Swap Obligation if, and to the extent that, all or a portion of the guarantee of such Guarantor of, or the grant by such Guarantor of a security interest to secure, such Swap Obligation (or any guarantee thereof) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) by virtue of such Guarantor’s failure for any reason to constitute an “eligible contract participant” as defined in the Commodity Exchange Act and the regulations thereunder at the time the guarantee of such Guarantor, or the grant of such security interest by such Guarantor, becomes effective with respect to such Swap Obligation. If a Swap Obligation arises under a master agreement governing more than one swap, such exclusion shall apply only to the portion of such Swap Obligation that is attributable to swaps for which such guarantee or security interest is or becomes illegal.

“Excluded Taxes” shall mean any of the following Taxes imposed on or with respect to, or required to be withheld or deducted from a payment to, the Administrative Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of any Credit Party hereunder or under any other Credit Document, (i) Taxes imposed on or measured by net income or branch profits (however denominated, and including (for the avoidance of doubt) any backup withholding in respect thereof under Section 3406 of the Code or any similar provision of state, local or foreign law), and franchise (or similar) Taxes imposed, in each case, by a jurisdiction (including any political subdivision thereof) as a result of such recipient being organized under the laws of, having its principal office in, or in the case of any Lender, having its applicable lending office in, such jurisdiction, or as a result of any other present or former connection with such jurisdiction (other than any such connection arising solely from this Agreement or any other Credit

​ 19

​ Documents or any transactions contemplated thereunder), (ii) in the case of a Lender, U.S. federal withholding Tax imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan or Commitment pursuant to a law in effect on the date on which (a) such Lender acquires such interest in the Loan or Commitment (other than to the extent such Lender is an assignee of such interest pursuant to a request by the Borrower under Section 13.7) or (b) such Lender designates a new lending office, except in each case to the extent that, pursuant to Section 5.4, amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its lending office, (iii) any withholding Tax imposed on any payment by or on account of any obligation of any Credit Party hereunder or under any other Credit Document that is attributable to the Administrative Agent’s, any Lender’s or any other recipient’s failure to comply with Section 5.4(d) or (iv) any Tax imposed under FATCA.

“Executive Order” shall mean Executive Order No. 13224 on Terrorist Financings: — Blocking Property and Prohibiting Transactions With Persons Who Commit, Threaten To Commit, or Support Terrorism issued on September 23, 2001, as amended by Executive Order No. 13268 and as further amended after the date hereof.

“Existing Credit Agreement” has the meaning assigned to such term in Amendment No. 2.

“Facility” shall mean this Agreement and the Commitments and the extensions of credit made hereunder.

“Fair Market Value” shall mean, with respect to any asset or group of assets on any date of determination, the value of the consideration obtainable in a Disposition of such asset at such date of determination assuming a Disposition by a willing seller to a willing purchaser dealing at arm’s length and arranged in an orderly manner over a reasonable period of time having regard to the nature and characteristics of such asset, as determined by the Borrower in good faith.

“FATCA” shall mean Sections 1471 through 1474 of the Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), or any Treasury regulations promulgated thereunder or official administrative interpretations thereof, any agreements entered into pursuant to Section 1471(b)(1) of the Code, any intergovernmental agreements entered into in connection with the implementation of such Sections of the Code and any fiscal or regulatory legislation, rules or practices adopted pursuant to such intergovernmental agreements.

“FCPA” shall mean the Foreign Corrupt Practices Act of 1977, as amended.

“Federal Funds Effective Rate” shall mean, for any day, the weighted average of the per annum rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers on such day, as published on the next succeeding Business Day by the Federal Reserve Bank of New York or, if such rate is not so published for any date that is a Business Day, the Federal Funds Effective Rate for such day shall be the average rate (rounded upward, if necessary, to a whole multiple of 1/100 of 1%) of the quotations for such day for such transactions received by the Administrative Agent from three Federal Funds brokers of recognized

​ 20

​ standing selected by it; provided that, if the Federal Funds Effective Rate shall be less than zero, such rate shall be deemed to be zero for the purposes of this Agreement.

“Fee Letter” shall mean that certain letter agreement of even date herewith between the Borrower and the Administrative Agent.

“Financial Officer” of any Person shall mean the Chief Financial Officer, principal accounting officer, Treasurer or Assistant Treasurer of such Person.

“Financial Statements” shall mean balance sheets, income statements, statements of cash flows, owners’ equity and appropriate footnotes (for audited financial statements) and schedules, prepared in accordance with GAAP.

“Flood Insurance Regulations” shall mean (i) the National Flood Insurance Act of 1968 as now or hereafter in effect or any successor statute thereto, (ii) the Flood Disaster Protection Act of 1973 as now or hereafter in effect or any successor statute thereto, (iii) the National Flood Insurance Reform Act of 1994 (amending 42 USC 4001 et seq.), as the same may be amended or recodified from time to time, and (iv) the Flood Insurance Reform Act of 2004 and any regulations promulgated thereunder.

“Floor” means the benchmark rate floor, if any, provided in this Agreement initially (as of the execution of this Agreement, the modification, amendment or renewal of this Agreement or otherwise) with respect to the LIBOR Rate or the Federal Funds Effective Rate, as applicable, as of the Benchmark Replacement Date.

“Foreign Lender” shall mean a Lender that is not a U.S. Person.

“Fronting Fee” shall have the meaning provided in Section 4.1((b).

“Funding Date” shall mean February 8, 2017.

“GAAP” shall mean generally accepted accounting principles in the United States, as in effect from time to time.

“General Partner” shall mean Kimbell Royalty GP, LLC, a Delaware limited liability company.

“Governmental Authority” shall mean any nation, sovereign or government, any state, province, territory or other political subdivision thereof, and any entity or authority exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government, including a central bank or stock exchange.

“Guarantee” shall mean the Guarantee made by any Guarantor in favor of the Administrative Agent for the benefit of the Secured Parties substantially in the form of Exhibit B hereto.

“Guarantee Obligations” shall mean, as to any Person, any obligation of such Person guaranteeing or intended to guarantee any Indebtedness of any other Person (the “primary

​ 21

​ obligor”) in any manner, whether directly or indirectly, including any obligation of such Person, whether or not contingent, (a) to purchase any such Indebtedness or any property constituting direct or indirect security therefor, (b) to advance or supply funds (i) for the purchase or payment of any such Indebtedness or (c) otherwise to assure or hold harmless the owner of such Indebtedness against loss in respect thereof.  The amount of any Guarantee Obligation shall be deemed to be an amount equal to the stated or determinable amount of the Indebtedness in respect of which such Guarantee Obligation is made or, if not stated or determinable, the maximum reasonably anticipated liability in respect thereof as determined by such Person in good faith.

“Guarantors” shall mean each Restricted Subsidiary of Borrower that becomes party to the Guarantee.

“Hazardous Materials” shall mean (a) any petroleum or petroleum products, natural gas or natural gas liquids, radioactive materials, friable asbestos or asbestos containing materials, urea formaldehyde foam insulation, transformers or other equipment that contain dielectric fluid containing regulated levels of polychlorinated biphenyls, and radon gas, (b) any chemicals, materials or substances defined as or included in the definition of “hazardous substances”, “hazardous waste”, “hazardous materials”, “extremely hazardous waste”, “restricted hazardous waste”, “toxic substances”, “toxic pollutants”, “contaminants”, or “pollutants”, or words of similar import, under any applicable Environmental Law and (c) any other chemical, material or substance which is prohibited, limited or regulated by any Environmental Law.

“Hedge Bank” shall mean (a) any Person (other than the Borrower or any of its Subsidiaries) that (x) at the time it enters into a Hedge Transaction is the Administrative Agent, an Affiliate of the Administrative Agent, a Lender or an Affiliate of a Lender or (y) at any time after it enters into a Hedge Transaction becomes a Lender or an Affiliate of a Lender or (b) with respect to any Hedge Transaction that is in effect on the Amendment No. 2 Effective Date, any Person (other than the Borrower or any of its Subsidiaries) that is a Lender or an Affiliate of a Lender on the Amendment No. 2 Effective Date.  For the avoidance of doubt, if any Hedge Bank ceases to be a Lender or an Affiliate of a Lender, such Person shall be a Hedge Bank in respect of any Hedge Transaction entered into before the date it ceases to be a Lender or Affiliate of a Lender and shall not be a Hedge Bank in respect of any Hedge Transaction entered into after the date it ceases to be a Lender or Affiliate of a Lender.

“Hedge Termination” shall mean with respect to any Hedge Transaction, any termination (other than a termination that occurs on the date scheduled for such termination and not as a result of any event of default or other event which permits a party to such Hedge Transaction to early terminate such Hedge Transaction, in each case however defined or described), cancellation, novation or other disposition of such Hedge Transaction or the entry into one or more offsetting Hedge Transactions in respect of such Hedge Transaction.

“Hedge Termination Date” shall mean, with respect to any Hedge Transaction, the date of expiration of that particular Hedge Transaction.

“Hedge Transactions” shall mean (a) any and all rate swap transactions, basis swaps, credit derivative transactions, forward rate transactions, commodity swaps, commodity options, forward commodity contracts, future contracts, equity or equity index swaps or options, bond or

​ 22

​ bond price or bond index swaps or options or forward bond or forward bond price or forward bond index transactions, interest rate options, forward foreign exchange transactions, cap transactions, floor transactions, collar transactions, currency swap transactions, cross-currency rate swap transactions, currency options, total return swaps, credit spread transactions, repurchase transactions, reserve repurchase transactions, securities lending transactions, weather index transactions, spot contracts, fixed-price physical delivery contracts, whether or not exchange traded, or any other similar transactions or any combination of any of the foregoing (including any options to enter into any of the foregoing), whether or not any such transaction is governed by or subject to any master agreement, and (b) any and all transactions of any kind, and the related confirmations, which are subject to the terms and conditions of, or governed by, any form of master agreement published by the International Swaps and Derivatives Association, Inc., any International Foreign Exchange Master Agreement or any other master agreement (any such master agreement, together with any related schedules, a “Master Agreement”), including any such obligations or liabilities under any Master Agreement.

“Hedging Obligations” shall mean, with respect to any Person, the obligations of such Person under Hedge Transactions.

“Hydrocarbon Interests” shall mean all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“Hydrocarbons” shall mean oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined or separated therefrom.

“Increasing Lender” has the meaning assigned such term in Section 4.4(a).

“Indebtedness” of any Person shall mean, if and to the extent (other than with respect to clause (e) below) the same would constitute indebtedness or a liability in accordance with GAAP, without duplication, (a) all indebtedness of such Person for borrowed money, (b) all obligations of such Person evidenced by bonds, debentures, notes, loan agreements or other similar instruments, (c) the deferred purchase price of assets or services that in accordance with GAAP would be required to be shown as a liability on the balance sheet of such Person (other than (i) any earn-out obligation until such obligation becomes a liability on the balance sheet of such Person in accordance with GAAP and (ii) obligations resulting under firm transportation contracts or take or pay contracts entered into in the ordinary course of business), (d) the face amount of all letters of credit issued for the account of such Person and, without duplication, all drafts drawn thereunder, (e) all Indebtedness (excluding prepaid interest thereon) described in the other clauses of this definition of any other Person secured by any Lien on any property owned by such Person, whether or not such Indebtedness has been assumed by such Person (but if such Indebtedness has not been assumed, limited to the lesser of the amount of such Indebtedness and the Fair Market Value of the property securing such Indebtedness), (f) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payment, (g) Capital Lease obligations, and (h) without duplication, all Guarantee

​ 23

​ Obligations of such Person in respect of Indebtedness of another Person of the types described in the other clauses of this definition); provided that Indebtedness shall not include (i) trade and other ordinary-course payables and accrued expenses arising in the ordinary course of business, (ii) deferred or prepaid revenues, (iii) purchase price holdbacks in respect of a portion of the purchase price of an asset to satisfy warranty or other unperformed obligations of the respective seller, (iv) in the case of the Borrower and its Subsidiaries, (A) all intercompany Indebtedness having a term not exceeding 364 days (inclusive of any roll-over or extensions of terms) and made in the ordinary course of business and (B) intercompany liabilities in connection with the cash management, tax and accounting operations of the Borrower and its Subsidiaries, (v) production payments and reserve sales, (vi) in-kind obligations relating to net oil, natural gas liquids or natural gas balancing positions arising in the ordinary course of business and (vii) any obligation in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property.

“Indemnified Liabilities” shall have the meaning provided in Section 13.5.

“Indemnified Taxes” shall mean all Taxes imposed on or with respect to or measured by, any payment by or on account of any obligation of any Credit Party hereunder or under any other Credit Document other than (a) Excluded Taxes and (b) Other Taxes.

“Information” shall have the meaning provided in Section 8.8(a).

“Initial Borrowing Base” shall mean the Borrowing Base in effect on the Amendment No. 2 Effective Date, which shall be $265,000,000.

“Initial Reserve Report” shall mean the reserve engineers’ report used to determine the Initial Borrowing Base, prepared as of July 1, 2020, prepared by the Borrower, with respect to the Oil and Gas Properties of the Credit Parties.

“Intercompany Note” means a promissory note substantially in the form of Exhibit H.

“Interest Expense” shall mean, with respect to any Person for any period, the sum of (a) gross interest expense of such Person for such period on a consolidated basis (including (i) the amortization of debt discounts, (ii) the amortization of all fees (including fees with respect to Hedge Transactions) payable in connection with the incurrence of Indebtedness to the extent included in interest expense and (iii) the portion of any payments or accruals with respect to capitalized lease obligations allocable to interest expense) and (b) capitalized interest of such Person. For purposes of the foregoing, gross interest expense shall be determined after giving effect to any net payments made or received and costs incurred by the Borrower with respect to any interest rate Hedge Transactions, and interest on a capitalized lease obligation shall be deemed to accrue at an interest rate reasonably determined by the Borrower to be the rate of interest implicit in such capitalized lease obligation in accordance with GAAP.

​ 24

​ “Interest Period” shall mean, with respect to any Loan, the interest period applicable thereto, as determined pursuant to Section 2.8.

“Investment” shall have the meaning provided in Section 10.15.

“ISDA Definitions” means the 2006 ISDA Definitions published by the International Swaps and Derivatives Association, Inc. or any successor thereto, as amended or supplemented from time to time, or any successor definitional booklet for interest rate derivatives published from time to time by the International Swaps and Derivatives Association, Inc. or such successor thereto.

“ISP” shall mean, with respect to any Letter of Credit, the “International Standby Practices 1998” published by the Institute of International Banking Law & Practice (or such later version thereof as may be in effect at the time of issuance).

“Issuer Documents” shall mean, with respect to any Letter of Credit, the Letter of Credit Application, and any other document, agreement and instrument entered into by the applicable Issuing Bank and the Borrower or in favor of the applicable Issuing Bank and relating to such Letter of Credit.

“Issuing Bank” shall mean (a) the Administrative Agent and Frost Bank, any of their Affiliates or any replacement or successor appointed pursuant to Section 3.6, and (b) if requested by the Borrower and reasonably acceptable to the Administrative Agent, any other Person who is a Lender at the time of such request and who accepts such appointment (it being understood that, if any such Person ceases to be a Lender hereunder, such Person will remain an Issuing Bank with respect to any Letter of Credit issued by such Person that remained outstanding as of the date such Person ceased to be a Lender). References herein and in the other Credit Documents to an Issuing Bank shall be deemed to refer to the Issuing Bank in respect of the applicable Letter of Credit or to all Issuing Banks, as the context requires.

“Joint Lead Arrangers” means BBVA USA, Frost Bank and Truist Bank.

“Kimbell Class B Units” shall mean the Class B Units in the Borrower.

“Kimbell Class B/OpCo Unit for Kimbell Common Unit Exchange” shall mean a transaction whereby a holder of both a Kimbell Class B Unit and a OpCo Common Unit exchanges such Equity Interests for (i) a Kimbell Common Unit and (ii) cash in respect of the dividend and liquidation preferences of the Kimbell Class B Units; provided that the aggregate amount of cash exchanged in connection with Kimbell Class B/OpCo Unit for Kimbell Common Unit Exchanges shall not exceed the aggregate amount of cash contributed to the Borrower by the holders of Kimbell Class B Units in respect of such Kimbell Class B Units**.**

“Kimbell Common Units” shall mean the Common Units in the Borrower.

“Lead Arranger” means Citibank, N.A.

“L/C Borrowing” shall mean an extension of credit resulting from a Drawing under any Letter of Credit which has not been reimbursed on the date when made or refinanced as a Borrowing.

​ 25

​ “L/C Maturity Date” shall mean the date that is five (5) Business Days prior to the Maturity Date.

“L/C Obligations” shall mean, as at any date of determination, the aggregate amount available to be drawn under all outstanding Letters of Credit plus the aggregate amount of all Reimbursement Obligations, including all L/C Borrowings. For all purposes of this Agreement, if on any date of determination a Letter of Credit has expired by its terms but any amount may still be drawn thereunder by reason of the operation of Rule 3.14 of the ISP, such Letter of Credit shall be deemed to be “outstanding” in the amount so remaining available to be drawn.

“L/C Participant” shall have the meaning provided in Section 3.3(a).

“L/C Participation” shall have the meaning provided in Section 3.3(a).

“L/C Sublimit” shall mean (a) (i) for all of the Issuing Banks an aggregate of $10,000,000 or (ii) such greater amount agreed to by the Administrative Agent and the Issuing Banks; provided that in no event shall the L/C Sublimit exceed the Borrowing Base then in effect and (b) for each Issuing Bank the aggregate amount set forth opposite such Issuing Bank’s name in Schedule 1(a) hereto as such amount may be amended or modified from time to time with the consent of the Administrative Agent and the relevant Issuing Bank(s) from time to time.

“Lender” shall have the meaning provided in the introductory paragraph hereto.

“Lender Default” shall mean (i) the refusal or failure of any Lender to make available its portion of any incurrence of Loans or participations in Letters of Credit, which refusal or failure is not cured within two (2) Business Days after the date of such refusal or failure; (ii) the failure of any Lender to pay over to the Administrative Agent, any Issuing Bank, or any other Lender any other amount required to be paid by it hereunder within two (2) Business Days of the date when due, unless the subject of a good faith dispute; (iii) a Lender has notified the Borrower or the Administrative Agent that it does not intend or expect to comply with any of its funding obligations or has made a public statement to that effect with respect to its funding obligations under the Facility; (iv) the failure by a Lender to confirm in a manner reasonably satisfactory to the Administrative Agent that it will comply with its obligations under the Facility, which failure is not cured after the date of such failure; (v) a Distressed Person has admitted in writing that it is insolvent or such Distressed Person becomes subject to a Lender-Related Distress Event or (vi) any Lender that has, or has a direct or indirect parent company that has, become the subject of a Bail-in Action.

“Lender Joinder Agreement” means a joinder agreement in form and substance reasonably satisfactory to the Administrative Agent delivered in connection with Section 4.4.

“Lender-Related Distress Event” shall mean, with respect to any Lender, that such Lender or any Person that directly or indirectly controls such Lender (each, a “Distressed Person”), as the case may be, is or becomes subject to a voluntary or involuntary case with respect to such Distressed Person under any Debtor Relief Law, or a custodian, conservator, receiver or similar official is appointed for such Distressed Person or any substantial part of such Distressed Person’s assets, or such Distressed Person or any Person that directly or indirectly controls such Distressed Person is subject to a forced liquidation, or such Distressed Person makes a general

​ 26

​ assignment for the benefit of creditors or is otherwise adjudicated as, or determined by any Governmental Authority having regulatory authority over such Distressed Person or its assets to be, insolvent or bankrupt; provided that a Lender-Related Distress Event shall not be deemed to have occurred solely by virtue of the ownership or acquisition of any equity interests in any Lender or any Person that directly or indirectly controls such Lender by a Governmental Authority or an instrumentality thereof so long as such ownership interest does not result in or provide such Lender with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Lender.

“Letter of Credit” shall have the meaning provided in Section 3.1(a).

“Letter of Credit Application” shall have the meaning provided in Section 3.2.

“Letter of Credit Exposure” shall mean, with respect to any Lender, at any time, the sum of (a) the principal amount of any Unpaid Drawings in respect of which such Lender has made (or is required to have made) payments to the applicable Issuing Bank pursuant to Section 3.4(a) at such time and (b) such Lender’s Commitment Percentage of the Letters of Credit Outstanding at such time (excluding the portion thereof consisting of Unpaid Drawings in respect of which the Lenders have made (or are required to have made) payments to the applicable Issuing Bank pursuant to Section 3.4(a)) minus the amount of cash or deposit account balances held by the Administrative Agent to Cash Collateralize outstanding Letters of Credit and Unpaid Drawings under Section 3.8.

“Letters of Credit Outstanding” shall mean, at any time, the sum of, without duplication, (a) the aggregate Stated Amount of all outstanding Letters of Credit and (b) the aggregate principal amount of all Unpaid Drawings in respect of all Letters of Credit.

“LIBOR Loan” shall mean any Loan bearing interest at a rate determined by reference to the LIBOR Rate.

“LIBOR Rate” shall mean, for any Interest Period with respect to any Borrowing of a LIBOR Loan, the interest rate per annum appearing on Reuters Screen LIBOR01 Page (or on any successor page or any successor service, or any substitute page or substitute for such service, providing rate quotations comparable to those currently provided on Reuters Screen LIBOR01 Page, as determined by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to Dollar deposits in the London interbank market) at approximately 11:00 a.m., London time, two (2) Business Days prior to the commencement of such Interest Period, as the rate for Dollar deposits with a maturity comparable to such Interest Period. In the event that such rate is not available at such time for any reason, then the “LIBOR Rate” with respect to such Borrowing of such LIBOR Loan for such Interest Period shall be determined by the Administrative Agent by reference to such other comparable publicly available service for displaying the offered rate for Dollar deposits in the London interbank market as may be selected by the Administrative Agent and, in the absence of availability, then such rate shall be the rate at which Dollar deposits of an amount comparable to the Advance of such LIBOR Loan and for a maturity comparable to such Interest Period are offered by the principal office of the

​ 27

​ Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two (2) Business Days prior to the commencement of such Interest Period; provided that, notwithstanding the foregoing, if the LIBOR Rate shall be less than 0.25%, such rate shall be deemed to be 0.25% for the purposes of this Agreement.

“Lien” shall mean, with respect to any asset, any mortgage, deed of trust, lien, notice of claim of lien, hypothecation, pledge, collateral assignment, security interest or similar encumbrance of any kind or character.

“Liquid Investments” shall mean:

(a)        direct obligations of, or obligations the principal of and interest on which are unconditionally guaranteed by, the United States maturing within 270 days from the date of any acquisition thereof;

(b)        (i) negotiable or nonnegotiable certificates of deposit, time deposits, or other similar banking arrangements maturing within 270 days from the date of acquisition thereof or which may be liquidated for the full amount thereof without penalty or premium (“bank debt securities”), issued by (A) any Lender (or any Affiliate of any Lender), or (B) any other bank or trust company so long as either (x) such certificate of deposit is not pledged to secure the Borrower’s or any Subsidiaries’ ordinary course of business bonding requirements, and (y) the amount thereof is less than or equal to $100,000, or any other bank or trust company, if at the time of deposit or purchase, such bank debt securities are rated A or A2 or better by either S&P or Moody’s, and (ii) commercial paper issued by (A) any Lender (or any Affiliate of any Lender) or (B) any other Person if at the time of purchase such commercial paper is rated at the highest credit rating given by either S&P or Moody’s, or upon the discontinuance of both of such services, such other nationally recognized rating service or services, as the case may be, as shall be selected by the Borrower with the consent of the Majority Lenders;

(c)        deposits in money market funds investing exclusively in investments described in clauses (a) and (b) above; and

(d)        repurchase agreements relating to investments described in clauses (a) and (b) above with a market value at least equal to the consideration paid in connection therewith, with any Person who regularly engages in the business of entering into repurchase agreements and has a combined capital and surplus and undivided profit of not less than $500,000,000, if at the time of entering into such agreement such Person is a Lender (or an Affiliate of any Lender) or the debt securities of such Person is rated at the highest credit rating given by either S&P or Moody’s.

“Liquidity” shall mean the sum of (a) the Available Commitment, (b) all unrestricted cash held in deposit accounts of the Borrower or any Restricted Subsidiary and (c) Liquid Investments of the Borrower or any Restricted Subsidiary, and in the case of clauses (b) and (c), which are subject to a Lien in favor of the Administrative Agent securing the Obligations, perfected by an account control agreement with the Administrative Agent or held in a deposit account or securities account maintained with the Administrative Agent and otherwise free and clear of all Liens (other than Permitted Liens).

​ 28

​ “Loan” shall mean the loans made to the Borrower pursuant to Section 2.1 of this Agreement.

“Loan Limit” shall mean, at any time, the lesser of (i) the Total Commitment at such time, (ii) the Borrowing Base at such time (including as it may be reduced pursuant to Sections 2.14, 2.15 or 2.17) or (iii) the Aggregate Elected Commitment Amount at such time.

“Majority Lenders” shall mean, at any date, (a) if there are two or fewer Lenders, all Lenders, (b) if there are three Lenders, Required Lenders and (c) if there are more than three Lenders, (i) Non-Defaulting Lenders (including Administrative Agent as a Lender) having or holding more than 50% of the Adjusted Total Commitment at such date or (ii) if the Total Commitment has been terminated, Non-Defaulting Lenders (including Administrative Agent as a Lender) having or holding more than 50% of the Total Outstandings (excluding the Loans and Letter of Credit Exposure of Defaulting Lenders) in the aggregate at such date.

“Management Services Agreement” shall mean the management services agreement, dated as of the Funding Date, among the Borrower, Kimbell Operating Company, LLC and the other parties thereto.

“Master Assignment Agreement” shall have the meaning provided in Amendment No. 2.

“Material Adverse Effect” shall mean a circumstance or condition affecting the business, assets, operations, properties or financial condition of the Borrower and the Restricted Subsidiaries, taken as a whole, that would, individually or in the aggregate, reasonably be expected to materially adversely affect (a) the ability of the Borrower and the other Credit Parties, taken as a whole, to perform their payment obligations under this Agreement or any of the other Credit Documents or (b) the rights and remedies of the Administrative Agent and the Lenders under this Agreement or under any of the other Credit Documents.

“Material Indebtedness” shall mean Indebtedness (other than Loans and Letters of Credit) of any one or more of the Borrower or any Restricted Subsidiary in an aggregate principal amount exceeding $10,000,000.

“Material Subsidiary” shall mean, as of the date of each Compliance Certificate delivered under Section 9.1(c), each Restricted Subsidiary of the Borrower whose Total Assets (when combined with the assets of such Restricted Subsidiary’s Restricted Subsidiaries, after eliminating intercompany obligations) as at the last day of the four consecutive fiscal quarter period then ended for which the financial statements required pursuant to Section 9.1(a) or (b) have been delivered (or required to be delivered) were equal to or greater than 2% of the Consolidated Total Assets of the Borrower and the Restricted Subsidiaries at such date, determined in accordance with GAAP.

“Maturity Date” shall mean June 7, 2024.

“Maximum Facility Amount” shall mean $500,000,000.

“Maximum Rate” shall mean the maximum rate of interest that the Administrative Agent is permitted to charge to Borrower in compliance with all applicable laws.

​ 29

​ “Moody’s” shall mean Moody’s Investors Service, Inc. or any successor by merger or consolidation to its business.

“Mortgage” shall mean the mortgages, deeds of trust, security agreements, fixture filings, assignments of production and financing statements and amendments and supplements thereto delivered by the Borrower or any of the Restricted Subsidiaries in favor of the Administrative Agent or any trustee for the Administrative Agent.

“Mortgaged Property” shall mean each of the Oil and Gas Properties of the Credit Parties with respect to which a Mortgage has been granted.

“Multiemployer Plan” shall mean a Plan that is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

“Net Income” shall mean, with respect to any Person, the net income (loss) of such Person, determined in accordance with GAAP; provided that in calculating Net Income of the Borrower for any period, there shall be excluded the net income of any Unrestricted Subsidiary or any other Person in which the Borrower or any Restricted Subsidiary has an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of the Borrower and the Restricted Subsidiaries in accordance with GAAP), except, to the extent of the amount of dividends or distributions actually paid in cash during such period by such Unrestricted Subsidiary or such other Person to the Borrower or to a Restricted Subsidiary.

“Non-Consenting Lender” shall have the meaning provided in Section 13.7(b).

“Non-Defaulting Lender” shall mean and include each Lender other than a Defaulting Lender.

“Note” means a promissory note of the Borrower payable to any Lender or its Affiliates in an amount not to exceed the Commitment of such Lender, in substantially the form of attached Exhibit C evidencing indebtedness of the Borrower to such Lender resulting from Advances owing to such Lender.

“Notice of Borrowing” shall mean a request of the Borrower in accordance with the terms of Section 2.1(b) and substantially in the form of Exhibit A or such other form as shall be approved by the Administrative Agent and the Borrower.

“Notice of Conversion or Continuation” shall have the meaning provided in Section 2.5(a).

“NYFRB’s Website” means the website of the NYFRB at http://www.newyorkfed.org, or any successor source.

“Obligations” shall mean all Advances to, and all other obligations of, any Credit Party arising under any Credit Document to pay principal and interest on any Loan and all Reimbursement Obligations in respect of any Letter of Credit and to pay all costs and expenses under the Credit Documents and all Cash Management Obligations and Hedging Obligations, in each case, entered into with the Borrower or any Restricted Subsidiary, whether direct or indirect

​ 30

​ (including those acquired by assumption pursuant to this Agreement), absolute or contingent, due or to become due, now existing or hereafter arising and including interest and fees that accrue after the commencement by or against any Credit Party or any Affiliate thereof in any proceeding under any bankruptcy or insolvency law naming such Person as the debtor in such proceeding, regardless of whether such interest and fees are allowed claims in such proceeding. Without limiting the generality of the foregoing, the Obligations of the Credit Parties under the Credit Documents (and any of their Restricted Subsidiaries to the extent they have obligations under the Credit Documents) include the obligation (including Guarantee Obligations) to pay principal, interest, charges, expenses, fees, attorney costs, indemnities and other amounts payable by any Credit Party under any Credit Document. Notwithstanding the foregoing, (a) the obligations of the Borrower or any Restricted Subsidiary under any Hedge Transaction and under any Cash Management Agreement that has been secured at the option of the Borrower (such option shall be deemed exercised as reflected in the documents related to any such Hedge Transaction or Cash Management Agreement among the Borrower or any Restricted Subsidiary and the applicable Hedge Bank or Cash Management Bank) shall be secured and guaranteed pursuant to the Security Documents and the Guarantee only to the extent that, and for so long as, the other Obligations are so secured and guaranteed; (b) any release of Collateral or Guarantors effected in the manner permitted by this Agreement and the other Credit Documents shall not require the consent of the holders of Hedge Obligations under Hedge Transactions or of the holders of Cash Management Obligations under Cash Management Agreements; and (c) “Obligations” of a Guarantor shall exclude any Excluded Swap Obligations of such Guarantor.

“OFAC” shall have the meaning provided in Section 8.19(b).

“Oil and Gas Properties” shall mean all of the following in which Borrower or any Restricted Subsidiary owns an interest: (i) all oil, gas and/or mineral leases, oil, gas or mineral properties, mineral servitudes and/or mineral rights of any kind (including, without limitation, mineral fee interests, lease interests, farmout interests, overriding royalty and royalty interests, net profits interests, oil payment interests, production payment interests and other types of mineral interests), and all oil and gas gathering, treating, storage, processing and handling assets, (ii) all oil and gas gathering, treating, storage, processing and handling plants and assets,  (iii) all oil or gas pipelines, and (iv) all platforms, wells, wellhead equipment, pumping units, flowlines, tanks, buildings, injection facilities, saltwater disposal facilities, compression facilities, gathering systems, and other equipment.

“OpCo” shall mean Kimbell Royalty Operating, LLC, a Delaware limited liability company.

“OpCo Common Units” shall mean the common units in OpCo.

“OpCo Preferred Units” shall mean, collectively, the convertible preferred units in OpCo in the same number of issued and outstanding units as the Apollo Group Preferred Units and containing terms substantially similar to the Apollo Group Preferred Units, including, with an aggregate liquidation preference equal to the liquidation preference of the Apollo Group Preferred Units.

​ 31

​ “Other Taxes” shall mean any and all present or future stamp, registration, documentary, intangible, recording, filing or any other excise, property or similar Taxes (including related reasonable out-of-pocket expenses with regard thereto) arising from any payment made hereunder or made under any other Credit Document or from the execution or delivery of, registration or enforcement of, consummation or administration of, or otherwise with respect to, this Agreement or any other Credit Document; provided that such term shall not include any of the foregoing Taxes (i) that result from an assignment, grant of a participation pursuant to Section 13.6(c) or transfer or assignment to or designation of a new lending office or other office for receiving payments under any Credit Document (“Assignment Taxes”) to the extent such Assignment Taxes are imposed as a result of a connection between the assignor/participating Lender and/or the assignee/Participant and the taxing jurisdiction (other than a connection arising solely from any Credit Documents or any transactions contemplated thereunder), except to the extent that any such action described in this proviso is requested or required by the Borrower, or (ii) Excluded Taxes.

“Overnight Rate” shall mean, for any day, the greater of (a) the Federal Funds Effective Rate and (b) an overnight rate determined by the Administrative Agent or the applicable Issuing Bank, as the case may be, in accordance with banking industry rules on interbank compensation.

“Participant” shall have the meaning provided in Section 13.6(c).

“Participant Register” shall have the meaning provided in Section 13.6(c).

“Patriot Act” shall have the meaning provided in Section 13.18.

“PBGC” shall mean the Pension Benefit Guaranty Corporation established pursuant to Section 4002 of ERISA, or any successor thereto.

“PDP Reserves” shall mean oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as “Proved Developed Producing Reserves”.

“Permitted Acquisition” shall mean the acquisition, by merger or otherwise, by the Borrower of assets (including any assets constituting a business unit, line of business or division) or Equity Interests, so long as (a) such acquisition and all transactions related thereto shall be consummated in all material respects in accordance with Requirements of Law; (b) if such acquisition involves the acquisition of Equity Interests of a Person that upon such acquisition would become a Restricted Subsidiary, such acquisition shall result in the issuer of such Equity Interests becoming, to the extent required by Section 9.11, a Guarantor; (c) such acquisition shall result in the Administrative Agent, for the benefit of the Secured Parties, being granted a security interest in any Equity Interests or any assets so acquired to the extent required by Section 9.11; (d) after giving effect to such acquisition, no Default or Event of Default shall have occurred and be continuing; (e) after giving effect to such acquisition, the Borrower shall be in compliance with Section 9.16; (f) the Borrower shall be in Pro Forma Compliance after giving effect to such acquisition and (g) no existing Indebtedness for borrowed money of a Person acquired in connection with such acquisition shall be assumed as a direct result of such acquisition.

“Permitted Additional Debt” shall mean unsecured senior, unsecured senior subordinated or unsecured subordinated Indebtedness issued by the Borrower or a Guarantor, (a) the terms of which do not provide for any scheduled repayment, mandatory redemption or sinking fund

​ 32

​ obligation prior to the 91st day after the Maturity Date (other than customary offers to purchase upon a change of control, asset sale or casualty or condemnation event and customary acceleration rights after an event of default), (b) the covenants (other than financial covenants), events of default, guarantees and other terms of which (other than interest rate, fees, funding discounts and redemption or prepayment premiums determined by the Borrower to be “market” rates, fees, discounts and premiums at the time of issuance or incurrence of any such Indebtedness), taken as a whole, are determined by the Borrower to be “market” terms on the date of issuance or incurrence and in any event are not, in the aggregate, materially more restrictive on the Borrower and its Restricted Subsidiaries than the terms of this Agreement as in effect at the time of such issuance or incurrence, (c) the financial covenants of which are not, individually or in the aggregate, more restrictive than the financial covenants contained in this Agreement as in effect at the time of such issuance or incurrence, (d) the terms of which do not contain maintenance financial covenants or require the achievement of any financial performance standards other than as a condition to taking specified actions or as permitted by clause (c) above, (e) if such Indebtedness is senior subordinated or subordinated Indebtedness, the terms of such Indebtedness provide for customary subordination of such Indebtedness to the Obligations and (f) no Restricted Subsidiary of the Borrower (other than a Guarantor or a corporate finance subsidiary who has no operations or assets other than those incidental to the issuance of the Indebtedness) is an obligor under such Indebtedness; provided that a certificate of an Authorized Officer of the Borrower is delivered to the Administrative Agent at least three (3) Business Days prior to the incurrence of such Additional Indebtedness, together with  drafts of the indenture, credit agreement or similar document and any security agreements and guaranty agreements related thereto, stating that the Borrower has determined in good faith that the terms and conditions contained in such documentation satisfy the criteria set forth above.

“Permitted Holders” shall mean each of (a) Kimbell GP Holdings, LLC, (b) Rochelle Royalties, LLC, (c) BGT Investments LLC, (d) Double Eagle Interests, LLC, (e) Robert D. Ravnaas, (f) Brett G. Taylor, (g) Mitch S. Wynne and (h) Ben J. Fortson.

“Permitted Liens” shall mean:

(a)        royalties, overriding royalties, reversionary interests, production payments and similar burdens;

(b)        sales contracts or other arrangements for the sale of production of oil, gas or associated liquid or gaseous hydrocarbons which would not (when considered cumulatively with the matters discussed in clause (a) above) deprive the Borrower or the Restricted Subsidiaries, taken as a whole, of any material right with respect to their assets or properties (except for rights customarily granted with respect to such contracts and arrangements);

(c)        statutory Liens for taxes or other assessments that are not yet delinquent (or that, if delinquent, are being contested in good faith by appropriate proceedings, levy and execution thereon having been stayed and continue to be stayed and for which the Borrower has set aside on its books adequate reserves in accordance with GAAP);

(d)        easements, rights-of-way, servitudes, permits, surface leases and other rights with respect to surface operations, pipelines, grazing, logging, canals, ditches, reservoirs or the like,

​ 33

​ conditions, covenants and other restrictions, and easements of streets, alleys, highways, pipelines, telephone lines, power lines, railways and other easements and rights of way on, over or with respect to the Borrower’s or its Restricted Subsidiaries’ assets or properties and that do not individually or in the aggregate cause a Material Adverse Effect;

(e)        materialman’s, mechanic’s, repairman’s, employee’s, vendor’s, laborer’s, warehouseman’s, carrier’s, pipeline’s, contractor’s, sub-contractor’s, operator’s, non-operator’s (arising under operating or joint operating agreements), and other like Liens (including any financing statements filed in respect thereof) incidental to obligations incurred by the Borrower in connection with the construction, maintenance, development, transportation, processing, storage or operation of the Borrower’s or a Restricted Subsidiary’s assets or properties to the extent not delinquent (or which, if delinquent, are being contested in good faith by appropriate proceedings and for which the Borrower has set aside on its books adequate reserves in accordance with GAAP);

(f)        all contracts, agreements and instruments, and all defects and irregularities and other matters affecting the Borrower’s or its Restricted Subsidiaries’ assets and properties which were in existence at the time Borrower’s or its Restricted Subsidiaries’ assets and properties were originally acquired by the Borrower or such Restricted Subsidiaries and all routine operational agreements entered into in the ordinary course of business, which contracts, agreements, instruments, defects, irregularities and other matters and routine operational agreements are not such as to, individually or in the aggregate, interfere materially with the operation, value or use of the Borrower’s and its Restricted Subsidiaries’ assets and properties, considered in the aggregate;

(g)        liens in connection with workmen’s compensation, unemployment insurance or other social security, old age pension or public liability obligations;

(h)        legal or equitable encumbrances deemed to exist by reason of the existence of any litigation or other legal proceeding or arising out of a judgment or award with respect to which an appeal is being prosecuted in good faith and levy and execution thereon have been stayed and continue to be stayed;

(i)         rights reserved to or vested in any municipality, governmental, statutory or other public authority to control or regulate the Borrower’s or any Restricted Subsidiary’s assets and properties in any manner, and all applicable laws, rules and orders from any Governmental Authority;

(j)         landlord’s liens or Liens to secure performance of tenders, surety bonds, appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the ordinary course of business;

(k)        Liens incurred pursuant to the Security Documents;

(l)         contractual Liens which arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-in and farm-out agreements, division orders, contracts for the sale, transportation or exchange of Oil and Gas Properties, unitization and pooling declarations and agreements, area of mutual

​ 34

​ interest agreements, saltwater or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements which are customary in the oil and gas business;

(m)       judgment and attachment Liens not giving rise to an Event of Default;

(n)        Liens securing Indebtedness permitted under Section 10.7(d), but only on the Property under lease or the Property purchased with such Indebtedness, as applicable;

(o)        other Liens securing obligations that in the aggregate do not exceed $5,000,000 in principal amount at any one time;

(p)        banker’s liens and rights of setoff or similar rights and remedies under statutory or common law or customary account documentation in the ordinary course of business in favor of banks and other financial institutions over any bank accounts of the Borrower and the Restricted Subsidiaries;

(q)        Liens on Equity Interests of Unrestricted Subsidiaries;

(r)        Liens on insurance policies and the proceeds thereof securing the financing of the premiums with respect thereto;

(s)        any inconsequential, insignificant or immaterial Liens against any of the Oil and Gas Properties that are of a type that would be customarily accepted in the oil and gas industry; and

(t)         Liens on Property, other than Oil and Gas Properties, not constituting Collateral securing Indebtedness or other obligations of the Borrower or any Restricted Subsidiary in an aggregate amount not to exceed $3,000,000 at any time.

“Person” shall mean any individual, partnership, joint venture, firm, corporation, limited liability company, association, trust or other enterprise or any Governmental Authority.

“Petroleum Industry Standards” shall mean the definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“Plan” shall mean any multiemployer or single-employer plan, as defined in Section 4001 of ERISA and subject to Title IV of ERISA, that is or was within any of the preceding six plan years maintained or contributed to by (or to which there is or was an obligation to contribute or to make payments to) the Borrower or an ERISA Affiliate.

“Platform” shall means Debt Domain, Intralinks, Syndtrak, DebtX or a similar electronic transmission system.

“Preferred Equity” shall mean Equity Interests of the Borrower that is preferred stock or preferred units, including without limitation the Apollo Group Preferred Units.

​ 35

​ “Preferred Equity Purchase Agreement” shall mean that certain Series A Preferred Unit Purchase Agreement, as dated May 28, 2018 among the Borrower and the Apollo Group, pursuant to which the Apollo Group purchased the Apollo Group Series A Units from the Borrower, as such agreement may be amended, restated, supplemented or otherwise modified from time to time.

“Prime Rate” means the rate of interest per annum announced from time to time by the Administrative Agent to be its prime rate in effect at its principal office in New York, New York.  Each change in the Prime Rate shall be effective from and including the date such change is publicly announced or quoted as being effective.

“Pro Forma Basis” shall mean, as to any Person, for any events as described below that occur subsequent to the commencement of a period for which the financial effect of such events is being calculated, and giving effect to the events for which such calculation is being made, such calculation as will give pro forma effect to such events as if such events occurred on the first day of the four consecutive fiscal quarter period ended on or before the occurrence of such event (the “Reference Period”): (i) in making any determination of EBITDAX, effect shall be given to any Disposition, any acquisition, Investment, capital expenditure, construction, repair, replacement, improvement, development, disposition, merger, amalgamation, consolidation, any dividend, distribution or other similar payment, and any restructurings of the business of the Borrower that the Borrower has determined to make and/or made and are expected to have a continuing impact and are factually supportable, which would include cost savings resulting from head count reduction, closure of facilities and similar operational and other cost savings, which adjustments the Borrower determines are reasonable as set forth in a certificate of a Financial Officer of the Borrower (the foregoing, together with any transactions related thereto or in connection therewith, the “relevant transactions”), in each case that occurred during the Reference Period (or, in the case of determinations made pursuant to the definition of the term “Pro Forma Compliance” or pursuant to Sections 10.2, 10.7 and 10.8 occurring during the Reference Period or thereafter and through and including the date upon which the respective Permitted Acquisition or relevant transaction is consummated), and (ii) in making any determination on a Pro Forma Basis, (y) all Indebtedness (including Indebtedness issued, incurred or assumed as a result of, or to finance, any relevant transactions and for which the financial effect is being calculated, whether incurred under this Agreement or otherwise, but excluding normal fluctuations in revolving Indebtedness incurred for working capital purposes) issued, incurred, assumed or permanently repaid during the Reference Period (or, in the case of determinations made pursuant to the definition of the term “Pro Forma Compliance” or pursuant to Sections 10.2, 10.7 and 10.8 occurring during the Reference Period or thereafter and through and including the date upon which the respective Permitted Acquisition or relevant transaction is consummated) shall be deemed to have been issued, incurred, assumed or permanently repaid at the beginning of such period and (z) Interest Expense of such Person attributable to interest on any Indebtedness, for which pro forma effect is being given as provided in preceding clause (y), bearing floating interest rates shall be computed on a pro forma basis as if the rates that would have been in effect during the period for which pro forma effect is being given had been actually in effect during such periods.  Calculations made pursuant to the definition of the term “Pro Forma Basis” shall be determined in good faith by a Financial Officer of the Borrower and approved by the Administrative Agent and may include, for any fiscal period ending on or prior to the third anniversary of any relevant pro forma event (but not for any fiscal period ending after such third anniversary), adjustments to reflect operating expense reductions and other operating improvements, synergies or cost savings reasonably

​ 36

​ expected to result from such relevant pro forma event (including, to the extent applicable, the Transactions).

“Pro Forma Compliance” shall mean, at any date of determination, that the Borrower shall be in compliance, on a Pro Forma Basis after giving effect on a Pro Forma Basis to the relevant transactions (including the assumption, issuance, incurrence and permanent repayment of Indebtedness), with the Debt to EBITDAX Ratio recomputed as at the last day of the most recently ended fiscal quarter of the Borrower for which the financial statements and certificates required pursuant to Section 9.1(a) or Section 9.1(b) have been or were required to have been delivered; provided that “Pro Forma Compliance” shall include the Debt to EBITDAX Ratio tested without regard to whether or not the Debt to EBITDAX Ratio was or was required to be tested on the applicable quarter-end date pursuant to Section 10.3.

“Projected Cash Available For Distribution” shall mean, with respect to any fiscal quarter of the Borrower, the projected Cash Available For Distribution of the Borrower, as calculated in good faith by a Financial Officer of the Borrower.

“Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, cash, securities, accounts and contract rights.

“Proved Reserves” shall mean, collectively, oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as “Proved Developed Producing Reserves”, “Proved Developed Non-Producing Reserves”, and “Proved Undeveloped Reserves”.

“PV-9” shall mean, with respect to any PDP Reserves expected to be produced from any Borrowing Base Properties, the net present value, discounted at 9% per annum, of the future net revenues expected to accrue to the Borrower’s and the Credit Parties’ collective interests in such reserves during the remaining expected economic lives of such reserves, calculated in accordance with the most recent price deck and other pricing parameters provided to the Borrower by the Administrative Agent pursuant to Sections 2.14 and 2.15.

“Qualified ECP Counterparty” shall mean, in respect of any Swap Obligation, each Credit Party that has total assets exceeding $10,000,000 at the time the relevant guarantee or grant of the relevant security interest becomes effective with respect to such Swap Obligation or such other person as constitutes an “eligible contract participant” under the Commodity Exchange Act or any regulations promulgated thereunder and can cause another person to qualify as an “eligible contract participant” at such time by entering into a keepwell under Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

“Redetermination Date” shall mean, the date that the redetermined Borrowing Base becomes effective pursuant to Section 2.14.

“Redetermination Effective Date” shall have the meaning provided in Amendment No. 2.

“Reference Time” with respect to any setting of the then-current Benchmark means (a) if such Benchmark is USD LIBOR, 11:00 a.m. (London time) on the day that is two London banking

​ 37

​ days preceding the date of such setting, and (b) if such Benchmark is not USD LIBOR, the time determined by the Administrative Agent in its reasonable discretion.

“Register” shall have the meaning provided in Section 13.6(b)(iv).

“Regulation D” shall mean Regulation D of the Board as from time to time in effect and any successor thereto and other regulation or official interpretation of the Board relating to reserve requirements applicable to member banks of the Federal Reserve System.

“Regulation T” shall mean Regulation T of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Regulation U” shall mean Regulation U of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Regulation X” shall mean Regulation X of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Reimbursement Date” shall have the meaning provided in Section 3.4(a).

“Reimbursement Obligations” shall mean, at any time, the obligations of the Borrower with respect to all Letters of Credit then outstanding to reimburse amounts paid by the Issuing Bank with respect to any drawing or drawings under a Letter of Credit.

“Related Parties” shall mean, with respect to any specified Person, such Person’s partners, Affiliates and the partners, managers, directors, officers, employees, agents and members of such Person or such Person’s Affiliates and any Person that possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of such Person, whether through the ability to exercise voting power, by contract or otherwise.

“Relevant Governmental Body” means the Board of Governors of the Federal Reserve System or the Federal Reserve Bank of New York, or a committee officially endorsed or convened by the Board of Governors of the Federal Reserve System or the Federal Reserve Bank of New York, or any successor thereto.

“Reportable Event” shall mean an event described in Section 4043 of ERISA and the regulations thereunder, other than any event as to which the 30-day notice period has been waived.

“Required Cash Collateral Amount” shall have the meaning provided in Section 3.8(c).

“Required Lenders” shall mean, at any date, (a) Non-Defaulting Lenders having or holding at least 66-2/3% of the Adjusted Total Commitment at such date or (b) if the Total Commitment has been terminated, Non-Defaulting Lenders having or holding at least 66-2/3% of the Total Outstandings (excluding the Loans and Letter of Credit Exposure of Defaulting Lenders) in the aggregate at such date; provided that, at any time there are only two Lenders under this Agreement, “Required Lenders” means all Lenders (other than Defaulting Lenders).

​ 38

​ “Requirement of Law” shall mean, as to any Person, any law, treaty, rule, regulation, statute, order, ordinance, decree, judgment, consent decree, writ, injunction, settlement agreement or governmental requirement enacted, promulgated or imposed or entered into or agreed by any Governmental Authority, in each case applicable to or binding upon such Person or any of its property or assets or to which such Person or any of its property or assets is subject.

“Reserve Report” shall have the meaning provided in Section 2.14 hereof.

“Reserve Report Certificate” shall mean a certificate of an Authorized Officer in certifying as to the matters set forth in Section 9.14(c) in such form reasonably acceptable to the Administrative Agent.

“Restricted Payments” shall have the meaning provided in Section 10.8.

“Resolution Authority” means an EEA Resolution Authority or, with respect to any UK Financial Institution, a UK Resolution Authority.

“Restricted Subsidiary” shall mean any Subsidiary of the Borrower that is not an Unrestricted Subsidiary.

“S&P” shall mean Standard & Poor’s Ratings Services or any successor by merger or consolidation to its business.

“Sanction(s)” shall mean any international economic sanction administered or enforced by the United States government (including without limitation, OFAC), the United Nations Security Council, the Norwegian State, the European Union, the Member States of the European Union, Her Majesty’s Treasury or any other relevant sanctions authority.

“Scheduled Redetermination” means determination of the Borrowing Base pursuant to Section 2.14.

“SEC” shall mean the Securities and Exchange Commission or any successor thereto.

“Secured Parties” shall mean, collectively, the Administrative Agent, each Issuing Bank, each Lender, each Hedge Bank that is party to any Hedge Transaction and each Cash Management Bank that is a party to any Cash Management Agreement.

“Securities Account” has the meaning assigned to such term in the UCC.

“Securities Act” shall mean the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

“Security Documents” shall mean, collectively, all deeds of trust, mortgages, security agreements, collateral assignments of production, deposit account control agreements and other instruments granting Liens on any assets of the Borrower or any of its Restricted Subsidiaries that are executed by the Borrower or any of its Restricted Subsidiaries pursuant to Section 9.11 or 9.13 to secure the Obligations of the Borrower or any of its Restricted Subsidiaries under the Credit Documents.

​ 39

​ “SOFR” means, with respect to any Business Day, a rate per annum equal to the secured overnight financing rate for such Business Day published by the SOFR Administrator on the SOFR Administrator’s Website on the immediately succeeding Business Day.

“SOFR Administrator” means the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate).

“SOFR Administrator’s Website” means the website of the Federal Reserve Bank of New York, currently at http://www.newyorkfed.org, or any successor source for the secured overnight financing rate identified as such by the SOFR Administrator from time to time.

“Solvent” shall mean, with respect to any Person on any date of determination, that on such date (i) the fair value of the assets of such Person, at a fair valuation, exceeds the debts and liabilities, direct, subordinated, contingent or otherwise, of such Person; (ii) the present fair saleable value of the property of such Person is greater than the amount that will be required to pay the probable liability of such Person on its debts and other liabilities, direct, subordinated, contingent or otherwise, as such debts and other liabilities become absolute and matured; (iii) such Person does not intend to, and such Person does not believe that it will incur debts beyond such Person’s ability to pay such debts as they mature, taking into account the timing and amounts of cash to be received by such Person and the timing and amounts of cash to be payable on or in respect of their debt; (iv) such Person is able to pay its debts and liabilities, direct, subordinated, contingent or otherwise, as such debts and liabilities become absolute and matured; and (v) such Person does not have unreasonably small capital with which to conduct the businesses in which it is engaged as such businesses are now conducted and are proposed to be conducted.

“Stated Amount” of any Letter of Credit shall mean the maximum amount from time to time available to be drawn thereunder, determined without regard to whether any conditions to drawing could then be met.

“Subsidiary” of any Person shall mean and include (a) any corporation more than 50% of whose Equity Interests of any class or classes having by the terms thereof ordinary voting power to elect a majority of the directors of such corporation (irrespective of whether or not at the time Equity Interests of any class or classes of such corporation shall have or might have voting power by reason of the happening of any contingency) is at the time owned by such Person directly or indirectly through Subsidiaries, (b) any limited liability company, partnership, association, joint venture or other entity of which such Person directly or indirectly through Subsidiaries has more than a 50% equity interest at the time and (c) any partnership, the general partner of which meets the description set forth in either clause (a) or (b) above. Unless otherwise expressly provided, all references herein to a “Subsidiary” shall mean a Subsidiary of the Borrower. OpCo will at all times constitute a “Subsidiary” of the Borrower.

“Subsidiary Guarantor” shall mean each Restricted Subsidiary that is a Guarantor.

“Swap Obligation” means, with respect to any Guarantor, any obligation to pay or perform under any agreement, contract or transaction that constitutes a “swap” within the meaning of section 1a(47) of the Commodity Exchange Act.

​ 40

​ “Swap Termination Value” shall mean, in respect of any one or more Hedge Transactions after taking into account the effect of any legally enforceable netting agreement relating to such Hedge Transactions, (a) for any date on or after the date such Hedge Transactions have been closed out and termination value(s) determined in accordance therewith, such termination value(s), and (b) for any date prior to the date referenced in clause (a), the amount(s) determined as the mark-to-market value(s) for such Hedge Transactions, as determined based upon one or more mid-market or other readily available quotations provided by any recognized dealer in such Hedge Transactions (which may include a Lender or any Affiliate of a Lender).

“Syndication Agent” means Citibank, N.A.

“Taxes” shall mean any and all present or future taxes, duties, levies, imposts, assessments, deductions, withholdings or other similar charges imposed by any Governmental Authority whether computed on a separate, consolidated, unitary, combined or other basis and any interest, fines, penalties or additions to tax with respect to the foregoing.

“Term SOFR” means, for the applicable Corresponding Tenor as of the applicable Reference Time, the forward-looking term rate based on SOFR that has been selected or recommended by the Relevant Governmental Body.

“Total Assets” shall mean, as of any date of determination with respect to any Person, the amount that would, in conformity with GAAP, be set forth opposite the caption “total assets” (or any like caption) on a balance sheet of such Person at such date.

“Total Commitment” shall mean the sum of the Commitments of all of the Lenders.  The Total Commitment as of the Amendment No. 2 Effective Date is $265,000,000.

“Total Debt” shall mean, as of any date of determination, the sum of (without duplication) all Indebtedness (other than letters of credit or bank guarantees, to the extent undrawn) consisting of Capital Lease obligations and Indebtedness for borrowed money of the Borrower and its Restricted Subsidiaries on such date determined on a consolidated basis and in accordance with GAAP (provided that the amount of any Capital Lease obligations or any such Indebtedness issued at a discount to its face value shall be determined in accordance with GAAP).

“Total Exposure” shall mean, with respect to any Lender at any time, the sum of (a) the aggregate principal amount of the Loans of such Lender then outstanding and (b) such Lender’s Letter of Credit Exposure at such time.

“Total Net Debt” shall mean, at any date, Total Debt less up to $25,000,000 of Unrestricted Cash held by the Borrower and the Restricted Subsidiaries on such date.

“Total Outstandings” shall mean, at any time, the total principal balance outstanding on the Loans at any time plus the aggregate Letter of Credit Exposure at such time.

“Transaction Expenses” shall mean any fees or expenses incurred or paid by the Borrower or any of its Restricted Subsidiaries or any of their Affiliates in connection with the Transactions, this Agreement and the other Credit Documents and the transactions contemplated hereby and thereby.

​ 41

​ “Transactions” shall mean, collectively, the consummation of the transactions contemplated by this Agreement, the Credit Documents and the payment of Transaction Expenses.

“Transferee” shall have the meaning provided in Section 13.6(e).

“Type” shall mean, as to any Loan, its nature as an ABR Loan or a LIBOR Loan.

“UCC” shall mean the Uniform Commercial Code as in effect in the State of Texas or of any other state the laws of which are required to be applied in connection with the creation or perfection of any security interests in any Collateral.

“UK Financial Institution” means any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended form time to time) promulgated by the United Kingdom Prudential Regulation Authority) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.

“UK Resolution Authority” means the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.

“Unadjusted Benchmark Replacement” means the applicable Benchmark Replacement excluding the related Benchmark Replacement Adjustment.

“Unfunded Current Liability” of any Plan shall mean the amount, if any, by which the Accumulated Benefit Obligation (as defined under Statement of Financial Accounting Standards No. 87 (“SFAS 87”)) under the Plan as of the close of its most recent plan year, determined in accordance with SFAS 87 as in effect on the date hereof, exceeds the Fair Market Value of the assets allocable thereto.

“United States” or “U.S.” shall mean the United States of America.

“Unpaid Drawing” shall have the meaning provided in Section 3.4(a).

“Unrestricted Cash” shall mean cash or Liquid Investments of the Borrower or any of its Restricted Subsidiaries that would not appear as “restricted” on a consolidated balance sheet of the Borrower or any of its Restricted Subsidiaries; provided that cash or Liquid Investments that would appear as “restricted” on a consolidated balance sheet of Borrower or any of its Restricted subsidiaries solely because such cash or Liquid Investments are subject to a Deposit Account control agreement or a Securities Account control agreement in favor of the Administrative Agent shall constitute Unrestricted Cash hereunder.

“Unrestricted Subsidiary” shall mean any Subsidiary of the Borrower designated as such on Schedule 8.12 from time to time or which the Borrower has designated in writing to the Administrative Agent to be an Unrestricted Subsidiary pursuant to Section 10.17, until such time as the Borrower redesignates such Unrestricted Subsidiary as a Restricted Subsidiary in accordance with this Agreement.

​ 42

​ “Unscheduled Redetermination” shall mean a redetermination of the Borrowing Base made at any time other than on the date set for the regular semi-annual redetermination of the Borrowing Base pursuant to Section 2.14 which is made (A) at the request of the Borrower (but only once between successive Redetermination Dates) or (B) at the request of the Required Lenders (only once between successive Redetermination Dates).

“Unused Commitment Fee” shall have the meaning provided in Section 4.1(a).

“Unused Commitment Fee Rate” shall mean, for any day, with respect to the Available Commitment on such day, the applicable rate per annum set forth next to the row heading “Commitment Fee Rate” in the definition of “Applicable Margin” and based upon the Borrowing Base Utilization Percentage in effect on such day.

“USD LIBOR” means the London interbank offered rate for U.S. dollars.

“U.S. Person” means any Person that is a “United States Person” as defined in Section 7701(a)(30) of the Code.

“Write-Down and Conversion Powers” shall mean, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule and with respect to the United Kingdom, any powers of the applicable Resolution Authority under the Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.

Section 1.2      Other Interpretive Provisions.  With reference to this Agreement and each other Credit Document, unless otherwise specified herein or in such other Credit Document:

(a)        The meanings of defined terms are equally applicable to the singular and plural forms of the defined terms.

(b)        The words “herein”, “hereto”, “hereof” and “hereunder” and words of similar import when used in any Credit Document shall refer to such Credit Document as a whole and not to any particular provision thereof.

(c)        Article, Section, Exhibit and Schedule references are to the Credit Document in which such reference appears.

(d)        The term “including” is by way of example and not limitation.

(e)        The term “documents” includes any and all instruments, documents, agreements, certificates, notices, reports, financial statements and other writings, however evidenced, whether in physical or electronic form.

​ 43

​ (f)        In the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including”; the words “to” and “until” each mean “to but excluding”; and the word “through” means “to and including”.

(g)        Section headings herein and in the other Credit Documents are included for convenience of reference only and shall not affect the interpretation of this Agreement or any other Credit Document.

(h)        Any reference to any Person shall be constructed to include such Person’s successors or assigns (subject to any restrictions on assignment set forth herein) and, in the case of any Governmental Authority, any other Governmental Authority that shall have succeeded to any or all of the functions thereof.

(i)         Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms.

(j)         The word “will” shall be construed to have the same meaning as the word “shall”.

(k)        The words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, whether real, personal, movable or immovable, including cash, securities, accounts and contract rights.

Section 1.3      Accounting Terms.  All accounting terms not specifically or completely defined herein shall be construed in conformity with, and all financial data (including financial ratios and other financial calculations) required to be submitted pursuant to this Agreement shall be prepared in conformity with, GAAP, applied in a manner consistent with the Credit Parties’ past practices, except as otherwise specifically prescribed herein; provided, however, that if the Borrower notifies the Administrative Agent that the Borrower requests an amendment to any provision hereof to eliminate the effect of any change occurring after the Amendment No. 2 Effective Date in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent notifies the Borrower that the Majority Lenders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith. Notwithstanding any other provision contained herein, all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made (i) without giving effect to any election under Accounting Standards Codification 825-10-25 (or any other Accounting Standards Codification or Financial Accounting Standard having a similar result or effect) to value any Indebtedness or other liabilities of the Borrower or any Subsidiary at “fair value”, as defined therein, and (ii) without giving effect to any treatment of Indebtedness in respect of convertible debt instruments under Accounting Standards Codification 470-20 (or any other Accounting Standards Codification or Financial Accounting Standard having a similar result or effect) to value any such Indebtedness in a reduced or bifurcated manner as described therein, and such Indebtedness shall at all times be valued at the full stated

​ 44

​ principal amount thereof. Notwithstanding anything to the contrary in this Agreement or any other Credit Document, for purposes of calculations made pursuant to the terms of this Agreement or any other Credit Document, GAAP will be deemed to treat leases that would have been classified as operating leases in accordance with generally accepted accounting principles in the United States as in effect on December 31, 2015 in a manner consistent with the treatment of such leases under generally accepted accounting principles in the United States as in effect on December 31, 2015, notwithstanding any modifications or interpretive changes thereto that may occur thereafter.

Section 1.4      References to Agreements, Laws, Etc.  Unless otherwise expressly provided herein, (a) references to organizational documents, agreements (including the Credit Documents) and other Contractual Requirements shall be deemed to include all subsequent amendments, restatements, amendment and restatements, extensions, supplements and other modifications thereto, but only to the extent that such amendments, restatements, amendment and restatements, extensions, supplements and other modifications are permitted by any Credit Document and (b) references to any Requirement of Law shall include all statutory and regulatory provisions consolidating, amending, replacing, supplementing or interpreting such Requirement of Law.

Section 1.5      Times of Day.  Unless otherwise specified, all references herein to times of day shall be references to New York, New York (daylight saving or standard, as applicable).

ARTICLE II

AMOUNT AND TERMS OF CREDIT

Section 2.1      The Facility and Commitments .

(a)        Subject to, and upon the terms and conditions set forth herein, each Lender severally, but not jointly, agrees to make Loans to the Borrower, which Loans (i) shall be made to the Borrower from time to time on and after the Amendment No. 2 Effective Date and prior to the Maturity Date, (ii) may, at the option of the Borrower, be incurred and maintained as, and/or converted into, ABR Loans or LIBOR Loans, (iii) may be repaid and reborrowed in accordance with the provisions hereof at any time prior to the Maturity Date, (iv) shall not, for any Lender at any time, after giving effect thereto and to the application of the proceeds thereof, result in such Lender’s Total Exposure at such time exceeding such Lender’s Commitment Percentage at such time of the Loan Limit and (v) shall not, after giving effect thereto and to the application of the proceeds thereof, result in the Total Outstandings at such time exceeding the Loan Limit.  The Obligations of the Borrower hereunder shall be evidenced by this Agreement and the other Credit Documents.  Notwithstanding any other provision of this Agreement, no Loan shall be required to be made hereunder if any Default or Event of Default (as hereinafter defined) has occurred and is continuing.  The aggregate principal amount of each Advance of Loans shall be at least $500,000 or any whole multiples of $100,000 in excess thereof (except for any such Advance in an aggregate amount that is equal to the entire unused balance of the Loan Limit and except for Loans to reimburse the Issuing Bank with respect to any Unpaid Drawing which shall be made in the amounts required by Sections 3.3 or 3.4, as applicable), and in each case shall consist of Loans of the same Type made on the same day by each Lender ratably according to its Commitment Percentage.

​ 45

​ (b)        Whenever the Borrower desires an Advance of a Loan (other than Loans used to reimburse Unpaid Drawings), it shall give the Administrative Agent telegraphic, telex, facsimile or telephone notice of such requested Advance in the form of a Notice of Borrowing, which in the case of telephonic notice, shall be promptly confirmed in writing. Each Notice of Borrowing shall be substantially in the form of Exhibit A attached hereto and shall be received by the Administrative Agent not later than noon (New York, New York time) (i) on the Borrowing Date in the case of an ABR Loan or (ii) three (3) Business Days prior to any proposed Borrowing Date in the case of LIBOR Loans.  Each Notice of Borrowing shall specify (i) the Borrowing Date (which shall be a Business Day), (ii) the principal amount to be borrowed, (iii) the portion of such Advance constituting ABR Loans and/or LIBOR Loans, (iv) if any portion of the proposed Advance is to constitute LIBOR Loans, the Interest Period applicable thereto (if no Interest Period is selected, the Borrower shall be deemed to have selected an Interest Period of one month) and (v) the Cash Balance (without regard to the requested Advance) as of the close of business on the date of the Notice of Borrowing and the reasonably estimated pro forma Cash Balance on the close of business on the Borrowing Date (giving effect to the requested Advance).  Each Notice of Borrowing shall constitute a representation by the Borrower that (a) the amount of the requested Advances shall not cause the Total Outstandings to exceed the Available Commitment (after giving effect to the making of such Loans) and (b) as of the end of the third Business Day on which such requested Advances will be funded, after giving pro forma effect to the requested Advances, the Credit Parties shall not have any Excess Cash.  Neither the Administrative Agent nor any Lender shall incur any liability to the Borrower in acting upon any Notice of Borrowing referred to above which the Administrative Agent or such Lender believes in good faith to have been given by a duly authorized officer or other person authorized to borrow on behalf of the Borrower. Upon funding of Advances by the Lenders under Section 2.3 below and such funds being made available to the Borrower in accordance with this Agreement pursuant to any such Notice of Borrowing, the amount so funded and made available to the Borrower shall constitute a part of the Obligations hereunder.  Loans made to reimburse Unpaid Drawings shall be made upon the notice specified in Section 3.4(a).

(c)        Without in any way limiting the obligation of the Borrower to confirm in writing any notice it may give hereunder by telephone, the Administrative Agent may act prior to receipt of written confirmation without liability upon the basis of such telephonic notice believed by the Administrative Agent in good faith to be from an Authorized Officer of the Borrower.

Section 2.2      Maximum Number of Advances.  More than one Advance may be incurred on any date; provided that at no time shall there be outstanding more than) five (5) Advances of LIBOR Loans under this Agreement.

Section 2.3      Disbursement of Funds .

(a)        No later than 2:00 p.m. (New York, New York time) on the date specified in each Notice of Borrowing, each Lender will make available its Commitment Percentage of each Advance requested to be made on such date in the manner provided below; provided that on the Amendment No. 2 Effective Date, such funds shall be made available

​ 46

​ by 10:00 a.m. (New York, New York time) or such earlier time as may be agreed among the Lenders, the Borrower and the Administrative Agent for the purpose of consummating the Transactions.  The Borrower hereby irrevocably authorizes the Administrative Agent to disburse the proceeds of each Advance in immediately available funds by crediting or wiring such proceeds to the deposit account of the Borrower identified in the most recent Notice of Borrowing delivered by the Borrower to the Administrative Agent or as may be otherwise agreed upon by the Borrower and the Administrative Agent from time to time.

(b)        Each Lender shall make available all amounts it is to fund to the Borrower under any Advance in immediately available funds in Dollars to the Administrative Agent at the Administrative Agent’s Office, and the Administrative Agent will (except in the case of Advances to repay Unpaid Drawings) make available to the Borrower the aggregate of such amounts. Unless the Administrative Agent shall have been notified by any Lender prior to the date of any such Advance (or, with respect to an ABR Loan, the date of such Borrowing prior to 1:00 p.m. (New York, New York time)) that such Lender does not intend to make available to the Administrative Agent its portion of the Advance or Advances to be made on such date, the Administrative Agent may assume that such Lender has made such amount available to the Administrative Agent on such Borrowing Date, and the Administrative Agent, in reliance upon such assumption, may (in its sole discretion and without any obligation to do so) make available to the Borrower a corresponding amount. If such corresponding amount is not in fact made available to the Administrative Agent by such Lender and the Administrative Agent has made available such amount to the Borrower, the Administrative Agent shall be entitled to recover such corresponding amount from such Lender. If such Lender does not pay such corresponding amount forthwith upon the Administrative Agent’s demand therefor the Administrative Agent shall promptly notify the Borrower and the Borrower shall immediately pay such corresponding amount to the Administrative Agent. The Administrative Agent shall also be entitled to recover from such Lender or the Borrower, as the case may be, interest on such corresponding amount in respect of each day from the date such corresponding amount was made available by the Administrative Agent to the Borrower to the date such corresponding amount is recovered by the Administrative Agent, at a rate per annum equal to (i) if paid by such Lender, the Overnight Rate plus any administrative, processing or similar fees customarily charged by the Administrative Agent or (ii) if paid by the Borrower, the then-applicable rate of interest or fees, calculated in accordance with Section 2.7, for the respective Loans.

(c)        Nothing in this Section 2.3 shall be deemed to relieve any Lender from its obligation to fulfill its commitments hereunder or to prejudice any rights that the Borrower may have against any Lender as a result of any default by such Lender hereunder (it being understood, however, that no Lender shall be responsible for the failure of any other Lender to fulfill its commitments hereunder).

Section 2.4      Repayment of Loans; Evidence of Debt.

(a)        The Borrower agrees to repay to the Administrative Agent, for the benefit of the applicable Lenders on the Maturity Date, the then outstanding principal amount of all Loans.

​ 47

​ (b)        Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to the appropriate lending office of such Lender resulting from each Loan made by such lending office from time to time, including the amounts of principal and interest payable and paid to such lending office from time to time under this Agreement.

(c)        The Administrative Agent, on behalf of the Borrower, shall maintain the Register pursuant to Section 13.6(b), and a subaccount for each Lender, in which Register and subaccounts (taken together) shall be recorded (i) the amount of each Loan made hereunder, the Type of each Loan made and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender’s share thereof.

(d)        The entries made in the Register and accounts and subaccounts maintained pursuant to clauses (b) and (c) of this Section 2.4 shall, absent manifest error and to the extent permitted by applicable Requirements of Law, be prima facie evidence of the existence and amounts of the obligations of the Borrower therein recorded; provided, however, that the failure of any Lender or the Administrative Agent to maintain such account, such Register or such subaccount, as applicable, or any error therein, shall not in any manner affect the obligation of the Borrower to repay (with applicable interest) the Loans made to the Borrower by such Lender in accordance with the terms of this Agreement.

(e)        Upon the request of any Lender to Borrower made through the Administrative Agent, the Borrower shall execute and deliver to such Lender (through the Administrative Agent) a Note, which shall evidence the obligation of the Borrower to repay to such Lender its Advances to Borrower in addition to such records maintained by the Administrative Agent.  Each Lender may attach schedules to a Note and endorse thereon the date, Type, amount, currency and maturity of its Advances and payments with respect thereto, but such action or the failure to do so shall not control over the records thereof maintained by the Administrative Agent.

Section 2.5      Conversions and Continuations .

(a)        Subject to the penultimate sentence of this clause (a), (i) the Borrower shall have the option on any Business Day to convert all or a portion of the outstanding principal amount of Loans of one Type into an Advance or Advances of another Type and (ii) the Borrower shall have the option on any Business Day to continue the outstanding principal amount of any LIBOR Loans as LIBOR Loans for an additional Interest Period; provided that (A) ABR Loans may not be converted into LIBOR Loans if an Event of Default is in existence on the date of the conversion and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such conversion, (B) LIBOR Loans may not be continued as LIBOR Loans for an additional Interest Period if an Event of Default is in existence on the date of the proposed continuation and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such continuation, and (C) Borrowings resulting from conversions

​ 48

​ pursuant to this Section 2.5 shall be limited in number as provided in Section 2.2. Each such conversion or continuation shall be effected by the Borrower by giving the Administrative Agent at the Administrative Agent’s Office prior to 1:00 p.m. (New York, New York time) at least (i) three (3) Business Days’, in the case of a continuation of or conversion to LIBOR Loans or (ii) the date of conversion, in the case of a conversion into ABR Loans, prior written notice (or telephonic notice promptly confirmed in writing) (each, a “Notice of Conversion or Continuation”) specifying the Loans to be so converted or continued, the Type of Loans to be converted into or continued and, if such Loans are to be converted into or continued as LIBOR Loans, the Interest Period to be initially applicable thereto (if no Interest Period is selected, the Borrower shall be deemed to have selected an Interest Period of one month). The Administrative Agent shall give each applicable Lender notice as promptly as practicable of any such proposed conversion or continuation affecting any of its Loans.

(b)        If any Event of Default is in existence at the time of any proposed continuation of any LIBOR Loans and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such continuation, such LIBOR Loans shall be automatically converted on the last day of the current Interest Period into ABR Loans. If upon the expiration of any Interest Period in respect of LIBOR Loans, the Borrower has failed to elect a new Interest Period to be applicable thereto as provided in clause (a) above, the Borrower shall be deemed to have elected to convert such Borrowing of LIBOR Loans into a Borrowing of LIBOR Loans with an Interest Period of one month unless a Default or Event of Default is then in existence in which case the Borrower shall be deemed to have elected to convert such Borrowing of LIBOR Loans into a Borrowing of ABR Loans, in each case, effective as of the expiration date of such current Interest Period.

Section 2.6      Pro Rata Borrowings.  Each Borrowing under this Agreement shall be made by the Lenders pro rata on the basis of their applicable Commitment Percentages. It is understood that (a) no Lender shall be responsible for any default by any other Lender in its obligation to make Loans hereunder and that each Lender severally but not jointly shall be obligated to make the Loans provided to be made by it hereunder, regardless of the failure of any other Lender to fulfill its commitments hereunder and (b) failure by a Lender to perform any of its obligations under any of the Credit Documents shall not release any Person from performance of its obligation under any Credit Document.

Section 2.7      Interest .

(a)        The unpaid principal amount of each ABR Loan shall bear interest from the date of the Advance thereof until maturity thereof (whether by acceleration or otherwise) or conversion thereof to a LIBOR Loan, at a rate per annum that shall at all times be the Adjusted ABR Rate in effect from time to time.

(b)        The unpaid principal amount of each LIBOR Loan shall bear interest from the date of the Advance thereof until maturity thereof (whether by acceleration or otherwise) or conversion thereof to an ABR Loan, at a rate per annum that shall at all times be the Adjusted LIBOR Rate in effect from time to time.

​ 49

​ (c)        If (x) all or a portion of (i) the principal amount of any Loan or (ii) any interest payable thereon shall not be paid when due (whether at stated maturity, by acceleration or otherwise) and (y) an Event of Default has occurred and is continuing, such overdue amount shall bear interest at a rate per annum that is (the “Default Rate”) (A) in the case of overdue principal, the rate that would otherwise be applicable thereto plus 2% or (B) in the case of any overdue interest, to the extent permitted by applicable Requirements of Law, the rate described in Section 2.7(a) plus 2%, in each case from the date of such non-payment to the date on which such amount is paid in full (after as well as before judgment).

(d)        Interest on each Loan shall accrue from and including the date of any Advance to but excluding the date of any repayment thereof and shall be payable in Dollars; provided that any Loan that is repaid on the same date on which it is made shall bear interest for one day. Except as provided below, interest shall be payable (i) in respect of each ABR Loan, quarterly in arrears on the last Business Day of each March, June, September and December (ii) in respect of each LIBOR Loan, on the last day of each Interest Period applicable thereto and, in the case of an Interest Period in excess of three months, on each date occurring at three-month intervals after the first day of such Interest Period, (iii) in respect of each Loan, (A) on any prepayment (on the amount prepaid), (B) at maturity (whether by acceleration or otherwise) and (C) after such maturity, on demand.

(e)        All computations of interest hereunder shall be made in accordance with Section 5.5.

(f)        The Administrative Agent, upon determining the interest rate for any Advance of LIBOR Loans, shall promptly notify the Borrower and the relevant Lenders thereof. Each such determination shall, absent clearly demonstrable error, be final and conclusive and binding on all parties hereto.

Section 2.8      Interest Periods.  At the time the Borrower gives a Notice of Borrowing or Notice of Conversion or Continuation in respect of the making of, or conversion into or continuation as, an Advance of LIBOR Loans in accordance with Section 2.1(b) or 2.5(a), the Borrower shall give the Administrative Agent written notice (or telephonic notice promptly confirmed in writing) of the Interest Period applicable to such Borrowing, which Interest Period shall, at the option of the Borrower be (i) a one, two, three or six-month period, as requested by the Borrower.

Notwithstanding anything to the contrary contained above:

(a)        the initial Interest Period for any Borrowing of LIBOR Loans shall commence on the date of such Borrowing (including the date of any conversion from a Borrowing of ABR Loans) and each Interest Period occurring thereafter in respect of such Borrowing shall commence on the day on which the next preceding Interest Period expires;

(b)        if any Interest Period relating to a Borrowing of LIBOR Loans begins on the last Business Day of a calendar month or begins on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period,

​ 50

​ such Interest Period shall end on the last Business Day of the calendar month at the end of such Interest Period;

(c)        if any Interest Period would otherwise expire on a day that is not a Business Day, such Interest Period shall expire on the next succeeding Business Day; provided that, if any Interest Period in respect of a LIBOR Loan would otherwise expire on a day that is not a Business Day, but is a day of the month after which no further Business Day occurs in such month, such Interest Period shall expire on the next preceding Business Day; and

(d)        the Borrower shall not be entitled to elect any Interest Period in respect of any LIBOR Loan if such Interest Period would extend beyond the Maturity Date.

Section 2.9      Increased Costs, Illegality, Benchmark Replacement Setting, Etc.

(a)        In the event that (x) in the case of clause (i) below, the Administrative Agent or (y) in the case of clauses (ii) and (iii) below, any Lender, shall have reasonably determined (which determination shall, absent clearly demonstrable error, be final and conclusive and binding upon all parties hereto):

(i)         on any date for determining the LIBOR Rate for any Interest Period that (A) deposits in the principal amounts of the Loans comprising such LIBOR Advances are not generally available in the relevant market or (B) by reason of any changes arising on or after the Effective Date affecting the interbank LIBOR market, adequate and fair means do not exist for ascertaining the applicable interest rate on the basis provided for in the definition of LIBOR Rate; or

(ii)       that, due to a Change in Law occurring at any time after the Effective Date, which Change in Law shall (A) impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender, (B) subject any Lender to any Tax with respect to any Credit Document or any LIBOR Loan made by it (other than (1) Taxes indemnifiable under Section 5.4, or (2) Excluded Taxes), or (C) impose on any Lender or the London interbank market any other condition, cost or expense affecting this Agreement or LIBOR Loans made by such Lender, which results in the cost to such Lender of making, converting into, continuing or maintaining LIBOR Loans or participating in Letters of Credit (in each case hereunder) increasing by an amount which such Lender reasonably deems material or the amounts received or receivable by such Lender hereunder with respect to the foregoing shall be reduced; or

(iii)      at any time, that the making or continuance of any LIBOR Loan has become unlawful as a result of compliance by such Lender in good faith with any Requirement of Law (or would conflict with any such Requirement of Law not having the force of law even though the failure to comply therewith would not be unlawful);

then, and in any such event, such Lender (or the Administrative Agent, in the case of clause (i) above) shall within a reasonable time thereafter give notice (if by telephone,

​ 51

​ confirmed in writing) to the Borrower and to the Administrative Agent of such determination (which notice the Administrative Agent shall promptly transmit to each of the other Lenders). Thereafter (x) in the case of clause (i) above, LIBOR Loans shall no longer be available until such time as the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice by the Administrative Agent no longer exist (which notice the Administrative Agent agrees to give at such time when such circumstances no longer exist), and any Notice of Borrowing or Notice of Conversion or Continuation given by the Borrower with respect to LIBOR Loans that have not yet been incurred shall be deemed rescinded by the Borrower, (y) in the case of clause (ii) above, the Borrower shall pay to such Lender, promptly (but no later than thirty (30) days) after receipt of written demand therefor such additional amounts as shall be required to compensate such Lender for such increased costs or reductions in amounts receivable hereunder (it being agreed that a written notice as to the additional amounts owed to such Lender, showing in reasonable detail the basis for the calculation thereof, submitted to the Borrower by such Lender shall, absent clearly demonstrable error, be final and conclusive and binding upon all parties hereto) and (z) in the case of clause (iii) above, the Borrower shall take one of the actions specified in Section 2.9(b) as promptly as possible and, in any event, within the time period required by applicable Requirements of Law.

(b)        At any time that any LIBOR Loan is affected by the circumstances described in Section 2.9(a)(ii) or (iii), the Borrower may (and in the case of a LIBOR Loan affected pursuant to Section 2.9(a)(iii) shall) either (i) if the affected LIBOR Loan is then being made pursuant to an Advance, cancel such Advance by giving the Administrative Agent telephonic notice (confirmed promptly in writing) thereof on the same date that the Borrower was notified by a Lender pursuant to Section 2.9(a)(ii) or (iii) or (ii) if the affected LIBOR Loan is then outstanding, upon at least three (3) Business Days’ notice to the Administrative Agent, require the affected Lender to convert each such LIBOR Loan into an ABR Loan; provided that if more than one Lender is affected at any time, then all affected Lenders must be treated in the same manner pursuant to this Section 2.9(b).

(c)        If, after the Effective Date, any Change in Law relating to capital adequacy or liquidity requirements of any Lender or compliance by any Lender or its parent with any Change in Law relating to capital adequacy or liquidity requirements occurring after the Effective Date has or would have the effect of reducing the rate of return on such Lender’s or its parent’s capital or assets as a consequence of such Lender’s commitments or obligations hereunder to a level below that which such Lender or its parent could have achieved but for such Change in Law (taking into consideration such Lender’s or its parent’s policies with respect to capital adequacy or liquidity requirements), then from time to time, promptly (but in any event no later than fifteen (15) days) after written demand by such Lender (with a copy to the Administrative Agent), the Borrower shall pay to such Lender such additional amount or amounts as will compensate such Lender or its parent for such reduction, it being understood and agreed, however, that a Lender shall not be entitled to such compensation as a result of such Lender’s compliance with, or pursuant to any request or directive to comply with, any applicable Requirement of Law as in effect on the Effective Date. Each Lender, upon determining in good faith that any additional amounts will be payable pursuant to this Section 2.9(c), will give prompt written notice thereof to the Borrower, which notice shall set forth in reasonable detail the basis of the

​ 52

​ calculation of such additional amounts, although the failure to give any such notice shall not, subject to Section 2.12, release or diminish the Borrower’s obligations to pay additional amounts pursuant to this Section 2.9(c) upon receipt of such notice.

(d)        Benchmark Replacement Setting

(i)         Benchmark Replacement.

Notwithstanding anything to the contrary herein or in any other Credit Document, if a Benchmark Transition Event or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date have occurred prior to the Reference Time in respect of any setting of the then-current Benchmark, then (x) if a Benchmark Replacement is determined in accordance with clause (1) or (2) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Credit Document in respect of such Benchmark setting and subsequent Benchmark settings without any amendment to, or further action or consent of any other party to, this Agreement or any other Credit Document and (y) if a Benchmark Replacement is determined in accordance with clause (3) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Credit Document in respect of any Benchmark setting at or after 4:00 p.m. (New York, New York time) on the fifth (5th) Business Day after the date notice of such Benchmark Replacement is provided to the Lenders without any amendment to, or further action or consent of any other party to, this Agreement or any other Credit Document so long as the Administrative Agent has not received, by such time, written notice of objection to such Benchmark Replacement from Lenders comprising the Majority Lenders.

If (i) a Benchmark Replacement Date has occurred and the applicable Benchmark Replacement on such Benchmark Replacement Date is a Benchmark Replacement other than the sum of (a) Term SOFR and (b) the related Benchmark Replacement Adjustment; (ii) subsequently, the Relevant Governmental Body recommends for use a forward-looking term based on SOFR and the Borrower requests that the Administrative Agent review the administrative feasibility of such recommended forward-looking term rate for purposes of this Agreement and (iii) following such request from the Borrower, the Administrative Agent determines (in its sole discretion) that such forward-looking term rate is administratively feasible for the Administrative Agent, then the Administrative Agent may (in its sole discretion) provide the Borrower and Lenders with written notice that from and after a date identified in such notice:  (x) a Benchmark Replacement Date shall be deemed to have occurred, the Benchmark Replacement on such Benchmark Replacement Date shall be deemed to be a Benchmark Replacement determined in accordance with clause (1) of the definition of “Benchmark Replacement” under this Section 2.9(d); provided, however, that if upon such Benchmark Replacement Date the Benchmark Replacement Adjustment is unable to be determined in accordance with clause (1) of the definition of “Benchmark Replacement” and the corresponding definition of “Benchmark Replacement Adjustment”, then the Benchmark Replacement Adjustment in effect immediately prior to such new Benchmark Replacement Date shall be utilized for purposes of this Benchmark Replacement (for avoidance of doubt, for purposes of this proviso, such Benchmark Replacement Adjustment shall be the Benchmark Replacement Adjustment which was established in accordance with the definition of “Benchmark Replacement Adjustment” on the date determined in accordance with clauses (1) or (2), as applicable, of the

​ 53

​ definition of “Benchmark Replacement Date” hereunder) and (y) such forward looking term rate shall be deemed to be the forward looking term rate references in the definition of “Term SOFR” for all purposes hereunder or under any Credit Document in respect of any Benchmark setting and any subsequent Benchmark settings, without any amendment to, or further action or consent of any other party to this Agreement or any other Credit Document.  For the avoidance of doubt, if the circumstances described in the immediately preceding sentence shall occur, all applicable provisions set forth in this Section 2.9(d) shall apply with respect to such election of the Administrative Agent as completely as if such forward-looking terms rate was initially determined in accordance with clause (1) of the definition of “Benchmark Replacement”, including, without limitation, the provisions set forth in clauses (b) and (f) of this Section 2.9(d).

(ii)       Benchmark Replacement Conforming Changes.

In connection with the implementation of a Benchmark Replacement, the Administrative Agent and the Borrower will have the right to make Benchmark Replacement Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Credit Document, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement or any other Credit Document.

(iii)      Notices; Standards for Decisions and Determinations.

The Administrative Agent will promptly notify the Borrower and the Lenders of (i) any Benchmark Replacement Date and the related Benchmark Replacement, (ii) the effectiveness of any Benchmark Replacement Conforming Changes, (iii) the removal or reinstatement of any tenor of a Benchmark pursuant to clause (d) below and (iv) the commencement or conclusion of any Benchmark Unavailability Period. For the avoidance of doubt, any notice required to be delivered by the Administrative Agent as set forth in this Section 2.9(d) may be provided, at the option of the Administrative Agent (in its sole discretion), in one or more notices and may be delivered together with, or as part of any amendment which implements any Benchmark Replacement or Benchmark Conforming Changes. Any determination, decision or election that may be made by the Administrative Agent or, if applicable, any Lender (or group of Lenders) pursuant to this Section 2.9(d), including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action or any selection, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party to this Agreement or any other Credit Document, except, in each case, as expressly required pursuant to this Section 2.9(d).

(iv)       Unavailability of Tenor of Benchmark.

Notwithstanding anything to the contrary herein or in any other Credit Document, at any time (including in connection with the implementation of a Benchmark Replacement), (i) if the then-current Benchmark is a term rate (including Term SOFR or USD LIBOR) and either (A) any tenor for such Benchmark is not displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion or (B) the regulatory supervisor for the administrator of such Benchmark has provided a public

​ 54

​ statement or publication of information announcing that any tenor for such Benchmark is or will be no longer representative, then the Administrative Agent may modify the definition of “Interest Period” for any Benchmark settings at or after such time to remove such unavailable or non-representative tenor and (ii) if a tenor that was removed pursuant to clause (i) above either (A) is subsequently displayed on a screen or information service for a Benchmark (including a Benchmark Replacement) or (B) is not, or is no longer, subject to an announcement that it is or will no longer be representative for a Benchmark (including a Benchmark Replacement), then the Administrative Agent may modify the definition of “Interest Period” for all Benchmark settings at or after such time to reinstate such previously removed tenor.

(v)        Benchmark Unavailability Period.

Upon the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period, the Borrower may revoke any request for a LIBOR Loan of, conversion to or continuation of LIBOR Loans to be made, converted or continued during any Benchmark Unavailability Period and, failing that, the Borrower will be deemed to have converted any such request into a request for a Borrowing of or conversion to ABR Loans. During any Benchmark Unavailability Period or at any time that a tenor for the then-current Benchmark is not an Available Tenor, the component of ABR based upon the then-current Benchmark or such tenor for such Benchmark, as applicable, will not be used in any determination of ABR.

(vi)       Disclaimer.

The Administrative Agent does not warrant or accept any responsibility for, and shall not have any liability with respect to (i) the administration, submission or any other matter related to the London interbank offered rate or other rates in the definition of “Adjusted LIBOR Rate” or with respect to any alternative or successor rate thereto, or replacement rate thereof (including, without limitation any Benchmark Replacement implemented hereunder), (ii) the composition or characteristics of any such Benchmark Replacement, including whether it is similar to, or produces the same value or economic equivalence to USD LIBOR (or any other Benchmark) or have the same volume or liquidity as did USD LIBOR (or any other Benchmark), (iii) any actions or use of its discretion or other decisions or determinations made with respect to any matters covered by this Section 2.9 including, without limitation, whether or not a Benchmark Transition Event has occurred, the removal or lack thereof of unavailable or non-representative tenors, the implementation or lack thereof of any Benchmark Replacement Conforming Changes, the delivery or non-delivery of any notices required by clause (d) above or otherwise in accordance herewith, and (iv) the effect of any of the foregoing provisions of this Section 2.9

Section 2.10    Compensation.  If (a) any payment of principal of any LIBOR Loan is made by the Borrower to or for the account of a Lender other than on the last day of the Interest Period for such LIBOR Loan as a result of a payment or conversion pursuant to Section 2.4, 2.5, 2.9, 5.1, 5.2 or 13.5, as a result of acceleration of the maturity of the Loans pursuant to Article XI or for any other reason, (b) any Borrowing of LIBOR Loans is not made on the date specified in a Notice of Borrowing, (c) any ABR Loan is not converted into a LIBOR Loan on the date specified in a Notice of Conversion or Continuation, (d) any LIBOR Loan is not continued as a LIBOR Loan on the date specified in a Notice of Conversion or Continuation or (e) any prepayment of principal of any LIBOR Loan is not made as a result of a withdrawn notice of prepayment pursuant to

​ 55

​ Section 5.1 or 5.2, the Borrower shall after the Borrower’s receipt of a written request by such Lender (which request shall set forth in reasonable detail the basis for requesting such amount) pay to the Administrative Agent (within fifteen days after such request) for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that such Lender may reasonably incur as a result of such payment, failure to convert, failure to continue or failure to prepay, including any loss, cost or expense (excluding loss of anticipated profits) actually incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such LIBOR Loan.

Section 2.11    Change of Lending Office.  Each Lender agrees that, upon the occurrence of any event giving rise to the operation of Section 2.9(a)(ii), 2.9(a)(iii), 2.9(c), 3.5 or 5.4 with respect to such Lender, it will, if requested by the Borrower use reasonable efforts (subject to overall policy considerations of such Lender) to designate another lending office for any Loans affected by such event; provided that such designation does not cause such Lender or its lending office to suffer any economic, legal or regulatory disadvantage, with the object of avoiding the consequence of the event giving rise to the operation of any such Section. Nothing in this Section 2.11 shall affect or postpone any of the obligations of the Borrower or the right of any Lender provided in Section 2.9, 3.5 or 5.4.

Section 2.12    Notice of Certain Costs.  Notwithstanding anything in this Agreement to the contrary, to the extent any notice required by Section 2.9, 2.10, 3.5 or 5.4 is given by any Lender more than 180 days after such Lender has knowledge (or should have had knowledge) of the occurrence of the event giving rise to the additional cost, reduction in amounts, loss, tax or other additional amounts described in such Sections, such Lender shall not be entitled to compensation under Section 2.9, 2.10, 3.5 or 5.4, as the case may be, for any such amounts incurred or accruing prior to the 181st day prior to the giving of such notice to the Borrower; provided that if the circumstance giving rise to such claim is retroactive, then such 180-day period referred to above shall be extended to include the period of retroactive effect thereof.

Section 2.13    The Borrowing Base.  At the Amendment No. 2 Effective Date, the Borrowing Base shall be $265,000,000.  The Borrowing Base may be adjusted from time to time pursuant to Sections 2.14, 2.15, 2.16 and 2.17 hereof.

Section 2.14   Scheduled Determinations of Borrowing Base.  Subsequent determinations of the Borrowing Base shall be made by Lenders semi-annually effective on or about May 1 and November 1 of each year, beginning May 1, 2021, or such earlier date requested by the Borrower (each a “Redetermination Date”) or as Unscheduled Redeterminations, each based on an engineering report (each a “Reserve Report”) delivered to the Administrative Agent in form and substance reasonably satisfactory to the Administrative Agent, and prepared with respect to the reserve report for the May 1 redetermination, by an Approved Petroleum Engineer, and prepared with respect to the November 1 redetermination, by the Borrower (or by such Approved Petroleum Engineer), said Reserve Reports (i) to utilize economic, price deck and other pricing parameters used by the Administrative Agent in good faith in accordance with its usual and customary oil and gas lending criteria as it exists at the particular time, together with such other information, reports and data concerning the value of the Borrowing Base Properties as the Administrative Agent or any Lender shall deem reasonably necessary to determine the value of such Borrowing Base Properties.  Borrower shall deliver the Reserve Report to the Administrative

​ 56

​ Agent (i) on or about (but not after) April 1 of each year, beginning April 1, 2021, for the May 1 Redetermination Date, (ii) on or about (but not after) October 1 of each year, beginning October 1, 2021, for the November 1 Redetermination Date and (iii) within forty-five (45) days after either (a) receipt of notice that Required Lenders require an Unscheduled Redetermination, or (b) Borrower gives notice to the Administrative Agent that the Borrower wishes to have an Unscheduled Redetermination performed. The Reserve Report prepared for the May 1 Redetermination Date shall be dated effective as of February 1 of each year and the Reserve Report prepared for the November 1 Redetermination Date shall be dated effective as of August 1 of each year. Upon receipt of each such Reserve Report, the Lenders shall make a Redetermination of the Borrowing Base in accordance with standard practices at the time for reserve based loans.  It is expressly understood that the Lenders have no obligation to designate the Borrowing Base at any particular amount, except in the exercise of their discretion, whether in relation to the Commitment or otherwise.

Section 2.15    Unscheduled Redeterminations of the Borrowing Base.  Within thirty (30) days after either (i) receipt of notice from the Administrative Agent that the Required Lenders require an Unscheduled Redetermination, or (ii) the Borrower gives notice to the Administrative Agent of its desire to have an Unscheduled Redetermination performed, in each case the Borrower shall furnish to the Administrative Agent a Reserve Report prepared by petroleum engineers employed by the Borrower (or by an Approved Petroleum Engineer) in form and substance reasonably satisfactory to the Administrative Agent, said engineering report to utilize economic, price deck and other pricing parameters used by the Administrative Agent or any Lender as established from time to time, together with such other information, reports and data concerning the value of the Borrowing Base Properties.  The Administrative Agent shall by written notice to the Borrower within a reasonable time after the provision of all such information, reports and data (the date of such notice being herein called the “Determination Date”) notify the Borrower of the designation of the new Borrowing Base for the period beginning on such Determination Date and continuing until, but not including, the next Redetermination Date or Determination Date.  If the Borrower does not furnish all such information, reports and data by any date specified in this Section 2.15, unless such failure is of no fault of the Borrower, the Lenders nonetheless shall designate the Borrowing Base at any amount which the Lenders in their sole discretion determine and redesignate the Borrowing Base from time to time thereafter until the Administrative Agent receives all such information, reports and data, whereupon the Lenders shall designate a new Borrowing Base, as described above.  In addition to, and not including and/or limited by the Unscheduled Redeterminations allowed above, the Borrower may, by notifying the Administrative Agent thereof, at any time between Scheduled Redeterminations, request additional Redeterminations of the Borrowing Base in the event the Borrower or any other Credit Party acquires in one or more transactions Oil and Gas Properties with PDP Reserves that are to be Borrowing Base Properties having, in the aggregate, a PV-9 (calculated at the time of such acquisitions) in excess of 20% of the Borrowing Base in effect immediately prior to such acquisitions.

Section 2.16    Procedure.  The procedure for determining the Borrowing Base at each redetermination shall be that the Administrative Agent shall determine the Borrowing Base and submit the same to the Lenders. Increases in the Borrowing Base will require approval of all the Lenders, but other reaffirmations or changes in the Borrowing Base will be subject to the approval of Required Lenders. The  Lenders (in the case of a proposed increase to the Borrowing Base) or

​ 57

​ Required Lenders (in the case of a proposed reaffirmation or reduction to the Borrowing Base) shall approve or reject the Administrative Agent’s initial determination of the proposed Borrowing Base by written notice to the Administrative Agent on or about fifteen (15) days after the Administrative Agent’s notification of its initial determination; provided, however that, the failure by any Lender to confirm or reject in writing the Administrative Agent’s determination of the proposed Borrowing Base within such period shall be deemed an approval of the such proposed Borrowing Base by such Lender.  If Lenders (in the case of a proposed increase to the Borrowing Base) or Required Lenders (in the case of a proposed reaffirmation or reduction to the Borrowing Base) fail to approve any such proposed Borrowing Base determined by the Administrative Agent hereunder in such period, then the Administrative Agent shall poll the Lenders to ascertain the highest proposed Borrowing Base then acceptable to Lenders (in the case of a proposed increase to the Borrowing Base) or Required Lenders (in the case of a proposed reaffirmation or reduction to the Borrowing Base) for purposes of this Section 2.16, such amounts shall become the new Borrowing Base, effective on the date specified in this Section 2.16.  Until such approval or deemed approval, the Borrowing Base in effect before the proposed Borrowing Base shall remain in effect.  Upon agreement by the Administrative Agent and the Lenders (in the case of a proposed increase to the Borrowing Base) or Required Lenders (in the case of a proposed reaffirmation or reduction to the Borrowing Base) of the new Borrowing Base, the Administrative Agent shall, by written notice to the Borrower and the Lenders, designate the new Borrowing Base available to the Borrower.  Such designation shall be effective as of the Business Day specified in such written notice (or, if no effective date is specified in such written notice, the next Business Day following delivery of such written notice) and such new Borrowing Base shall remain in effect until the next determination or redetermination of the Borrowing Base in accordance with this Agreement.

Section 2.17    Reduction of Borrowing Base upon Sale of Borrowing Base Properties or Equity Interests in Restricted Subsidiaries, Hedge Terminations and Issuance of Permitted Additional Debt .

(a)        Sale of Borrowing Base Properties.  If (i) the Borrower or a Credit Party Disposes of Borrowing Base Properties included in the most recently delivered Reserve Report or Disposes of any Equity Interests in any Restricted Subsidiary owning any Borrowing Base Properties included in the most recently delivered Reserve Report or if the Borrower or a Credit Party effects any Hedge Termination and (ii) the aggregate value attributed in the most recent Reserve Report to all such Borrowing Base Properties Disposed of, when combined with the aggregate Borrowing Base value (as determined by the Administrative Agent) of all such Hedge Transactions subject of Hedge Terminations, in each case since the latest of (A) the Amendment No. 2 Effective Date, (B) the most recent scheduled Redetermination Date or Determination Date and (C) the last adjustment of the Borrower Base made pursuant to this Section 2.17(a), exceeds five percent (5%) of the then-effective Borrowing Base, individually or in the aggregate, then the Required Lenders shall have the right to adjust the Borrowing Base in an amount equal to the Borrowing Base value, if any, attributable to (i) such Disposed of Borrowing Base Properties and (ii) such Hedge Transactions subject of Hedge Terminations in the calculation of the then-effective Borrowing Base and, if the Required Lenders in fact make any such adjustment, the Administrative Agent shall promptly notify the Borrower in writing of the Borrowing Base value, if any, attributable to such Disposed of Borrowing

​ 58

​ Base Properties in the calculation of the then-effective Borrowing Base and upon receipt of such notice, the Borrowing Base shall be simultaneously reduced by such amount;

(b)        [Reserved]; and

(c)        Reduction of Borrowing Base Upon Issuance of Permitted Additional Debt.  Upon the issuance or incurrence of any Permitted Additional Debt (other than any Permitted Additional Debt to the extent the proceeds thereof are used to refinance any other Permitted Additional Debt) in accordance with Section 10.7(g), the Borrowing Base then in effect shall be reduced by an amount equal to the product of 0.25 multiplied by the stated principal amount of such Permitted Additional Debt (without regard to any original issue discount), and the Borrowing Base as so reduced shall become the new Borrowing Base immediately upon the date of such issuance or incurrence, effective and applicable to the Borrower, the Administrative Agent, the Issuing Bank and the Lenders on such date until the next redetermination or modification thereof hereunder.

Section 2.18    Defaulting Lenders.  Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes a Defaulting Lender, then the following provisions shall apply for so long as such Lender is a Defaulting Lender:

(a)        Commitment Fees shall cease to accrue on the unfunded portion of the Commitment of such Defaulting Lender pursuant to Section 4.1(a);

(b)        The Commitment and Total Exposure of such Defaulting Lender shall not be included in determining whether all Lenders or the Majority Lenders have taken or may take any action hereunder (including any consent to any amendment or waiver pursuant to Section 13.1); provided that (i) any waiver, amendment or modification requiring the consent of all Lenders pursuant to Section 13.1 (other than Section 13.1(a)(J)) or requiring the consent of each affected Lender pursuant to Section 13.1(a)(A) shall require the consent of such Defaulting Lender (which for the avoidance of doubt would include any change to the Maturity Date applicable to such Defaulting Lender, decreasing or forgiving any principal or interest due to such Defaulting Lender, any decrease of any interest rate applicable to Loans made by such Defaulting Lender (other than the waiving of post-default interest rates) and any increase in such Defaulting Lender’s Commitment) and (ii) any redetermination, whether an increase, decrease or affirmation, of the Borrowing Base shall occur without the participation of a Defaulting Lender, but the Commitment (i.e., the Commitment Percentage of the Borrowing Base) of a Defaulting Lender may not be increased without the consent of such Defaulting Lender;

(c)        If any Letter of Credit Exposure exists at the time a Lender becomes a Defaulting Lender, then all or any part of such Letter of Credit Exposure of such Defaulting Lender will, subject to the limitation in the first proviso below, automatically be reallocated (effective on the day such Lender becomes a Defaulting Lender) among the Non-Defaulting Lenders pro rata in accordance with their respective Commitment Percentages; provided that (i) each Non-Defaulting Lender’s Total Exposure may not in any event exceed the Commitment of such Non-Defaulting Lender as in effect at the time of such reallocation and (ii) neither such reallocation nor any payment by a Non-Defaulting Lender

​ 59

​ pursuant thereto will constitute a waiver or release of any claim the Borrower, the Administrative Agent, the Issuing Banks or any other Lender may have against such Defaulting Lender or cause such Defaulting Lender to be a Non-Defaulting Lender, to the extent that all or any portion (the “unreallocated portion”) of the Defaulting Lender’s Letter of Credit Exposure cannot, or can only partially, be so reallocated to Non-Defaulting Lenders, whether by reason of the first proviso in Section 2.18(c)(i) or otherwise, the Borrower shall within two Business Days following notice by the Administrative Agent, Cash Collateralize for the benefit of the applicable Issuing Bank only the Borrower’s obligations corresponding to such Defaulting Lender’s Letter of Credit Exposure (after giving effect to any partial reallocation pursuant to clause (i) above), in accordance with the procedures set forth in Section 3.8 for so long as such Letter of Credit Exposure is outstanding, if the Borrower Cash Collateralizes any portion of such Defaulting Lender’s Letter of Credit Exposure pursuant to this Section 2.18(c), the Borrower shall not be required to pay any fees to such Defaulting Lender pursuant to Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure during the period such Defaulting Lender’s Letter of Credit Exposure is Cash Collateralized, if the Letter of Credit Exposure of the Non-Defaulting Lenders is reallocated pursuant to this Section 2.18(c), then the Letter of Credit Fees payable for the account of the Lenders pursuant to Section 4.1(b) shall be adjusted in accordance with such Non-Defaulting Lenders’ Commitment Percentages and the Borrower shall not be required to pay any Letter of Credit Fees to the Defaulting Lender pursuant to Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure during the period that such Defaulting Lender’s Letter of Credit Exposure is reallocated, or if any Defaulting Lender’s Letter of Credit Exposure is neither Cash Collateralized nor reallocated pursuant to this Section 2.18(c), then, without prejudice to any rights or remedies of any Issuing Bank or any Lender hereunder, all Letter of Credit Fees payable under Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure shall be payable to such Issuing Bank until such Letter of Credit Exposure is Cash Collateralized and/or reallocated;

(d)        So long as any Lender is a Defaulting Lender, no Issuing Bank will be required to issue any new Letter of Credit or amend any outstanding Letter of Credit to increase the Face Amount thereof, alter the drawing terms thereunder or extend the expiration date thereof, unless each Issuing Bank is reasonably satisfied that any exposure that would result from the exposure to such Defaulting Lender is eliminated or fully covered by the Commitments of the Non-Defaulting Lenders or by Cash Collateralization or a combination thereof in accordance with clause (c) above or otherwise in a manner reasonably satisfactory to such Issuing Bank, and participating interests in any such newly issued or increased Letter of Credit shall be allocated among Non-Defaulting Lenders in a manner consistent with Section 2.18(c)(i) (and Defaulting Lenders shall not participate therein);

(e)        If the Borrower, the Administrative Agent and each Issuing Bank agree in writing in their discretion that a Lender that is a Defaulting Lender should no longer be deemed to be a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon, as of the effective date specified in such notice and subject to any conditions set forth therein, such Lender will cease to be a Defaulting Lender and will be a Non-Defaulting Lender and any applicable Cash Collateral shall be promptly returned to

​ 60

​ the Borrower and any Letter of Credit Exposure of such Lender reallocated pursuant to Section 2.18(c) shall be reallocated back to such Lender; provided that, except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Lender to Non-Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from such Lender’s having been a Defaulting Lender; and

(f)        Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of that Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Article XI or otherwise), shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by that Defaulting Lender to the Administrative Agent hereunder; second, to the payment on a pro rata basis of any amounts owing by that Defaulting Lender to each Issuing Bank hereunder; third, as the Borrower may request (so long as no Default or Event of Default exists), to the funding of any Loan in respect of which that Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; fourth, if so determined by the Administrative Agent and the Borrower, to be held in a non-interest bearing deposit account and released in order to satisfy obligations of that Defaulting Lender to fund Loans under this Agreement; fifth, to the payment of any amounts owing to the Lenders and each Issuing Bank as a result of any judgment of a court of competent jurisdiction obtained by any Lender, such Issuing Bank against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; sixth, so long as no Default or Event of Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; and seventh, to that Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that if such payment is a payment of the principal amount of any Loans or Unpaid Drawings, such payment shall be applied solely to pay the relevant Loans of, and Unpaid Drawings owed to, the relevant non-Defaulting Lenders on a pro rata basis prior to being applied in the manner set forth in this Section 2.18(f). Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender or to post Cash Collateral pursuant to Section 3.8 shall be deemed paid to and redirected by that Defaulting Lender, and each Lender irrevocably consents hereto.

ARTICLE III

LETTERS OF CREDIT

Section 3.1      Letters of Credit .

(a)        Subject to and upon the terms and conditions herein set forth, at any time and from time to time on and after the Effective Date and prior to the L/C Maturity Date, each Issuing Bank agrees, in reliance upon the agreements of the Lenders set forth in this Section 3.1, to issue upon the request of the Borrower and for the direct or indirect benefit of the Borrower or its Restricted Subsidiaries, a Letter of Credit or Letters of Credit in such form and with such Issuer Documents as may be approved by the applicable Issuing Bank in its reasonable discretion.

​ 61

​ (b)        Notwithstanding the foregoing, (i) no Letter of Credit shall be issued the Stated Amount of which, when added to the Letters of Credit outstanding at such time, would exceed the (a) L/C Sublimit then in effect, or (b) with respect to any Issuing Bank would cause the Stated Amount of such Issuing Bank’s outstanding Letters of Credit at such time to exceed such Issuing Bank’s L/C Sublimit unless such Issuing Bank shall otherwise agree, (ii) no Letter of Credit shall be issued the Stated Amount of which would cause the Total Outstandings at such time to exceed the Borrowing Base then in effect, (iii) each Letter of Credit shall have an expiration date occurring no later than twelve (12) months after the date of issuance or such longer period of time as may be agreed by the applicable Issuing Bank, unless otherwise agreed upon by the Administrative Agent and the applicable Issuing Bank or as provided under Section 3.2(b); provided that any Letter of Credit may provide for automatic renewal thereof for additional periods of up to twelve (12) months or such longer period of time as may be agreed upon by the applicable Issuing Bank, subject to the provisions of Section 3.2(b); provided, further, that in no event shall such expiration date occur later than the L/C Maturity Date unless arrangements which are reasonably satisfactory to the applicable Issuing Bank to Cash Collateralize (or backstop) such Letter of Credit have been made, (iv) no Letter of Credit shall be issued if (A) it would be illegal under any applicable Requirement of Law for the beneficiary of the Letter of Credit to have a Letter of Credit issued in its favor, (B) any order, judgment or decree of any Governmental Authority or arbitrator shall by its terms purport to enjoin or restrain the Issuing Bank from issuing the Letter of Credit, or any Requirement of Law applicable to the Issuing Bank or any request or directive (whether or not having the force of law) from any Governmental Authority with jurisdiction over the Issuing Bank shall prohibit, or request that the Issuing Bank refrain from, the issuance of letters of credit generally or the Letter of Credit in particular or shall impose upon Issuing Bank with respect to the Letter of Credit any restriction, reserve or capital requirement (for which the Issuing Bank is not otherwise compensated hereunder) not in effect on the Effective Date, or shall impose upon Issuing Bank any unreimbursed loss, cost or expense which was not applicable on the Effective Date and which, in each case, the Issuing Bank in good faith deems material to it or (C) the issuance of the Letter of Credit would violate one or more policies of the Issuing Bank applicable to letters of credit generally as certified to the Borrower in writing by such Issuing Bank and (v) no Letter of Credit shall be issued by an Issuing Bank after it has received a written notice from any Credit Party or the Administrative Agent or the Majority Lenders stating that a Default or Event of Default has occurred and is continuing until such time as such Issuing Bank shall have received a written notice (A) of rescission of such notice from the party or parties originally delivering such notice, (B) of the waiver of such Default or Event of Default in accordance with the provisions of Section 13.1 or (C) that such Default or Event of Default is no longer continuing.

(c)        Upon at least one Business Day’s prior written notice (or telephonic notice promptly confirmed in writing) to the Administrative Agent and the applicable Issuing Bank (which notice the Administrative Agent shall promptly transmit to each of the applicable Lenders), the Borrower shall have the right, on any day, permanently to terminate or reduce the L/C Sublimit in whole or in part; provided that, after giving effect to such termination or reduction, the outstanding Reimbursement Obligations shall not exceed the L/C Sublimit.

​ 62

​ Section 3.2      Letter of Credit Applications .

(a)        Whenever the Borrower desires that a Letter of Credit be issued, amended or renewed for its account, the Borrower shall hand deliver or telecopy (or transmit by electronic communication, if arrangements for doing so have been approved by the applicable Issuing Bank) to the applicable Issuing Bank and the Administrative Agent a Letter of Credit Application, amendment request or any such document as may be approved by the applicable Issuing Bank. Upon receipt of any Letter of Credit Application or amendment request, the applicable Issuing Bank will use its best efforts to process such Letter of Credit Application on (i) the Business Day on which such Letter of Credit Application is received, provided that such Letter of Credit Application is received no later than 12:00 p.m. (New York, New York time) on such Business Day, or (ii) otherwise, the first Business Day next succeeding receipt of such Letter of Credit Application. No Issuing Bank shall issue any Letters of Credit unless such Issuing Bank shall have received notice from the Administrative Agent that the conditions to such issuance have been met, which notice shall be deemed given (A) if the Letter of Credit Issuer has not received notice from the Administrative Agent that the conditions to such issuance have been met within one Business Day after the date of receipt of the Letter of Credit Application or (B) if the aggregate amount of Letters of Credit Outstanding issued by such Issuing Bank then outstanding does not exceed the amount theretofore agreed to by the Borrower, the Administrative Agent and such Issuing Bank, and the Administrative Agent has not otherwise notified such Issuing Bank that it may no longer rely on subclauses (A) or (B).

(b)        If the Borrower so requests in any Letter of Credit Application, the Issuing Bank may, in its sole and absolute discretion, agree to issue a Letter of Credit that has automatic extension provisions (each, an “Auto-Extension Letter of Credit”); provided that any such Auto-Extension Letter of Credit must permit the Issuing Bank to prevent any such extension at least once in each 12-month period (commencing with the date of issuance of such Letter of Credit) by giving prior notice to the beneficiary thereof not later than a day (the “Non-Extension Notice Date”) in each such 12-month period to be agreed upon at the time such Letter of Credit is issued.  Unless otherwise directed by the Issuing Bank, the Borrower shall not be required to make a specific request to the Issuing Bank for any such extension.  Once an Auto-Extension Letter of Credit has been issued, the Lenders shall be deemed to have authorized (but may not require) the Issuing Bank to permit the extension of such Letter of Credit at any time to an expiry date not later than the L/C Maturity Date unless arrangements which are reasonably satisfactory to the Issuing Bank to Cash Collateralize (or satisfactory to the Issuing Bank in its sole discretion to otherwise backstop) such Letter of Credit have been made (but no Lenders shall be obligated to fund participations in respect of any Letter of Credit after the Maturity Date); provided, however, that the Issuing Bank shall not permit any such extension if (i) the Issuing Bank has determined that it would not be permitted, or would have no obligation, at such time to issue such Letter of Credit in its revised form (as extended) under the terms hereof (by reason of the provisions of clause (b) of Section 3.1 or otherwise), or (ii) it has received notice (which may be by telephone or in writing) on or before the day that is five (5) Business Days before the Non-Extension Notice Date (A) from the Administrative Agent that the Majority Lenders have elected not to permit such extension or (B) from the Administrative Agent, any Lender or the Borrower that one or more of the applicable

​ 63

​ conditions specified in Section 7 are not then satisfied, and in each such case directing the Issuing Bank not to permit such extension.

(c)        Each Issuing Bank (other than the Administrative Agent or any of its Affiliates) shall, at least once each week, provide the Administrative Agent with a list of all Letters of Credit issued by it that are outstanding at such time; provided that, upon written request from the Administrative Agent, such Issuing Bank shall thereafter notify the Administrative Agent in writing on each Business Day of all Letters of Credit issued on the prior Business Day by such Issuing Bank.

(d)        The making of each Letter of Credit Application shall be deemed to be a representation and warranty by the Borrower that the Letter of Credit may be issued in accordance with, and will not violate the requirements of, Section 3.1(b).

Section 3.3      Letter of Credit Participations .

(a)        Immediately upon the issuance by an Issuing Bank of any Letter of Credit, such Issuing Bank shall be deemed to have sold and transferred to each Lender (each such Lender, in its capacity under this Section 3.3, an “L/C Participant”), and each such L/C Participant shall be deemed irrevocably and unconditionally to have purchased and received from such Issuing Bank, without recourse or warranty, an undivided interest and participation (each an “L/C Participation”), to the extent of such L/C Participant’s Commitment Percentage, in each Letter of Credit, each substitute therefor, each drawing made thereunder and the obligations of the Borrower under this Agreement with respect thereto, and any security therefor or guaranty pertaining thereto.

(b)        In determining whether to pay under any Letter of Credit, the relevant Issuing Bank shall have no obligation relative to the L/C Participants other than to confirm that

(i)         any documents required to be delivered under such Letter of Credit have been delivered,

(ii)       such Issuing Bank has examined the documents with reasonable care and

(iii)      the documents appear to comply on their face with the requirements of such Letter of Credit. Any action taken or omitted to be taken by the relevant Issuing Bank under or in connection with any Letter of Credit issued by it, if taken or omitted in the absence of gross negligence, bad faith or willful misconduct, shall not create for such Issuing Bank any resulting liability.

(c)        In the event that an Issuing Bank makes any payment under any Letter of Credit issued by it and the Borrower shall not have repaid such amount in full to such Issuing Bank pursuant to Section 3.4(a), or if any reimbursement payment is required to be refunded to the Borrower, such Issuing Bank shall promptly notify the Administrative Agent and each L/C Participant of such failure, and each such L/C Participant shall promptly and unconditionally pay to the Administrative Agent for the account of such

​ 64

​ Issuing Bank the amount of such L/C Participant’s Commitment Percentage of such unreimbursed payment in Dollars and in immediately available funds; provided, however, that no L/C Participant shall be obligated to pay to the Administrative Agent for the account of such Issuing Bank its Commitment Percentage of such unreimbursed amount arising from any wrongful payment made by such Issuing Bank under any such Letter of Credit as a result of acts or omissions constituting willful misconduct, bad faith or gross negligence on the part of such Issuing Bank. Each L/C Participant shall make available to the Administrative Agent for the account of the relevant Issuing Bank such L/C Participant’s Commitment Percentage of the amount of such payment no later than 1:00 p.m. (New York, New York time) on the first Business Day after the date notified by such Issuing Bank in immediately available funds. If and to the extent such L/C Participant shall not have so made its Commitment Percentage of the amount of such payment available to the Administrative Agent for the account of the relevant Issuing Bank, such L/C Participant agrees to pay to the Administrative Agent for the account of such Issuing Bank, forthwith on demand, such amount, together with interest thereon for each day from such date until the date such amount is paid to the Administrative Agent for the account of such Issuing Bank at a rate per annum equal to the Overnight Rate from time to time then in effect, plus any administrative, processing or similar fees customarily charged by such Issuing Bank in connection with the foregoing. The failure of any L/C Participant to make available to the Administrative Agent for the account of any Issuing Bank its Commitment Percentage of any payment under any Letter of Credit shall not relieve any other L/C Participant of its obligation hereunder to make available to the Administrative Agent for the account of such Issuing Bank its Commitment Percentage of any payment under such Letter of Credit on the date required, as specified above, but no L/C Participant shall be responsible for the failure of any other L/C Participant to make available to the Administrative Agent such other L/C Participant’s Commitment Percentage of any such payment.

(d)        Whenever an Issuing Bank receives a payment in respect of an unpaid Reimbursement Obligation as to which the Administrative Agent has received for the account of such Issuing Bank any payments from the L/C Participants pursuant to clause (c) above, such Issuing Bank shall pay to the Administrative Agent and the Administrative Agent shall promptly pay to each L/C Participant that has paid its Commitment Percentage of such Reimbursement Obligation, in Dollars and in immediately available funds, an amount equal to such L/C Participant’s share (based upon the proportionate aggregate amount originally funded by such L/C Participant to the aggregate amount funded by all L/C Participants) of the principal amount so paid in respect of such Reimbursement Obligation and interest thereon accruing after the purchase of the respective L/C Participations at the Overnight Rate.

(e)        The obligations of the L/C Participants to make payments to the Administrative Agent for the account of an Issuing Bank with respect to Letters of Credit shall be irrevocable and not subject to counterclaim, set-off or other defense or any other qualification or exception whatsoever and shall be made in accordance with the terms and conditions of this Agreement under all circumstances, including under any of the following circumstances:

​ 65

​ (i)         any lack of validity or enforceability of this Agreement or any of the other Credit Documents;

(ii)       the existence of any claim, set-off, defense or other right that the Borrower may have at any time against a beneficiary named in a Letter of Credit, any transferee of any Letter of Credit (or any Person for whom any such transferee may be acting), the Administrative Agent, any Issuing Bank, any Lender or other Person, whether in connection with this Agreement, any Letter of Credit, the transactions contemplated herein or any unrelated transactions (including any underlying transaction between the Borrower and the beneficiary named in any such Letter of Credit);

(iii)      any draft, certificate or any other document presented under any Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect;

(iv)       the surrender or impairment of any security for the performance or observance of any of the terms of any of the Credit Documents; or

(v)        the occurrence of any Default or Event of Default;

provided, however, that no L/C Participant shall be obligated to pay to the Administrative Agent for the account of any Issuing Bank its Commitment Percentage of any unreimbursed amount arising from any wrongful payment made by such Issuing Bank under a Letter of Credit as a result of acts or omissions constituting willful misconduct, bad faith or gross negligence on the part of such Issuing Bank.

Section 3.4      Agreement to Repay Letter of Credit Drawings .

(a)        The Borrower hereby agrees to reimburse the relevant Issuing Bank by making payment in Dollars to such Issuing Bank or to the Administrative Agent for the account of such Issuing Bank (whether with its own funds or with proceeds of the Loans) in immediately available funds, for any payment or disbursement made by such Issuing Bank under any Letter of Credit issued by it (each such amount so paid until reimbursed, an “Unpaid Drawing”) (i) within one Business Day of the date of such payment or disbursement if such Issuing Bank provides notice to the Borrower of such payment or disbursement prior to 11:00 a.m. (New York, New York time) on such next succeeding Business Day (from the date of such payment or disbursement) or (ii) if such notice is received after such time, on the next Business Day following the date of receipt of such notice (such required date for reimbursement under clause (i) or (ii), as applicable, the “Reimbursement Date”), with interest on the amount so paid or disbursed by such Issuing Bank, from and including the date of such payment or disbursement to but excluding the Reimbursement Date, at the per annum rate for each day equal to the rate described in Section 2.7(a); provided that, notwithstanding anything contained in this Agreement to the contrary, with respect to any Letter of Credit, (A) unless the Borrower shall have notified the Administrative Agent and such Issuing Bank prior to 11:00 a.m. (New York, New York time) on the Reimbursement Date that the Borrower intends to reimburse such Issuing

​ 66

​ Bank for the amount of such drawing with funds other than the proceeds of Loans, the Borrower shall be deemed to have given a Notice of Borrowing requesting that the Lenders make Loans (which shall be ABR Loans) on the Reimbursement Date in an amount equal to the amount of such drawing, and (B) the Administrative Agent shall promptly notify each L/C Participant of such drawing and the amount of its Loan to be made in respect thereof, and each L/C Participant shall be irrevocably obligated to make a Loan to the Borrower in the manner deemed to have been requested in the amount of its Commitment Percentage of the applicable Unpaid Drawing by 12:00 noon (New York, New York time) on such Reimbursement Date by making the amount of such Loan available to the Administrative Agent. Such Loans made in respect of such Unpaid Drawing on such Reimbursement Date shall be made without regard to the satisfaction of the conditions set forth in Article VII. The Administrative Agent shall use the proceeds of such Loans solely for purpose of reimbursing the relevant Issuing Bank for the related Unpaid Drawing. In the event that the Borrower fails to Cash Collateralize any Letter of Credit that is outstanding on the L/C Maturity Date, the full amount of the Letters of Credit Outstanding in respect of such Letter of Credit shall be deemed to be an Unpaid Drawing subject to the provisions of this Section 3.4 except that such Issuing Bank shall hold the proceeds received from the Lenders as contemplated above as cash collateral for such Letter of Credit to reimburse any Drawing under such Letter of Credit and shall use such proceeds first, to reimburse itself for any Drawings made in respect of such Letter of Credit following the L/C Maturity Date, second, to the extent such Letter of Credit expires or is returned undrawn while any such cash collateral remains, to the repayment of obligations in respect of any Loans that have not paid at such time and third, to the Borrower or as otherwise directed by a court of competent jurisdiction. Nothing in this Section 3.4(a) shall affect the Borrower’s obligation to repay all outstanding Loans when due in accordance with the terms of this Agreement.

(b)        The obligations of the Borrower under this Section 3.4 to reimburse the relevant Issuing Bank with respect to Unpaid Drawings (including, in each case, interest thereon) shall be absolute, unconditional and irrevocable under any and all circumstances and irrespective of any set-off, counterclaim or defense to payment that the Borrower or any other Person may have or have had against such Issuing Bank, the Administrative Agent or any Lender (including in its capacity as an L/C Participant), including any defense based upon (i) the failure of any drawing under a Letter of Credit (each a “Drawing”) to conform to the terms of the Letter of Credit, (ii) any non-application or misapplication by the beneficiary of the proceeds of such Drawing, (iii) any lack of validity or enforceability of any Letter of Credit or this Agreement, or any term or provision therein, (iv) any draft or other document presented under a Letter of Credit proving to be forged, fraudulent or invalid in any respect or any statement therein being untrue or inaccurate in any respect or (v) any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section 3.4(b), constitute a legal or equitable discharge of, or provide a right of setoff against, the Borrower’s obligations hereunder; provided that the foregoing shall not be construed to excuse the relevant Issuing Bank from liability to the Borrower to the extent of any direct damages (as opposed to special, indirect, consequential or punitive damages, claims in respect of which are hereby waived by the Borrower to the extent permitted by applicable law) suffered by the Borrower that are caused by such Issuing Bank’s failure to exercise care when determining

​ 67

​ whether drafts and other documents presented under a Letter of Credit comply with the terms thereof. The Borrower agrees that any action taken or omitted to be taken by an Issuing Bank under or in connection with any Letter of Credit or the related drafts or documents, if done in the absence of gross negligence or willful misconduct (as finally determined by a court of competent jurisdiction), shall be binding on the Borrower and shall not result in any liability of such Issuing Bank to the Borrower; provided that the foregoing shall not be construed to excuse such Issuing Bank from liability to the Borrower to the extent of any direct damages suffered by the Borrower that are caused by such Issuing Bank’s failure to exercise care, when determining whether drafts and other documents presented under a Letter of Credit comply with the terms thereof. In furtherance of the foregoing, the parties hereto agree that, with respect to documents presented which appear on their face to be in compliance with the terms of a Letter of Credit, the Issuing Bank that issued such Letter of Credit may in its sole discretion either accept or make payment upon such documents without responsibility for further investigation, regardless of any notice or information to the contrary, or refuse to accept and make payment upon such documents if such documents are not in strict compliance with the terms of such Letter of Credit (unless the Borrower shall consent to payment thereon notwithstanding such lack of strict compliance).

Section 3.5      Increased Costs.  If, after the Effective Date, the adoption of any Change in Law shall either (a) impose, modify or make applicable any reserve, deposit, capital adequacy or similar requirement against Letters of Credit issued by any Issuing Bank, or any L/C Participant’s L/C Participation therein, or (b) impose on any Issuing Bank or any L/C Participant any other conditions, costs or expenses affecting its obligations under this Agreement in respect of Letters of Credit or L/C Participations therein or any Letter of Credit or such L/C Participant’s L/C Participation therein, and the result of any of the foregoing is to increase the cost to such Issuing Bank or such L/C Participant of issuing, maintaining or participating in any Letter of Credit, or to reduce the amount of any sum received or receivable by such Issuing Bank or such L/C Participant hereunder (other than (i) Taxes indemnifiable under Section 5.4, or (ii) Excluded Taxes) in respect of Letters of Credit or L/C Participations therein, then, promptly (and in any event no later than 15 days) after receipt of written demand to the Borrower by such Issuing Bank or such L/C Participant, as the case may be (a copy of which notice shall be sent by such Issuing Bank or such L/C Participant to the Administrative Agent), the Borrower shall pay to such Issuing Bank or such L/C Participant such additional amount or amounts as will compensate such Issuing Bank or such L/C Participant for such increased cost or reduction, it being understood and agreed, however, that no Issuing Bank or L/C Participant shall be entitled to such compensation as a result of such Person’s compliance with, or pursuant to any request or directive to comply with, any such Requirement of Law as in effect on the Effective Date. A certificate submitted to the Borrower by the relevant Issuing Bank or an L/C Participant, as the case may be (a copy of which certificate shall be sent by such Issuing Bank or such L/C Participant to the Administrative Agent), setting forth in reasonable detail the basis for the determination of such additional amount or amounts necessary to compensate such Issuing Bank or such L/C Participant as aforesaid shall be conclusive and binding on the Borrower absent clearly demonstrable error.

Section 3.6      New or Successor Issuing Bank .

​ 68

​ (a)        Any Issuing Bank may resign as an Issuing Bank upon thirty (30) days’ prior written notice to the Administrative Agent, the Lenders and the Borrower; provided that no Issuing Bank may resign without the prior consent of the Borrower so long as such Issuing Bank (or one of its Affiliates) is also a Lender hereunder. The Borrower may replace any Issuing Bank for any reason upon written notice to such Issuing Bank and the Administrative Agent and may add Issuing Banks at any time upon notice by the Borrower to the Administrative Agent. If an Issuing Bank shall resign or be replaced, or if the Borrower shall decide to add a new Issuing Bank under this Agreement, then the Borrower may appoint from among the Lenders a successor issuer of Letters of Credit or a new Issuing Bank, as the case may be, or, with the consent of the Administrative Agent (such consent not to be unreasonably withheld) and such new Issuing Bank, another successor or new issuer of Letters of Credit, whereupon such successor issuer shall succeed to the rights, powers and duties of the replaced or resigning Issuing Bank under this Agreement and the other Credit Documents, or such new issuer of Letters of Credit shall be granted the rights, powers and duties of an Issuing Bank hereunder, and the term “Issuing Bank” shall mean such successor or such new issuer of Letters of Credit effective upon such appointment. The acceptance of any appointment as an Issuing Bank hereunder, whether as a successor issuer or new issuer of Letters of Credit in accordance with this Agreement, shall be evidenced by an agreement entered into by such new or successor issuer of Letters of Credit, in a form reasonably satisfactory to the Borrower and the Administrative Agent and, from and after the effective date of such agreement, such new or successor issuer of Letters of Credit shall become an “Issuing Bank” hereunder. After the resignation or replacement of an Issuing Bank hereunder, the resigning or replaced Issuing Bank shall remain a party hereto and shall continue to have all the rights and obligations of an Issuing Bank under this Agreement and the other Credit Documents with respect to Letters of Credit issued by it prior to such resignation or replacement, but shall not be required to issue additional Letters of Credit. In connection with any resignation or replacement pursuant to this clause (a) (but, in case of any such resignation, only to the extent that a successor issuer of Letters of Credit shall have been appointed), either

(i)         the Borrower, the resigning or replaced Issuing Bank and the successor Issuing Bank shall arrange to have any outstanding Letters of Credit issued by the resigning or replaced Issuing Bank replaced with Letters of Credit issued by the successor Issuing Bank or

(ii)       the Borrower shall cause the successor Issuing Bank, if such successor issuer is reasonably satisfactory to the replaced or resigning Issuing Bank, to issue “back-stop” Letters of Credit naming the resigning or replaced Issuing Bank as beneficiary for each outstanding Letter of Credit issued by the resigning or replaced Issuing Bank, which new Letters of Credit shall have a Stated Amount equal to the Letters of Credit being back-stopped and the sole requirement for drawing on such new Letters of Credit shall be a drawing on the corresponding back-stopped Letters of Credit. After any resigning or replaced Issuing Bank’s resignation or replacement as Issuing Bank, the provisions of this Agreement relating to an Issuing Bank shall inure to its benefit as to any actions taken or omitted to be taken by it (A) while it was an Issuing Bank under this Agreement or (B) at any time with respect to Letters of Credit issued by such Issuing Bank.

​ 69

​ (b)        To the extent that there are, at the time of any resignation or replacement as set forth in clause (a) above, any outstanding Letters of Credit, nothing herein shall be deemed to impact or impair any rights and obligations of any of the parties hereto with respect to such outstanding Letters of Credit (including any obligations related to the payment of fees or the reimbursement or funding of amounts drawn), except that the Borrower, the resigning or replaced Issuing Bank and the successor Issuing Bank shall have the obligations regarding outstanding Letters of Credit described in clause (a) above.

Section 3.7      Role of Issuing Bank.  Each Lender and the Borrower agree that, in paying any drawing under a Letter of Credit, no Issuing Bank shall have any responsibility to obtain any document (other than any sight draft, certificates and documents expressly required by the Letter of Credit) or to ascertain or inquire as to the validity or accuracy of any such document or the authority of the Person executing or delivering any such document. None of the Issuing Banks, the Administrative Agent, any of their respective affiliates nor any correspondent, participant or assignee of any Issuing Bank shall be liable to any Lender for (a) any action taken or omitted in connection herewith at the request or with the approval of the Majority Lenders, (b) any action taken or omitted in the absence of gross negligence or willful misconduct or (c) the due execution, effectiveness, validity or enforceability of any document or instrument related to any Letter of Credit or Issuer Document. The Borrower hereby assumes all risks of the acts or omissions of any beneficiary or transferee with respect to its use of any Letter of Credit; provided that this assumption is not intended to, and shall not, preclude the Borrower’s pursuing such rights and remedies as it may have against the beneficiary or transferee at law or under any other agreement. None of the Issuing Banks, the Administrative Agent, any of their respective affiliates nor any correspondent, participant or assignee of any Issuing Bank shall be liable or responsible for any of the matters described in Section 3.3(e); provided that anything in such Section to the contrary notwithstanding, the Borrower may have a claim against an Issuing Bank, and such Issuing Bank may be liable to the Borrower, to the extent, but only to the extent, of any direct, as opposed to consequential or exemplary, damages suffered by the Borrower which the Borrower proves were caused by such Issuing Bank’s willful misconduct or gross negligence or such Issuing Bank’s unlawful failure to pay under any Letter of Credit after the presentation to it by the beneficiary of a sight draft and certificate(s) strictly complying with the terms and conditions of a Letter of Credit. In furtherance and not in limitation of the foregoing, any Issuing Bank may accept documents that appear on their face to be in order, without responsibility for further investigation, regardless of any notice or information to the contrary, and no Issuing Bank shall be responsible for the validity or sufficiency of any instrument transferring or assigning or purporting to transfer or assign a Letter of Credit or the rights or benefits thereunder or proceeds thereof, in whole or in part, which may prove to be invalid or ineffective for any reason.

Section 3.8      Cash Collateral .

(a)        Upon the request of the Majority Lenders if, as of the L/C Maturity Date, there are any Letters of Credit outstanding, the Borrower shall immediately Cash Collateralize the then Letters of Credit outstanding.

(b)        If any Event of Default shall occur and be continuing, the Majority Lenders may require that the L/C Obligations be Cash Collateralized; provided that, upon the occurrence of an Event of Default referred to in Section 11.5 with respect to the Borrower,

​ 70

​ the Borrower shall immediately Cash Collateralize the Letters of Credit then outstanding and no notice or request by or consent from the Majority Lenders shall be required.

(c)        For purposes of this Agreement, “Cash Collateralize” shall mean (i) to pledge and deposit with or deliver to the Administrative Agent, for the benefit of the Issuing Banks and the Lenders, as collateral for the L/C Obligations, cash or deposit account balances in an amount equal to the amount of the Letters of Credit outstanding required to be Cash Collateralized (the “Required Cash Collateral Amount”) or (ii) if the relevant Issuing Bank benefiting from such collateral shall agree in its reasonable discretion, to provide other forms of credit support (including any backstop letter of credit) in a face amount equal to 103% of the Required Cash Collateral Amount from an issuer reasonably satisfactory to such Issuing Bank, in each case under clause (i) and (ii) above pursuant to documentation in form and substance reasonably satisfactory to the Administrative Agent and the relevant Issuing Bank (which documents are hereby consented to by the Lenders). The Borrower hereby grants to the Administrative Agent, for the benefit of the Issuing Banks and the L/C Participants, a security interest in all such cash, deposit accounts and all balances therein and all proceeds of the foregoing. Such cash Collateral shall be maintained in blocked, interest bearing deposit accounts established by and in the name of the Borrower, but under the “control” (as defined in Section 9-104 of the UCC) of the Administrative Agent.

Section 3.9      Applicability of ISP and UCP.  Unless otherwise expressly agreed to by the relevant Issuing Bank and the Borrower when a Letter of Credit is issued, (a) the rules of the ISP or the Uniform Customs and Practice for Documentary Credits shall apply to each standby Letter of Credit and (b) the rules of the Uniform Customs and Practice for Documentary Credits, as most recently published by the International Chamber of Commerce at the time of issuance, shall apply to each commercial Letter of Credit.

Section 3.10    Conflict with Issuer Documents.  In the event of any conflict between the terms hereof and the terms of any Issuer Document, the terms hereof shall control.

ARTICLE IV

FEES; COMMITMENTS

Section 4.1      Fees .

(a)        The Borrower agrees to pay to the Administrative Agent in Dollars, for the account of each Lender (in each case pro rata according to the respective Commitment Percentages of the Lenders), a commitment fee (the “Unused Commitment Fee”) for each day from the Effective Date until but excluding the Maturity Date. Each Unused Commitment Fee shall be payable by the Borrower (i) quarterly in arrears on the last Business Day of each March, June, September and December (for the three-month period (or portion thereof) ended on such day for which no payment has been received) and (ii) on the Maturity Date (for the period ended on such date for which no payment has been received pursuant to clause (i) above), and shall be computed for each day during such period at a rate per annum equal to the Unused Commitment Fee Rate in effect on such day on the Available Commitment in effect on such day.

​ 71

​ (b)        The Borrower agrees to pay to (i) each Issuing Bank a fee in respect of each Letter of Credit issued by it (the “Fronting Fee”), for the period from the date of issuance of such Letter of Credit to the termination or expiration date of such Letter of Credit, computed at the rate for each day equal to 0.20% per annum (or such other amount as may be agreed in a separate writing between the Borrower and the relevant Issuing Bank) on the average daily Stated Amount of such Letter of Credit (or at such other rate per annum as agreed in writing between the Borrower and the relevant Issuing Bank) and (ii) the Administrative Agent for the account of each Lender a fee equal to the Applicable Margin for a LIBOR Loan then in effect (the “Letter of Credit Fee”) on such Lender’s Letter of Credit Exposure. Such Fronting Fees and Letter of Credit Fees shall be due and payable by the Borrower (i) quarterly in arrears on the last Business Day of each March, June, September and December and (ii) on the Termination Date (for the period for which no payment has been received pursuant to clause (i) above).

(c)        The Borrower agrees to pay to the Administrative Agent, for its account and on behalf of the Lenders, as applicable, the administrative agent fees in the amounts and on the dates as set forth in writing in a fee letter between the Administrative Agent and the Borrower.

Section 4.2      Voluntary Reduction of Commitment Amount .

(a)        Upon at least two Business Days’ prior written notice (or telephonic notice promptly confirmed in writing) to the Administrative Agent at the Administrative Agent’s Office (which notice the Administrative Agent shall promptly transmit to each of the Lenders), the Borrower shall have the right, without premium or penalty, on any day, permanently to terminate or reduce the Total Commitment, as determined by the Borrower, in whole or in part; provided that (i) any such termination or reduction shall apply proportionately and permanently to reduce the Commitment of each Lender, (ii) any partial reduction pursuant to this Section 4.2 shall be in the amount of at least $500,000 (and increments of $100,000 above that minimum) and (iii) after giving effect to such termination or reduction and to any prepayments of Loans or cancellation or Cash Collateralization of Letters of Credit made on the date thereof in accordance with this Agreement, the aggregate amount of the Total Outstandings shall not exceed the Loan Limit.

(b)        The Borrower may terminate the unused amount of the Commitment of a Defaulting Lender upon not less than two (2) Business Days’ prior notice to the Administrative Agent (which will promptly notify the Lenders thereof), and in such event the provisions of Section 2.18(f) will apply to all amounts thereafter paid by the Borrower for the account of such Defaulting Lender under this Agreement (whether on account of principal, interest, fees, indemnity or other amounts), provided that such termination will not be deemed to be a waiver or release of any claim the Borrower, the Administrative Agent, any Issuing Bank or any Lender may have against such Defaulting Lender.

Section 4.3      Mandatory Termination of Commitments.  The Total Commitment shall terminate at 5:00 p.m. (New York, New York time) on the Maturity Date. If at any time the Total

​ 72

​ Commitment or the Borrowing Base is terminated or reduced to zero, then each Lender’s Commitment shall terminate on the effective date of such termination or reduction.

Section 4.4      Increases, Reductions and Terminations of Aggregate Elected Commitment Amount.

(a)        Subject to the conditions set forth in Section 4.4(b), the Borrower may increase the Aggregate Elected Commitment Amount then in effect by increasing the Elected Commitment of one or more existing Lenders (each such Lender, an “Increasing Lender”) and/or by causing one or more Persons reasonably acceptable to the Administrative Agent (it being agreed that any Affiliate of a Lender shall be deemed acceptable to the Administrative Agent) and that at such time are not Lenders to become a Lender (each such Person that is not at such time a Lender and becomes a Lender, an “Additional Lender”).  Notwithstanding anything to the contrary contained in this Agreement, in no case shall an Additional Lender be the Borrower, an Affiliate of the Borrower or a natural person.

(b)        Any increase in the Aggregate Elected Commitment Amount shall be subject to the following additional conditions:

(i)         no increase in the Aggregate Elected Commitment Amount shall be permitted if immediately after giving effect thereto the Aggregate Elected Commitment Amount exceeds the lesser of (I) the Borrowing Base then in effect and (II) the Maximum Facility Amount;

(ii)       the Borrower may not increase the Aggregate Elected Commitment Amount more than once between any two redeterminations of the Borrowing Base unless the Administrative Agent otherwise consents (for the sake of clarity, all increases in the Aggregate Elected Commitment Amount effective on a single date shall be deemed a single increase in the Aggregate Elected Commitment Amount for purposes of this Section 4.4(b)(ii)), whether a Scheduled Redetermination or an Unscheduled Redetermination;

(iii)      no Lender’s Elected Commitment may be increased without the consent of such Lender;

(iv)       subject to Section 4.4(b)(iii), if the Borrower elects to increase the Aggregate Elected Commitment Amount by increasing the Elected Commitment of one or more Lenders, the Borrower and each such Increasing Lender shall execute and deliver to the Administrative Agent a certificate substantially in the form of Exhibit G-1 (an “Elected Commitment Increase Certificate”) and the Borrower shall pay any applicable fees as may have been agreed to between the Borrower, such Increasing Lender and/or the Administrative Agent; and

(v)        if the Borrower elects to increase the Aggregate Elected Commitment Amount by causing one or more Additional Lenders to become a party to this Agreement, then the Borrower and each such Additional Lender shall execute and deliver to the Administrative Agent a certificate substantially in the

​ 73

​ form of Exhibit G-2 (an “Additional Lender Certificate”), together with an Administrative Questionnaire for each Additional Lender, and the Borrower shall (I) if requested by any Additional Lender, deliver a Note payable to such Additional Lender in a principal amount equal to its Commitment, and otherwise duly completed and (II) pay any applicable fees as may have been agreed to between the Borrower, any Additional Lender and/or the Administrative Agent.

(c)        Subject to acceptance and recording thereof pursuant to Section 4.4(d), from and after the effective date specified in the Elected Commitment Increase Certificate or the Additional Lender Certificate, as applicable: (A) the amount of the Aggregate Elected Commitment Amount shall be increased as set forth therein, and (B) in the case of an Additional Lender Certificate, any Additional Lender party thereto shall be a party to this Agreement and have the rights and obligations of a Lender under this Agreement and the other Documents.  In addition, each Increasing Lender and Additional Lender, as applicable, shall be deemed to have purchased a pro rata portion of the outstanding Loans (and participation interests in Letters of Credit) of each of the other Lenders (and such Lenders hereby agree to sell and to take all such further action to effectuate such sale) such that each Lender (including any Increasing Lender and any Additional Lender, if applicable) shall hold its Commitment Percentage of the outstanding Loans (and participation interests in Letters of Credit) after giving effect to the increase in the Aggregate Elected Commitment Amount and the resulting modification of each Lender’s Commitment Percentage and Commitment pursuant to Section 4.4(d).

(d)        Upon its receipt of a duly completed Elected Commitment Increase Certificate or an Additional Lender Certificate, executed by the Borrower and the Increasing Lender or by the Borrower and the Additional Lender party thereto, as applicable, and, if applicable, the Administrative Questionnaire referred to in Section 4.4(b)(v) the Administrative Agent shall accept such Elected Commitment Increase Certificate or Additional Lender Certificate and record the information contained therein in the Register required to be maintained by the Administrative Agent pursuant to Section 13.6(b)(iv).

(e)        Upon any increase in the Aggregate Elected Commitment Amount pursuant to this Section 4.4, (A) each Lender’s Commitment Percentage shall be automatically deemed amended to the extent necessary so that each such Lender’s Commitment Percentage equals the percentage of the Aggregate Elected Commitment Amount represented by such Lender’s Elected Commitment, in each case after giving effect to such increase, (B) each Lender’s Commitment shall be automatically deemed amended to the extent necessary so that each Lender’s Commitment equals such Lender’s Commitment Percentage, after giving effect to any adjustments thereto pursuant to the foregoing clause (A), of the Total Commitment, (C) Schedule 13.2 to this Agreement shall be deemed amended to reflect the Elected Commitment of any Increasing Lender and any Additional Lender, and any changes in the Lenders’ respective Commitment Percentages and aggregate Commitment pursuant to the foregoing clauses (A) and (B), and (D) the Borrower shall execute and deliver new Notes to the extent required under Section 2.4(e).  The Administrative Agent shall promptly notify the Borrower, the Lenders and the Issuing Banks of the effectiveness of any increase in the Total Commitment and in connection

​ 74

​ therewith promptly provide such amended and restated Schedule 13.2 to the Borrower, the Lenders and the Issuing Banks

(f)        The Borrower may from time to time terminate or reduce the Aggregate Elected Commitment Amount; provided that (A) each reduction of the Aggregate Elected Commitment Amount shall be in an amount that is an integral multiple of $100,000 and not less than $1,000,000 and (B) the Borrower shall not reduce the Aggregate Elected Commitment Amount if, after giving effect to any concurrent prepayment of the Loans in accordance with Section 5.1 or 5.2, the Total Exposures would exceed the Aggregate Elected Commitment Amount.

(g)        The Borrower shall notify the Administrative Agent of any election to terminate or reduce the Aggregate Elected Commitment Amount under Section 4.4(f) at least three (3) Business Days (or such shorter period as the Administrative Agent may reasonably agree) prior to the effective date of such termination or reduction, specifying such election and the effective date thereof.  Any such notice of termination or reduction may state that it is conditioned upon the effectiveness of other credit facilities or other events, in which case such notice may be revoked by the Borrower if such condition is not satisfied.

Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof.  Any termination or reduction of the Aggregate Elected Commitment Amount shall be permanent and may not be reinstated, except pursuant to Section 4.4(a).  Each reduction of the Aggregate Elected Commitment Amount shall be made ratably among the Lenders in accordance with each Lender’s Commitment Percentage (and Schedule 13.2 shall be deemed amended to reflect such amendments to each Lender’s Elected Commitment and the Aggregate Elected Commitment Amount).

(h)        Upon any redetermination or other adjustment in the Borrowing Base pursuant to this Agreement that would otherwise result in the Borrowing Base becoming less than the Aggregate Elected Commitment Amount, the Aggregate Elected Commitment Amount shall be automatically reduced (ratably among the Lenders in accordance with each Lender’s Commitment Percentage) so that they equal such redetermined Borrowing Base (and Schedule 13.2 shall be deemed amended to reflect such amendments to each Lender’s Elected Commitment and the Aggregate Elected Commitment Amount).

(i)         If (A) the Borrower elects to increase the Aggregate Elected Commitment Amount and (B) each Lender has consented to such increase in its Elected Commitment, then the Aggregate Elected Commitment Amount shall be increased (ratably among the Lenders in accordance with each Lender’s Commitment Percentage) by the amount requested by the Borrower (subject to the limitations set forth in Section 4.4(b)(i)) without the requirement that any Lender deliver an Elected Commitment Increase Certificate, and Schedule 13.2 shall be deemed amended to reflect such amendments to each Lender’s Elected Commitment and the Aggregate Elected Commitment Amount.  The Administrative Agent shall record the information regarding such increases in the Register required to be maintained by the Administrative Agent pursuant to Section 13.6(b)(iv).

​ 75

​ ARTICLE V

PAYMENTS

Section 5.1      Voluntary Prepayments.  The Borrower shall have the right to prepay Loans, without premium or penalty, in whole or in part from time to time on the following terms and conditions:

(a)        the Borrower shall give the Administrative Agent at the Administrative Agent’s Office written notice (or telephonic notice promptly confirmed in writing) of its intent to make such prepayment, the amount of such prepayment and (in the case of LIBOR Loans) the specific Advance(s) being prepaid, which notice shall be given by the Borrower no later than 12:00 p.m. (New York, New York time) (or such later time as agreed to by the Administrative Agent in its reasonable discretion) (i) in the case of LIBOR Loans, three Business Days prior to and (ii) in the case of ABR Loans on the date of such prepayment and shall promptly be transmitted by the Administrative Agent to each of the Lenders;

(b)        each partial prepayment of (i) LIBOR Loans shall be in a minimum amount of $100,000 and in multiples of $100,000 in excess thereof, and (ii) any ABR Loans shall be in a minimum amount of $500,000 and in multiples of $100,000 in excess thereof; and

(c)        any prepayment of LIBOR Loans pursuant to this Section 5.1 on any day other than the last day of an Interest Period applicable thereto shall be subject to compliance by the Borrower with the applicable provisions of Section 2.10.

Each such notice shall specify the date and amount of such prepayment and the Type of Loans to be prepaid; provided that any such notice may state that such notice is conditioned upon the effectiveness of other credit facilities or any incurrence or issuance of debt or equity or the occurrence of any other transaction, in which case such notice may be revoked by the Borrower (by notice to the Administrative Agent on or prior to the specified effective date) if such condition is not satisfied. At the Borrower’s election in connection with any prepayment pursuant to this Section 5.1, such prepayment shall not be applied to any Loans of a Defaulting Lender.

Section 5.2      Mandatory Prepayments .

(a)        Repayment following Optional Reduction of Commitments. If, after giving effect to any reduction of the Total Commitment pursuant to Section 5.1(a), there is a Borrowing Base Deficiency, then the Borrower shall on the same Business Day, prepay the remaining Loans on the date of such termination or reduction in an aggregate principal amount equal to such Borrowing Base Deficiency and (ii) if any Borrowing Base Deficiency remains after prepaying all of the Loans as a result of any Letter of Credit Exposure, pay to the Administrative Agent on behalf of the Issuing Banks and the L/C Participants an amount in cash or otherwise Cash Collateralize an amount equal to such Borrowing Base Deficiency as provided in Section 3.8.

(b)        Repayment of Loans Following Redetermination or Adjustment of Borrowing Base.  Upon any redetermination of the Borrowing Base in accordance with Section 2.14 or 2.15, if there is a Borrowing Base Deficiency, then the Borrower shall, within ten (10) Business Days after its receipt of notice of such Borrowing Base

​ 76

​ Deficiency, inform the Administrative Agent of the Borrower’s election to: (A) within 30 days following such election prepay the Loans in an aggregate principal amount equal to such Borrowing Base Deficiency, (B) prepay the Loans in six substantially equal monthly installments, commencing on the 30th day following such election with each payment being equal to l/6^th^of the aggregate principal amount of such Borrowing Base Deficiency, (C) within 30 days following such election, provide additional Collateral in the form of additional Oil and Gas Properties not evaluated in the most recently delivered Reserve Report or other Collateral reasonably acceptable to the Administrative Agent having a value (as proposed by the Administrative Agent and approved by the Required Lenders in good faith in accordance with their respective usual and customary oil and gas lending criteria as they exist at the particular time) sufficient, after giving effect to any other actions taken pursuant to this Section 5.2(b)(i) to eliminate any such Borrowing Base Deficiency or (D) undertake a combination of clauses (A), (B) and (C); provided that if, because of Letter of Credit Exposure, a Borrowing Base Deficiency remains after prepaying all of the Loans, the Borrower shall Cash Collateralize such remaining Borrowing Base Deficiency as provided in Section 3.8; provided further, that all payments required to be made pursuant to this Section 5.2(b)(i) must be made on or prior to the Maturity Date.

(c)        Disposition of Oil and Gas Properties or Equity Interests in Restricted Subsidiaries and Hedge Terminations or Issuance of Permitted Additional Debt.  Upon any reductions to the Borrowing Base pursuant to Section 2.17 in connection with a Disposition of Oil and Gas Properties or a Hedge Termination or issuance of Permitted Additional Debt, if a Borrowing Base Deficiency exists, then the Borrower shall (A) prepay Loans in an aggregate principal amount equal to such Borrowing Base Deficiency or (B) if any Borrowing Base Deficiency remains after prepaying all of the Loans as a result of any Letter of Credit Exposure, Cash Collateralize an amount equal to such Borrowing Base Deficiency as provided in Section 3.8.  The Borrower shall be obligated to make such prepayment or deposit such Cash Collateral not later than two (2) Business Days after it receives written notice from the Administrative Agent of the adjustment of the Borrowing Base and the resulting Borrowing Base Deficiency.

(d)        Application to Loans. With respect to each prepayment of Loans elected under Section 5.1 or required by Section 5.2, the Borrower may designate (i) the Types of Loans that are to be prepaid and the specific Advance(s) being repaid and (ii) the Loans to be prepaid; provided that (A) each prepayment of any Loans made pursuant to an Advance shall be applied pro rata among such Loans and (B) notwithstanding the provisions of the preceding clause (A), no prepayment of Loans shall be applied to the Loans of any Defaulting Lender unless otherwise agreed to in writing by the Borrower. In the absence of a designation by the Borrower as described in the preceding sentence, the Administrative Agent shall, subject to the above, make such designation in its reasonable discretion with a view, but no obligation, to minimize breakage costs owing under Section 2.12.

(e)        LIBOR Interest Periods. In lieu of making any payment pursuant to this Section 5.2 in respect of any LIBOR Loan, other than on the last day of the Interest Period therefor so long as no Event of Default shall have occurred and be continuing, the Borrower at its option may deposit, on behalf of the Borrower, with the Administrative Agent an amount equal to the amount of the LIBOR Loan to be prepaid and such LIBOR Loan shall

​ 77

​ be repaid on the last day of the Interest Period therefor in the required amount. Such deposit shall be held by the Administrative Agent in a corporate time deposit account established on terms reasonably satisfactory to the Administrative Agent, earning interest at the then customary rate for accounts of such type. The Borrower hereby grants to the Administrative Agent, for the benefit of the Lenders, a security interest in all such cash, deposit accounts and all balances therein and all proceeds of the foregoing. Such deposit shall constitute cash collateral for the LIBOR Loans to be so prepaid; provided that the Borrower may at any time direct that such deposit be applied to make the applicable payment required pursuant to this Section 5.2.

(f)        Application of Proceeds. The application of proceeds pursuant to this Section 5.2 shall not reduce the Commitment under the Facility and amounts prepaid may be reborrowed subject to the Available Commitment.

(g)        Excess Cash. If, on the last Business Day of any week (or, if a Default, Event of Default or Borrowing Base Deficiency has occurred and is continuing, on any Business Day), (A) there are any outstanding Loans and (B) the Borrower has any Excess Cash as of the date of such determination, then the Borrower shall, within three (3) Business Days, (1) prepay the Loans in an aggregate principal amount equal to the amount of such Excess Cash or (2) otherwise reduce the amount of Excess Cash to zero in a manner permitted by this Agreement.

Section 5.3      Method and Place of Payment .

(a)        Except as otherwise specifically provided herein, all payments under this Agreement shall be made by the Borrower without set-off, counterclaim or deduction of any kind, to the Administrative Agent for the ratable account of the Lenders entitled thereto or the Issuing Banks entitled thereto, as the case may be, not later than 2:00 p.m. (New York, New York time) (or such later time as agreed to by the Administrative Agent in its reasonable discretion), in each case, on the date when due and shall be made in immediately available funds at the Administrative Agent’s Office or at such other office as the Administrative Agent shall specify for such purpose by notice to the Borrower, it being understood that written or facsimile notice by the Borrower to the Administrative Agent to make a payment from the funds in the Borrower’s account at the Administrative Agent’s Office shall constitute the making of such payment to the extent of such funds held in such account. All repayments or prepayments of any Loans (whether of principal, interest or otherwise) hereunder and all other payments under each Credit Document shall be made in Dollars. The Administrative Agent will thereafter cause to be distributed on the same day (if payment was actually received by the Administrative Agent prior to 2:00 p.m. (New York, New York time) or, otherwise, on the next Business Day in the sole discretion of the Administrative Agent) like funds relating to the payment of principal or interest or fees ratably to the Lenders or the Issuing Banks, as applicable, entitled thereto.

(b)        For purposes of computing interest or fees, any payments under this Agreement that are made later than 2:00 p.m. (New York, New York time) (or such later time as agreed to by the Administrative Agent in its reasonable discretion) shall be deemed to have been made on the next succeeding Business Day in the sole discretion of the

​ 78

​ Administrative Agent. Whenever any payment to be made hereunder shall be stated to be due on a day that is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day and, with respect to payments of principal, interest shall be payable during such extension at the applicable rate in effect immediately prior to such extension.

Section 5.4      Net Payments.  For purposes of this Section 5.4, the term “applicable law” includes FATCA.

(a)        Any and all payments made by or on behalf of the Borrower or any Guarantor under this Agreement or any other Credit Document shall be made free and clear of, and without deduction or withholding for or on account of, any Taxes; provided that if the Borrower, any Guarantor, the Administrative Agent or any other applicable withholding agent shall be required by applicable Requirements of Law to deduct or withhold any Taxes from such payments, then (i) the applicable withholding agent shall make such deductions or withholdings as are reasonably determined by the applicable withholding agent to be required by any applicable Requirement of Law, (ii) the applicable withholding agent shall timely pay the full amount deducted or withheld to the relevant Governmental Authority within the time allowed and in accordance with applicable Requirements of Law, and (iii) to the extent withholding or deduction is required to be made on account of Indemnified Taxes or Other Taxes, the sum payable by the Borrower or such Guarantor shall be increased as necessary so that after all required deductions and withholdings have been made (including deductions or withholdings of Indemnified Taxes or Other Taxes applicable to additional sums payable under this Section 5.4) the Administrative Agent or the applicable Issuing Bank or Lender, as the case may be, receives an amount equal to the sum it would have received had no such deductions or withholdings been made. Whenever any Indemnified Taxes or Other Taxes are payable by the Borrower or such Guarantor, as promptly as possible thereafter, the Borrower or Guarantor shall send to the Administrative Agent for its own account or for the account of such Issuing Bank or Lender, as the case may be, a certified copy of an official receipt (or other evidence acceptable to such Issuing Bank or Lender, acting reasonably) received by the Borrower or such Guarantor showing payment thereof. Without duplication, after any payment of Taxes by any Credit Party or the Administrative Agent to a Governmental Authority as provided in this Section 5.4, the Borrower shall deliver to the Administrative Agent or the Administrative Agent shall deliver to the Borrower, as the case may be, a copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by laws to report such payment or other evidence of such payment reasonably satisfactory to the Borrower or the Administrative Agent, as the case may be.

(b)        The Borrower shall timely pay and shall indemnify and hold harmless the Administrative Agent and each Lender with regard to any Other Taxes (whether or not such Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority).

(c)        The Borrower shall indemnify and hold harmless the Administrative Agent and each Lender within thirty (30) Business Days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes imposed on the Administrative Agent

​ 79

​ or such Lender, as the case may be (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section 5.4), and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate setting forth in reasonable detail the basis and calculation of the amount of such payment or liability delivered to the Borrower by a Lender or the Administrative Agent (as applicable) on its own behalf or on behalf of a Lender shall be conclusive absent manifest error.

(d)        (i) Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Credit Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding.  In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements.  Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 5.4(d) (ii)(A), (ii)(B) and (ii)(D) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii)       Without limiting the generality of the foregoing,

(A)     any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

(B)      any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(1)      in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Credit Document,

​ 80

​ executed copies of IRS Form W-8BEN or IRS Form W-8BEN-E, as applicable, establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Credit Document, IRS Form W-8BEN or IRS Form W-8BEN-E, as applicable, establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(2)      executed copies of IRS Form W-8ECI;

(3)      in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit F-1 to the effect that such Foreign Lender is not a “bank” within the meaning of Section 881(c)(3)(A) of the Code, a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Code, or a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) executed copies of IRS Form W-8BEN or IRS Form W-8BEN-E, as applicable; or

(4)      to the extent a Foreign Lender is not the beneficial owner, executed copies of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN or IRS Form W-8BEN-E, as applicable, a U.S. Tax Compliance Certificate substantially in the form of Exhibit F-2 or Exhibit F-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit F-4 on behalf of each such direct and indirect partner;

(C)      any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed copies of any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by applicable law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and

​ 81

​ (D)     if a payment made to a Lender under any Credit Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment.  Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

Each Lender agrees that if any form or certification it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so.

(e)        If any Lender or the Administrative Agent, as applicable, determines, in its sole discretion, that it had received a refund of an Indemnified Tax or Other Tax for which a payment has been made by the Borrower or any Guarantor pursuant to this Agreement or any other Credit Document, which refund in the good faith judgment of such Lender or the Administrative Agent, as the case may be, is attributable to such payment made by the Borrower or any Guarantor, then the Lender or the Administrative Agent, as the case may be, shall reimburse the Borrower or such Guarantor for such amount (net of all reasonable out-of-pocket expenses of such Lender or the Administrative Agent, as the case may be, and without interest other than any interest received thereon from the relevant Governmental Authority with respect to such refund) as the Lender or Administrative Agent, as the case may be, determines in its sole discretion to be the proportion of the refund as will leave it, after such reimbursement, in no better or worse position (taking into account expenses or any taxes imposed on the refund) than it would have been in if the payment had not been required; provided that the Borrower or such Guarantor, upon the request of the Lender or the Administrative Agent, agrees to repay the amount paid over to the Borrower or such Guarantor (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Lender or the Administrative Agent in the event the Lender or the Administrative Agent is required to repay such refund to such Governmental Authority. In such event, such Lender or the Administrative Agent, as the case may be, shall, at the Borrower’s request, provide the Borrower with a copy of any notice of assessment or other evidence of the requirement to repay such refund received from the relevant Governmental Authority (provided that such Lender or the Administrative Agent may delete any information therein that it deems confidential). A Lender or the Administrative Agent shall claim any refund that it determines is available to it, unless it concludes in its sole discretion that it would be adversely affected by making such a claim. No Lender nor the Administrative Agent shall be obliged to make available

​ 82

​ its tax returns (or any other information relating to its taxes that it deems confidential) to any Credit Party in connection with this clause (f) or any other provision of this Section 5.4.

(f)        If the Borrower determines that a reasonable basis exists for contesting an Indemnified Tax or Other Tax for which a Credit Party has paid additional amounts or indemnification payments, each Lender or the Administrative Agent, as the case may be, shall use reasonable efforts to cooperate with the Borrower as the Borrower may reasonably request in challenging such Tax. The Borrower shall indemnify and hold each Lender and the Administrative Agent harmless against any reasonable out-of-pocket expenses incurred by such Person in connection with any request made by the Borrower pursuant to this Section 5.4(f). Nothing in this Section 5.4(f) shall obligate any Lender or the Administrative Agent to take any action that such Person, in its sole judgment, determines may result in a material detriment to such Person.

(g)        For the avoidance of doubt, for purposes of this Section 5.4, the term “Lender” includes any Issuing Bank.

(h)        The agreements in this Section 5.4 shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

Section 5.5      Computations of Interest and Fees .

(a)        Interest on LIBOR Loans shall be calculated on the basis of a 360-day year for the actual days elapsed. Interest on ABR Loans and interest on overdue interest shall be calculated on the basis of a 365- (or 366-, as the case may be) day year for the actual days elapsed.

(b)        Fees and the average daily Stated Amount of Letters of Credit shall be calculated on the basis of a 360-day year for the actual days elapsed.

Section 5.6      Limit on Rate of Interest .

(a)        No Payment Shall Exceed Lawful Rate. Notwithstanding any other term of this Agreement, the Borrower shall not be obligated to pay any interest or other amounts under or in connection with this Agreement or otherwise in respect to any of the Obligations in excess of the amount or rate permitted under or consistent with any applicable law, rule or regulation.

(b)        Payment at Maximum Rate. If the Borrower is not obliged to make a payment that it would otherwise be required to make, as a result of Section 5.6(a), the Borrower shall make such payment to the maximum extent permitted by or consistent with applicable laws, rules and regulations.

(c)        Adjustment if Any Payment Exceeds Lawful Rate. If any provision of this Agreement or any of the other Credit Documents would obligate the Borrower or any other Credit Party to make any payment of interest or other amount payable to any Lender in an amount or calculated at a rate that would be prohibited by any applicable Requirement of Law, then notwithstanding such provision, such amount or rate shall be deemed to have

​ 83

​ been adjusted with retroactive effect to the Maximum Rate as would not be so prohibited by applicable Requirements of Law, such adjustment to be effected, to the extent necessary, by reducing the amount or rate of interest required to be paid by the Borrower to the affected Lender under Section 2.7.

(d)        Rebate of Excess Interest. Notwithstanding the foregoing, and after giving effect to all adjustments contemplated thereby, if any Lender shall have received from the Borrower an amount in excess of the maximum permitted by any applicable Requirement of Law, then the Borrower shall be entitled, by notice in writing to the Administrative Agent, to obtain reimbursement from that Lender in an amount equal to such excess, and pending such reimbursement, such amount shall be deemed to be an amount payable by that Lender to the Borrower.

ARTICLE VI

CONDITIONS PRECEDENT TO EFFECTIVE DATE

Section 6.1      Effective Date.  This Agreement shall be effective upon the satisfaction of the following conditions precedent, except as otherwise agreed or waived pursuant to Section 13.1.

(a)        Executed Credit Agreement.  The Administrative Agent (or its counsel) shall have received from each party hereto either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include electronic transmission of a signed signature page of this Agreement) that such party has signed a counterpart of this Agreement.

(b)        Secretary’s Certificate of the Borrower.  The Administrative Agent shall have received, in the case of the Borrower, each of the items referred to in subclauses (i), (ii) and (iii) below:

(i)         a certificate as to the good standing of the Borrower as of a recent date from the Secretary of State of the State of Delaware;

(ii)       a certificate of the Secretary or Assistant Secretary or similar officer of the Borrower dated the Effective Date and certifying:

(A)     that attached thereto is a true and complete copy of the limited partnership agreement of the Borrower as in effect on the Effective Date and at all times since a date prior to the date of the resolutions described in clause (B) below,

(B)      that attached thereto is a true and complete copy of resolutions duly adopted by the general partner of the Borrower authorizing the execution, delivery and performance of the Credit Documents to which the Borrower is a party and the Loans hereunder, and that such resolutions have not been modified, rescinded or amended and are in full force and effect on the Effective Date, that the certificate of limited partnership of the Borrower has not been amended since the date of the last amendment thereto disclosed pursuant to subclause (i) above,

​ 84

​ (C)      as to the incumbency and specimen signature of each officer executing any Credit Document or any other document delivered in connection herewith on behalf of the Borrower, and

(D)     as to the absence of any pending proceeding for the dissolution or liquidation of the Borrower; and

(iii)      a certificate of a director or an officer as to the incumbency and specimen signature of the Secretary or Assistant Secretary or similar officer executing the certificate pursuant to subclause (ii) above.

(c)        Secretary’s Certificate of the General Partner. The Administrative Agent shall have received, in the case of the General Partner, each of the items referred to in subclauses (i), (ii) and (iii) below:

(i)         a certificate as to the good standing of the General Partner as of a recent date from the Secretary of State of the State of Delaware;

(ii)       a certificate of the Secretary or Assistant Secretary or similar officer of the General Partner dated the Effective Date and certifying:

(A)     that attached thereto is a true and complete copy of the company agreement of the General Partner as in effect on the Effective Date and at all times since a date prior to the date of the resolutions described in clause (B) below,

(B)      that attached thereto is a true and complete copy of resolutions duly adopted by the general partner of the Borrower authorizing the execution, delivery and performance of the Credit Documents to which the General Partner is a party and the Loans hereunder, and that such resolutions have not been modified, rescinded or amended and are in full force and effect on the Effective Date, that the certificate of formation of the General Partner has not been amended since the date of the last amendment thereto disclosed pursuant to subclause (i) above,

(C)      as to the incumbency and specimen signature of each officer executing any Credit Document or any other document delivered in connection herewith on behalf of the General Partner, and

(D)     as to the absence of any pending proceeding for the dissolution or liquidation of the General Partner, and

(iii)      a certificate of a director or an officer as to the incumbency and specimen signature of the Secretary or Assistant Secretary or similar officer executing the certificate pursuant to subclause (ii) above.

​ 85

​ (d)        The Notes.  The Administrative Agent shall have received duly executed Notes payable to each Lender that has requested a Note in a principal amount equal to such Lender’s Commitment Percentage of the Commitment.

The Administrative Agent (or at the Administrative Agent’s direction, its counsel) shall notify the Borrower and the Lenders of the Effective Date, and such notice shall be conclusive and binding.

ARTICLE VII

CONDITIONS PRECEDENT TO THE FUNDING DATE

AND ALL SUBSEQUENT CREDIT EVENTS

Section 7.1      Funding Date.  The obligation of each Lender to advance the initial Loan hereunder and of each Issuing Bank to issue its initial Letter of Credit hereunder on the Funding Date, is subject to satisfaction (or waiver in accordance with Section 13.1) of the following conditions precedent:

(a)        Legal Opinions.  The Administrative Agent shall have received, on behalf of itself and the Secured Parties on the Funding Date, a customary written opinion of Baker Botts L.L.P., counsel to the Credit Parties, (i) dated the Funding Date, (ii) addressed to the Administrative Agent, the Lenders and each Issuing Bank and (iii) in form and substance reasonably satisfactory to the Administrative Agent. The Borrower, the other Credit Parties and the Administrative Agent hereby instruct such counsel to deliver such legal opinion.

(b)        Secretary’s Certificates of the Credit Parties.  The Administrative Agent shall have received, in the case of each Credit Party, each of the items referred to in subclauses (i), (ii) and (iii) below:

(i)         a certificate as to the good standing (to the extent such concept or a similar concept exists under the laws of such jurisdiction) of each such Credit Party as of a recent date from such Secretary of State (or other similar official) of the jurisdiction of its organization;

(ii)       a certificate of the Secretary or Assistant Secretary or similar officer of each Credit Party dated the Funding Date and certifying:

(A)     that attached thereto is a true and complete copy of the bylaws (or partnership agreement, limited liability company agreement or other equivalent governing documents) of such Credit Party as in effect on the Funding Date and at all times since a date prior to the date of the resolutions described in clause (B) below,

(B)      that attached thereto is a true and complete copy of resolutions duly adopted by the board of directors (or managing general partner, managing member or equivalent) of such Credit Party authorizing the execution, delivery and performance of the Credit Documents to which such Person is a party and, in the case of the Borrower, the Loans hereunder, and that such resolutions have not been modified, rescinded or

​ 86

​ amended and are in full force and effect on the Funding Date, that the certificate or articles of incorporation, certificate of limited partnership, articles of incorporation or certificate of formation of such Credit Party has not been amended since the date of the last amendment thereto disclosed pursuant to subclause (i) above,

(C)      as to the incumbency and specimen signature of each officer executing any Credit Document or any other document delivered in connection herewith on behalf of such Credit Party, and

(D)     as to the absence of any pending proceeding for the dissolution or liquidation of such Credit Party; and

(iii)      a certificate of a director or an officer as to the incumbency and specimen signature of the Secretary or Assistant Secretary or similar officer executing the certificate pursuant to subclause (ii) above.

(c)        Guarantee.  The Guarantee shall be in full force and effect.

(d)        Security Documents.  All of the Security Documents, including UCC or other applicable personal property and financing statements, reasonably requested by the Administrative Agent to be filed, registered or recorded to create the Liens sufficient to comply with the Collateral Coverage Minimum intended to be created by such Security Document and perfect such Liens to the extent required by such Security Documents and as necessary to comply with the Collateral Coverage Minimum shall have been delivered to the Administrative Agent for filing, registration or recording and none of the Collateral shall be subject to any other pledges, security interests or mortgages, except for Permitted Liens.

(e)        Local Counsel Opinions.  The Administrative Agent shall have received a favorable opinion of local counsel in those jurisdictions selected by Administrative Agent where a Security Document will be filed in such form and covering such matters as the Administrative Agent may reasonably request.

(f)        Fees and Expenses.  The Administrative Agent shall have received all fees payable thereto or to any Lender on or prior to the Funding Date, including all fees then due pursuant to the Fee Letter,  and, to the extent invoiced, all other amounts due and payable pursuant to the Credit Documents on or prior to the Funding Date, including, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses (including reasonable fees, charges and disbursements of outside counsel and recording fee for the filing of the Security Documents in the appropriate recording offices) required to be reimbursed or paid by the Credit Parties hereunder or under any Credit Document.

(g)        KYC.  The Administrative Agent shall have received prior to the Effective Date all documentation and other information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including without limitation, the Patriot Act that has been requested not less than five Business Days prior to the Funding Date.

​ 87

​ (h)        Notice of Borrowing. The Administrative Agent shall have received, in the case of an Advance, a Notice of Borrowing as required by Section 2.1(b) or, in the case of the issuance of a Letter of Credit, the applicable Issuing Bank and the Administrative Agent shall have received a Letter of Credit Application as required by Section 3.2(a).

The Administrative Agent (or at the Administrative Agent’s direction, its counsel) shall notify the Borrower and the Lenders of the Funding Date, and such notice shall be conclusive and binding.

Section 7.2      All Credit Events **.**The agreement of each Lender to make any Loan constituting a Credit Event requested to be made by it on any date from and after the Funding Date (other than on the Amendment No. 2 Effective Date) (excluding Loans required to be made by the Lenders in respect of Unpaid Drawings pursuant to Sections 3.3 and 3.4), and the obligation of any Issuing Bank to issue Letters of Credit on any date on or after the Funding Date (other than on the Amendment No. 2 Effective Date), is subject to the satisfaction of the following conditions precedent:

(a)        At the time of each such Credit Event and also after giving effect thereto, (a) no Default or Event of Default shall have occurred and be continuing and (b) all representations and warranties made by any Credit Party contained herein or in the other Credit Documents shall be true and correct in all material respects with the same effect as though such representations and warranties had been made on and as of the date of such Credit Event (except where such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct in all material respects as of such earlier date).

(b)        Prior to the making of each Loan (other than any Loan made pursuant to Section 3.4(a)), the Administrative Agent shall have received a Notice of Borrowing (whether in writing or by telephone) meeting the requirements of Section 2.1(b).

(c)        Prior to the issuance of each Letter of Credit, the Administrative Agent and the applicable Issuing Bank shall have received a Letter of Credit Application meeting the requirements of Section 3.2(a).

(d)        A representation and warranty made by the Borrower (which may be included in the Notice of Borrowing) that as of the end of the third Business Day on which such Borrowing will be funded, the Credit Parties shall not have any Excess Cash.

The acceptance of the benefits of each Credit Event after the Effective Date (other than on the Amendment No. 2 Effective Date) shall constitute a representation and warranty by each Credit Party to each of the Lenders that all the applicable conditions specified in this Article VII above have been satisfied as of that time.

The agreement of each Lender to make a Loan requested to be made by it on the Amendment No. 2 Effective Date shall be subject solely to the satisfaction of the condition contained in Section 7.2(b) hereof and the conditions in Amendment No. 2.

​ 88

​ ARTICLE VIII

REPRESENTATIONS, WARRANTIES AND AGREEMENTS

In order to induce the Lenders to enter into this Agreement, to make the Loans and issue or participate in Letters of Credit as provided for herein, the Borrower makes, on the date of each Credit Event, the following representations and warranties to, and agreements with, the Lenders, all of which shall survive the execution and delivery of this Agreement and the making of the Loans and the issuance of the Letters of Credit:

Section 8.1      Organizational Status.  The Borrower and each of its Restricted Subsidiaries is duly organized and validly existing and in good standing under the laws of the jurisdiction of such Person’s organization and has the organizational power and authority to own its property and assets and to transact its business as now conducted and has duly qualified and is authorized to do business and is in good standing (if applicable) in all jurisdictions where it is required to be so qualified, except where the failure to be so qualified would not reasonably be expected to have a Material Adverse Effect.

Section 8.2      Organizational Power and Authority; Enforceability.  The Borrower and each of its Restricted Subsidiaries has the power and authority to execute, deliver and carry out the terms and provisions of the Credit Documents to which it is a party and has taken all necessary partnership or other organizational action to authorize the execution, delivery and performance by it of the Credit Documents to which it is a party. Each Credit Party has duly executed and delivered each Credit Document to which it is a party and each such Credit Document constitutes the legal, valid and binding obligation of such Credit Party enforceable in accordance with its terms, subject to the effects of bankruptcy, insolvency, fraudulent conveyance, reorganization and other similar laws relating to or affecting creditors’ rights generally and general principles of equity (whether considered in a proceeding in equity or law).

Section 8.3      No Violation.  None of the execution, delivery or performance by any Credit Party of the Credit Documents to which it is a party or the compliance with the terms and provisions thereof will (a) contravene any Requirement of Law except to the extent such contravention would not reasonably be expected to result in a Material Adverse Effect, (b) result in any breach of any of the terms, covenants, conditions or provisions of, or constitute a default under, or result in the creation or imposition of (or the obligation to create or impose) any Lien upon any of the property or assets of such Credit Party (other than Liens created under the Credit Documents and Liens permitted hereunder) pursuant to the terms of any indenture, loan agreement, lease agreement, mortgage, deed of trust, agreement or other instrument to which such Credit Party is a party or by which it or any of its property or assets is bound (any such term, covenant, condition or provision, a “Contractual Requirement”) except to the extent such breach, default or Lien that would not reasonably be expected to result in a Material Adverse Effect or (c) violate any provision of the partnership agreement, certificate of formation or other organizational documents of such Credit Party.

Section 8.4      Litigation.  Except as set forth on Schedule 8.4, there are no actions, investigations, suits or proceedings (including Environmental Claims) pending or, to the knowledge of the Borrower, threatened in writing with respect to the Borrower or any Restricted Subsidiary that would reasonably be expected to result in a Material Adverse Effect.

​ 89

​ Section 8.5      Margin Regulations.  Neither the making of any Loan hereunder nor the use of the proceeds thereof will violate the provisions of Regulation T, Regulation U or Regulation X of the Board.

Section 8.6      Governmental Approvals.  The execution, delivery and performance of each Credit Document by the Credit Parties do not require any consent or approval of, registration or filing with, or other action by, any Governmental Authority, except for (a) such as have been obtained or made and are in full force and effect, (b) filings and recordings in respect of the Liens created pursuant to the Security Documents and (c) such consents, approvals, registrations, filings or actions the failure of which to obtain or make would not reasonably be expected to have a Material Adverse Effect.

Section 8.7      Investment Company Act.  No Credit Party is required to be registered as an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

Section 8.8      True and Complete Disclosure .

(a)        All written information (other than projections, estimates and information of a general economic nature or general industry nature) (the “Information”) concerning the Borrower or its Restricted Subsidiaries, the Transactions and any other transactions contemplated hereby prepared by or on behalf of the foregoing or their representatives and made available to any Lenders or the Administrative Agent in connection with the Transactions or the other transactions contemplated hereby, when taken as a whole, was true and correct in all material respects, as of the date such Information was furnished to the Lenders and as of the Amendment No. 2 Effective Date (with respect to Information provided prior to the Amendment No. 2 Effective Date) and did not, taken as a whole, contain any untrue statement of a material fact as of any such date or omit to state a material fact necessary in order to make the statements contained therein, taken as a whole, not materially misleading in light of the circumstances under which such statements were made.

(b)        The projections, estimates and information of a general economic nature or general industry nature prepared by or on behalf of the Borrower or any of its representatives that have been made available to any Lenders or the Administrative Agent in connection with the Transactions or the other transactions contemplated hereby have been prepared in good faith based upon assumptions believed by the Borrower to be reasonable as of the date thereof (it being understood that actual results may vary materially from any such projections), as of the date such projections and estimates were furnished to the Lenders (with respect to any projections, estimates or information of a general economic nature or general industry nature provided prior to the Amendment No. 2 Effective Date) and as of the Amendment No. 2 Effective Date.

Section 8.9       Financial Condition; Financial Statements.  As of the Amendment No. 2 Effective Date, the Borrower and its Restricted Subsidiaries do not have any material Indebtedness, any material guarantee obligations, contingent liabilities, off balance sheet liabilities, partnership liabilities for taxes or unusual forward or long-term commitments that, in each case, have not been

​ 90

​ disclosed on Schedule 8.9, except as would not reasonably be expected to result in a Material Adverse Effect.

Section 8.10    Tax Matters.  Except where the failure of which would not, individually or in the aggregate, be reasonably expected to have a Material Adverse Effect, (a) each of the Borrower and the Restricted Subsidiaries has filed all federal income Tax returns and all other Tax returns, domestic and foreign, required to be filed by it (including in its capacity as withholding agent) and has paid all Taxes payable by it that have become due, other than those (i) not yet delinquent or (ii) being contested in good faith by appropriate proceedings and as to which adequate reserves have been provided to the extent required by and in accordance with GAAP and (b) the Borrower and each of the Restricted Subsidiaries have provided adequate reserves in accordance with GAAP for all Taxes of the Borrower and the Restricted Subsidiaries not yet due and payable.

Section 8.11    Compliance with ERISA.  Each Plan is in compliance with ERISA, the Code and any applicable Requirement of Law; no Reportable Event has occurred (or is reasonably likely to occur) with respect to any Plan; no Plan is “insolvent” (within the meaning of Section 4245 of ERISA) or in “reorganization” (within the meaning of Section 4245 of ERISA) (or is reasonably likely to be insolvent or in reorganization) or is in “endangered” or “critical” status (within the meaning of Section 432 of the Code or Section 305 of ERISA), and no written notice of any such insolvency, reorganization, or endangered or critical status has been given to the Borrower or, to the knowledge of the Borrower, any ERISA Affiliate; each Plan that is subject to Title IV of ERISA has satisfied the minimum funding standards (within the meaning of Section 412 of the Code or Section 302 of ERISA) applicable to such Plan, and there has been no determination that any such Plan is, or is expected to be, in “at risk” status (within the meaning of Section 303(i)(4) of ERISA); none of the Borrower or any ERISA Affiliate has incurred (or is reasonably likely to incur) any liability to or on account of a Plan pursuant to Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code nor has the Borrower or, to the knowledge of the Borrower, any ERISA Affiliate, been notified in writing that it will incur any liability under any of the foregoing Sections with respect to any Plan; no proceedings have been instituted (or are reasonably likely to be instituted) to terminate or to reorganize any Plan or to appoint a trustee to administer any Plan, and no written notice of any such proceedings has been given to the Borrower or, to the knowledge of the Borrower, any ERISA Affiliate; and no lien imposed under the Code or ERISA on the assets of the Borrower or any ERISA Affiliate exists (or is reasonably likely to exist) nor has the Borrower or, to the knowledge of the Borrower, any ERISA Affiliate been notified in writing that such a lien will be imposed on the assets of the Borrower or any ERISA Affiliate on account of any Plan, except to the extent that a breach of any of the representations or warranties in this Section 8.11 would not result, individually or in the aggregate, in an amount of liability that would be reasonably likely to have a Material Adverse Effect. No Plan (other than a Multiemployer Plan) has an Unfunded Current Liability that would, individually or when taken together with any other liabilities referenced in this Section 8.11, be reasonably likely to have a Material Adverse Effect. With respect to Plans that are Multiemployer Plans, the representations and warranties in this Section 8.11 other than any made with respect to (i) liability under Section 4201 or 4204 of ERISA or (ii) liability for “termination” or “reorganization” (within the meaning of Title IV of ERISA) of such Plans under ERISA, are made to the best knowledge of the Borrower.

​ 91

​ Section 8.12     Subsidiaries.  As of the Amendment No. 2 Effective Date, the Subsidiaries of the Borrower are listed on Schedule 8.12 (which Schedule shall be provided by the Borrower to the Administrative Agent and made part of this Agreement on the Amendment No. 2 Effective Date) and such Schedule 8.12 shall indicate whether such Subsidiary is a Restricted Subsidiary or an Unrestricted Subsidiary.

Section 8.13   Intellectual Property.  The Borrower owns or has obtained valid rights to use all intellectual property, free from any burdensome restrictions, that is necessary for the operation of its business as currently conducted and as proposed to be conducted, except where the failure to obtain any such rights would not reasonably be expected to have a Material Adverse Effect. The operation of the business of the Borrower, as currently conducted and as proposed to be conducted, does not infringe, misappropriate, violate or otherwise conflict with the proprietary rights of any third party, except as would not reasonably be expected to have a Material Adverse Effect.

Section 8.14    Environmental Laws.  Except as would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect:

(a)        (i) the Borrower and each of the Restricted Subsidiaries are in compliance with all Environmental Laws; (ii) neither the Borrower nor any Restricted Subsidiary has received written notice of any Environmental Claim or any other liability under any Environmental Law; (iii) neither the Borrower nor any Restricted Subsidiary is conducting any investigation, removal, remedial or other corrective action pursuant to any Environmental Law at any location; and (iv) no underground storage tank or related piping, or any impoundment or disposal area containing Hazardous Materials has been used by the Borrower or any of its Restricted Subsidiaries or, to the knowledge of the Borrower, is located at, on or under any Oil and Gas Properties currently owned or leased by the Borrower or any of its Restricted Subsidiaries.

(b)        Neither the Borrower nor any of the Restricted Subsidiaries has treated, stored, transported, released or disposed or arranged for disposal or transport for disposal of Hazardous Materials at, on, under or from any currently or formerly owned or leased Oil and Gas Properties or facility in a manner that would reasonably be expected to give rise to liability of the Borrower or any Restricted Subsidiary under Environmental Law.

Section 8.15    Properties .

(a)        Each Credit Party has good and defensible title to the Borrowing Base Properties evaluated in the most recently delivered Reserve Report (other than those (i) disposed of in compliance with Section 10.2 since delivery of such Reserve Report, (ii) leases that have expired in accordance with their terms and (iii) with title defects disclosed in writing to the Administrative Agent), and valid title to all its material personal properties, in each case, free and clear of all Liens other than Permitted Liens, except in each case where the failure to have such title would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect. After giving full effect to the Liens permitted by Article X, the Borrower owns the working interests and net revenue interests attributable to its Oil and Gas Properties as reflected in the most recently delivered Reserve

​ 92

​ Report, and the ownership of such properties shall not in any material respect obligate the Borrower to bear the costs and expenses relating to the maintenance, development and operations of each such property in an amount in excess of the working interest of each property set forth in the most recently delivered Reserve Report that is not offset by a corresponding proportionate increase in the Borrower’s net revenue interest in such property.

(b)        All material leases and agreements necessary for the conduct of the business of the Borrower are valid and subsisting and are in full force and effect, except to the extent that any such failure to satisfy the foregoing would not reasonably be expected to have a Material Adverse Effect.

(c)        The rights and properties presently owned, leased or licensed by the Credit Parties, including all easements and rights of way, include all rights and properties necessary to permit the Credit Parties to conduct their respective businesses as currently conducted, except to the extent any failure to have any such rights or properties would not reasonably be expected to have a Material Adverse Effect.

(d)        All of the properties of the Borrower that are reasonably necessary for the operation of its business are in good working condition and are maintained in accordance with prudent business standards, except to the extent any failure to satisfy the foregoing would not reasonably be expected to have a Material Adverse Effect.

Section 8.16    Solvency.  The Borrower is Solvent, and the Borrower and its Restricted Subsidiaries, on a consolidated basis, are Solvent.

Section 8.17    Insurance.  The properties of the Borrower and its Restricted Subsidiaries are insured in the manner contemplated by Section 9.3.

Section 8.18    Hedge Transactions; Qualified EPC Counterparty.  Schedule 8.18 sets forth, as of the Amendment No. 2 Effective Date, a true and complete list of all material commodity Hedge Transactions of each Credit Party, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark to market value thereof (as of the last Business Day of the most recent fiscal quarter preceding the Amendment No. 2 Effective Date and for which a mark to market value is reasonably available), all credit support agreements relating thereto (including any margin required or supplied) and the counterparty to each such agreement.  The Borrower is a Qualified EPC Counterparty.

Section 8.19    Patriot Act; OFAC .

(a)        On the Amendment No. 2 Effective Date, each Credit Party is in compliance in all material respects with the Patriot Act, and the Borrower has provided to the Administrative Agent all information related to the Credit Parties (including but not limited to names, addresses and tax identification numbers (if applicable)) reasonably requested in writing by the Administrative Agent and mutually agreed to be required by the Patriot Act to be obtained by the Administrative Agent or any Lender.

​ 93

​ (b)        None of the Borrower or any of its Restricted Subsidiaries nor, to the knowledge of Borrower, any partner, manager, director, officer, agent, employee or Affiliate of the Borrower or any of the Restricted Subsidiaries is currently subject to any U.S. sanctions administered by the Office of Foreign Assets Control of the U.S. Treasury Department (“OFAC”); and the Borrower will not directly or indirectly use the proceeds of the Loans or the Letters of Credit or otherwise make available such proceeds to any Person, for the purpose of financing the activities of any Person currently subject to any U.S. sanctions administered by OFAC.

(c)        As of the Amendment No. 2 Effective Date, the information included in the Beneficial Ownership Certification is true and correct in all respects.

Section 8.20    No Material Adverse Effect.  Since December 31, 2019, there has been no event or circumstance that has had or would reasonably be expected to have a Material Adverse Effect.

Section 8.21    Foreign Corrupt Practices Act.  Neither the Borrower nor, to the knowledge of the Borrower, any of its partners, directors, officers, agents or employees has (i) used any partnership funds for any unlawful contribution, gift, entertainment or other unlawful expense relating to political activity, (ii) made any direct or indirect unlawful payment to any government official or employee from corporate funds, (iii) violated or is in violation of any provision of the U.S. Foreign Corrupt Practices Act of 1977 or (iv) made any unlawful bribe, rebate, payoff, influence payment, kickback or other unlawful payment.

Section 8.22     Security Interests.  The Obligations are secured by Liens in the Collateral granted in favor of the Administrative Agent, for the benefit of the Lenders, and such Liens are or will be perfected (in each case, to the extent contemplated by this Agreement and the Security Documents) (i) by the filing of a UCC financing statement in the states in which each applicable Credit Party is located, (ii) by filing mortgages affecting the Borrowing Base Properties, as-extracted collateral and/or fixtures (as applicable) in the real property or other appropriate records of the parish or county in which the applicable real property or fixtures are located, or (iii) by possession or control.

Section 8.23    Accounts.  As of the Amendment No. 2 Effective Date, Schedule 8.23 lists all Deposit Accounts, Securities Accounts and Commodity Accounts maintained by or for the benefit of any Credit Party.

Section 8.24    Gas Imbalances; Prepayments.  On the Amendment No. 2 Effective Date, on a net basis, there are no gas imbalances, take or pay or other prepayments exceeding one-half Bcfe of hydrocarbon volumes (stated on a gas equivalent basis) in the aggregate, with respect to the Borrower’s and its Restricted Subsidiaries Oil and Gas Properties that would require the Borrower or any Restricted Subsidiary to deliver Hydrocarbons either generally or produced from their Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor.

Section 8.25   Marketing of Production.  On the Amendment No. 2 Effective Date, no material agreements exist (which are not cancelable on 60 days’ notice or less without penalty or

​ 94

​ detriment) for the sale of production of the Borrower’s or its Restricted Subsidiaries’ Hydrocarbons at a fixed non-index price (including calls on, or other rights to purchase, production, whether or not the same are currently being exercised) that (i) represent in respect of such agreements 2.5% or more of the Borrower’s and its Restricted Subsidiaries’ average monthly production of Hydrocarbon volumes and (ii) have a maturity or expiry date of longer than six months from the Amendment No. 2 Effective Date.

ARTICLE IX

AFFIRMATIVE COVENANTS

A deviation from the provisions of this Article IX shall not constitute an Event of Default under this Agreement if such deviation is consented to in writing by the Administrative Agent and Majority Lenders prior to the date of deviation.  The Borrower hereby covenants and agrees that on the Amendment No. 2 Effective Date and thereafter, until the Total Commitment and each Letter of Credit have terminated (unless such Letters of Credit have been collateralized or other arrangements in respect thereof have been made on terms and conditions reasonably satisfactory to each applicable Issuing Bank following the termination of the Total Commitment)  and the Loans and Unpaid Drawings, together with interest, fees and all other Obligations incurred hereunder (other than Hedging Obligations, Cash Management Obligations or contingent indemnification obligations not then due and payable), are paid in full,  Borrower will comply with the covenants contained in this Article IX:

Section 9.1      Information Covenants.  The Borrower will furnish to the Administrative Agent (which shall promptly make such information available to the Lenders in accordance with its customary practice):

(a)        Annual Financial Statements.  Beginning with financial statements for fiscal year 2020, on or before the date that is 120 days (or such longer period as the Administrative Agent may reasonably agree) after the end of each such fiscal year, the audited consolidated balance sheets of the Borrower, in each case as at the end of such fiscal year, and the related consolidated statements of operations, partners’ equity and cash flows for such fiscal year, setting forth comparative consolidated figures for the preceding fiscal years prepared in accordance with GAAP, and certified by independent certified public accountants reasonably acceptable to the Administrative Agent whose opinion shall not be materially qualified with a “going concern” or like qualification or exception with respect to the Borrower or any of its Restricted Subsidiaries (other than with respect to, or resulting from, (x) the occurrence of the Maturity Date within one year from the date such opinion is delivered or (y) any potential inability to satisfy the financial covenants set out in Sections 10.3 or 10.4 hereof on a future date or in a future period), together with a certificate of such accounting firm unless such accounting firm is restricted from providing such a certificate by its policies or unless the delivery of such certificate increases the costs payable by the Borrower to such accounting firm, stating that in the course of either (i) its regular audit of the business of the Borrower and its Subsidiaries, which audit was conducted in accordance with generally accepted auditing standards or (ii) performing certain other procedures permitted by professional standards, such accounting firm has obtained no knowledge of any Event of Default relating to the financial covenants set forth in Sections 10.3 and 10.4 that has occurred and is continuing or, if in the opinion of such

​ 95

​ accounting firm such an Event of Default has occurred and is continuing, a statement as to the nature thereof.

(b)        Quarterly Financial Statements. On or before the date that is 60 days (or such longer period as the Administrative Agent may reasonably agree) after the end of each of the first three quarterly accounting periods of each fiscal year, beginning with the quarterly period ending March 31, 2021, the consolidated balance sheets of the Borrower, in each case as at the end of such quarterly period and the related statements of operations, partners’ equity and cash flows for such quarterly accounting period and for the elapsed portion of the fiscal year ended with the last day of such quarterly period, and setting forth comparative figures for the related periods in the prior fiscal year or, in the case of such balance sheet, for the last day of the prior fiscal year, all of which shall be certified by a Financial Officer of the Borrower as fairly presenting in all material respects the financial condition, results of operations, shareholders’ equity and cash flows of the Borrower and its Restricted Subsidiaries in accordance with GAAP, subject to changes resulting from audit and normal year­end audit adjustments and the absence of footnotes .

(c)        Compliance Certificates. At the earlier of the time of the delivery of the financial statements provided for in Section 9.1(a) and Section 9.1(b) or within five (5) Business Days after the date on which such financial statements are required to be filed with the Securities and Exchange Commission (after giving effect to any permitted extensions), a Compliance Certificate of a Financial Officer of the Borrower which certificate shall also set forth (i) the calculations required to establish whether the Borrower and its Restricted Subsidiaries were in compliance with each of the financial covenants set forth in Section 10.3 and 10.4 as at the end of such fiscal year or period, as the case may be, (ii) a listing each Material Subsidiary as of such date of delivery and (iii) the Cash Available For Distribution for the preceding fiscal quarter.

(d)        Notice of Default; Litigation. Promptly after an Authorized Officer of the Borrower obtains actual knowledge thereof, notice of (i) the occurrence of any Default or Event of Default, which notice shall specify the nature thereof, the period of existence thereof and what action the Borrower proposes to take with respect thereto and (ii) any litigation or governmental proceeding pending against the Borrower or any of the Restricted Subsidiaries that would reasonably be expected to be determined adversely and, if so determined, to result in a Material Adverse Effect.

(e)        Environmental Matters. Promptly after obtaining actual knowledge of any one or more of the following environmental matters, unless such environmental matters would not, individually, or when aggregated with all other such matters, be reasonably expected to result in a Material Adverse Effect, notice of:

(i)         any pending or threatened Environmental Claim against any Credit Party or any Oil and Gas Properties;

(ii)       any condition or occurrence on any Oil and Gas Properties that (A) would reasonably be expected to result in noncompliance by any Credit Party with any applicable Environmental Law or (B) would reasonably be anticipated to form

​ 96

​ the basis of an Environmental Claim against any Credit Party or any Oil and Gas Properties;

(iii)      any condition or occurrence on any Oil and Gas Properties that would reasonably be anticipated to cause such Oil and Gas Properties to be subject to any restrictions on the ownership, occupancy, use or transferability of such Oil and Gas Properties under any Environmental Law; and

(iv)       the conduct of any investigation, or any removal, remedial or other corrective action in response to the actual or alleged presence, release or threatened release of any Hazardous Material on, at, under or from any Oil and Gas Properties.

All such notices shall describe in reasonable detail the nature of the claim, investigation, condition, occurrence or removal or remedial action and the response thereto.

(f)        Certificate of Authorized Officer – Hedge Transactions.  Concurrently with any delivery of each Reserve Report, setting forth as of the date of the Reserve Report, a true and complete list of all material commodity Hedge Transactions of the Borrower and each Credit Party, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark-to-market value thereof (as of the last Business Day of the most recent date such mark-to-market value is reasonably available), any new credit support agreements relating thereto not listed on Schedule 8.18 or on any previously delivered certificate delivered pursuant to this clause (f), any margin required or supplied under any credit support document and the counterparty to each such agreement.

(g)        [Reserved].

(h)        [Reserved].

(i)         Other Information.  (i) Promptly upon filing thereof, copies of any filings (including on Form 10-K, 10-Q or 8-K) or registration statements with, and reports to, the SEC or any analogous Governmental Authority in any relevant jurisdiction by the Borrower or any Restricted Subsidiaries (other than amendments to any registration statement (to the extent such registration statement, in the form it becomes effective, is delivered to the Administrative Agent), exhibits to any registration statement and, if applicable, any registration statements on Form S-8), (ii) copies of all financial statements, proxy statements, notices and reports that the Borrower or any of the Restricted Subsidiaries shall send to the holders of any publicly issued debt of the Borrower and/or any of its Restricted Subsidiaries, in each case in their capacity as such holders, lenders or agents, (iii) upon the request of the Administrative Agent, information and documentation reasonably requested by the Administrative Agent or any Lender for purposes of compliance with applicable “know your customer” requirements under the PATRIOT Act or other applicable Anti-Money Laundering Laws, (iv) promptly after an Authorized Officer of the Borrower obtains actual knowledge thereof, the Borrower shall provide to the Administrative Agent written notice of any change in the information provided in the Beneficial Ownership Certification that would result in a change to the list of beneficial

​ 97

​ owners identified in parts (c) or (d) of such certification and (v) such other information regarding the operations, business affairs and the financial condition of the Borrower and the Restricted Subsidiaries as the Administrative Agent on its own behalf or on behalf of any Lender (acting through the Administrative Agent) may reasonably request in writing from time to time.

(j)         Annual Budget.  At the time of the delivery of the financial statements provided for in Section 9.1(a), the annual budget of the Borrower for the next fiscal year after the fiscal year covered by such financial statements, set forth on a monthly basis for such fiscal year covered by the annual budget.

It is understood that documents required to be delivered pursuant to Sections 9.1(a), 9.1(b), 9.1(c), 9.1(f), 9.1(g) and 9.1(j) may be delivered electronically and if so delivered, shall be deemed to have been delivered on the date (i) on which the Borrower posts such documents, or provides a link thereto on the Borrower’s website on the Internet at the website address listed on Schedule 13.2 or (ii) on which such documents are transmitted by electronic mail to the Administrative Agent; provided that the Borrower shall notify (which may be by facsimile or electronic mail) the Administrative Agent of the posting of any such documents. Each Lender shall be solely responsible for timely accessing posted documents.  Notwithstanding the foregoing, in respect of any information required to be delivered to the Administrative Agent and/or the Lenders pursuant to this Section 9.1, to the extent such information has been published on EDGAR at or prior to the time the information is required to be delivered under this Agreement, Borrower may send to the Administrative Agent a notice that such information is available on EDGAR and delivery of such notice shall satisfy the Borrower’s requirements under this Section 9.1 to deliver to the Administrative Agent and each Lender such information.

Section 9.2      Books, Records and Inspections .

(a)        The Borrower will (i) permit officers and designated representatives of the Administrative Agent or officers and designated representatives of the Majority Lenders (as accompanied by the Administrative Agent) to visit and inspect any of the properties or assets of the Borrower in whomsoever’s possession to the extent that it is within such party’s control to permit such inspection (and shall use commercially reasonable efforts to cause such inspection to be permitted to the extent that it is not within such party’s control to permit such inspection), and to examine the financial records of the Borrower and discuss the affairs, finances, accounts and condition of the Borrower with its officers and independent accountants therefor, in each case of the foregoing upon reasonable advance notice to the Borrower, all at such reasonable times and intervals during normal business hours and to such reasonable extent as the Administrative Agent or the Majority Lenders may desire (and subject, in the case of any such meetings or advice from such independent accountants, to such accountants’ customary policies and procedures); provided that, excluding any such visits and inspections during the continuation of an Event of Default only one such visit per fiscal year shall be at the Borrower’s expense; provided, further, that when an Event of Default exists, the Administrative Agent (or any of its representatives or independent contractors) or any representative of the Majority Lenders may do any of the foregoing at the expense of the Borrower at any time during normal business hours and upon reasonable advance notice and (ii) during the continuance of an Event of Default,

​ 98

​ provide contact information for each bank or institution where each Credit Party has a Deposit Account and/or Securities Account to the Administrative Agent upon the Administrative Agent’s written request and the Borrower hereby authorizes the Administrative Agent to contact such bank(s) or institution(s) in order to request bank statements and/or balances during the continuance of such Event of Default.  The Administrative Agent and the Majority Lenders shall give the Borrower the opportunity to participate in any discussions with the Borrower’s independent public accountants. Notwithstanding anything to the contrary in this Section 9.2, the Borrower will not be required to disclose, permit the inspection, examination or making copies or abstracts of, or discussion of, any document, information or other matter (i) that constitutes non-financial trade secrets or non-financial proprietary information, (ii) in respect of which disclosure to the Administrative Agent or any Lender (or their respective representatives or contractors) is prohibited by any Requirement of Law or any binding agreement or (iii) that is subject to attorney-client or similar privilege or constitutes attorney work product.

(b)        The Borrower will maintain financial records in accordance with GAAP in all material respects.

Section 9.3      Maintenance of Insurance.  The Borrower will at all times maintain in full force and effect, pursuant to self-insurance arrangements or with insurance companies that the Borrower believes (in the good faith judgment of the management of the Borrower) are financially sound and reputable at the time the relevant coverage is placed or renewed, insurance in at least such amounts (after giving effect to any self-insurance which the Borrower believes (in the good faith judgment of management of the Borrower) is reasonable and prudent in light of the size and nature of its business) and against at least such risks (and with such risk retentions) as the Borrower believes (in the good faith judgment of management of the Borrower) is reasonable and prudent in light of the size and nature of its business; and will furnish to the Administrative Agent, upon written request from the Administrative Agent, information presented in reasonable detail as to the insurance so carried. The Secured Parties shall be the additional insureds on any such liability insurance as their interests may appear and, if property insurance is obtained, the Administrative Agent shall be the loss payee under any such property insurance; provided that, so long as no Event of Default has occurred and is then continuing, the Secured Parties will provide any proceeds of such property insurance to the Borrower to the extent that the Borrower undertakes to apply such proceeds to the reconstruction, replacement or repair of the property insured thereby.

Section 9.4       Payment of Taxes.  The Borrower shall, and shall cause each Restricted Subsidiary to, pay its obligations in respect of all Tax liabilities, assessments and governmental charges, before the same shall become delinquent or in default, except where (i) the amount or validity thereof is being contested in good faith by appropriate proceedings and the Borrower or such applicable Restricted Subsidiary has set aside on its books adequate reserves therefor in accordance with GAAP or (ii) the failure to make payment could not reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect.

Section 9.5       Maintenance of Existence.  The Borrower will do or cause to be done, all things necessary to preserve and keep, or cause to be kept, in full force and effect its and the Restricted Subsidiaries’ existence, partnership rights and authority (except as otherwise permitted under Sections 10.2 and 10.5 or with respect to any Restricted Subsidiary (other than a Restricted

​ 99

​ Subsidiary that has granted a Mortgage to the Administrative Agent or any trustee for the Administrative Agent, unless (a) such Restricted Subsidiary assigns, transfers or otherwise modifies such Mortgage or the related Borrowing Base Properties in a manner reasonably satisfactory to the Administrative Agent for maintaining a Lien in favor of the Administrative Agent on such Borrowing Base Properties and (b) immediately after such Restricted Subsidiary ceases to exist, the Borrower is in compliance with the Collateral Coverage Minimum)) that the Borrower makes a good faith determination that such Restricted Subsidiary’s existence is no longer desirable or necessary in the conduct of the business of the Borrower and its Restricted Subsidiaries).

Section 9.6      Compliance with Statutes, Regulations, Etc.  The Borrower will, and will cause its Restricted Subsidiaries to, comply with all Requirements of Law applicable them or their property, including all governmental approvals or authorizations required to conduct their business, and to maintain all such governmental approvals or authorizations in full force and effect, in each case except where the failure to do so would not reasonably be expected to have a Material Adverse Effect.

Section 9.7      ERISA .

(a)        Promptly after the Borrower knows or has reason to know of the occurrence of any of the following events that, individually or in the aggregate (including in the aggregate such events previously disclosed or exempt from disclosure hereunder, to the extent the liability therefor remains outstanding), would be reasonably likely to have a Material Adverse Effect, the Borrower will deliver to the Administrative Agent a certificate of an Authorized Officer setting forth details as to such occurrence and the action, if any, that the Borrower or such ERISA Affiliate is required or proposes to take, together with any notices (required, proposed or otherwise) given to or filed with or by the Borrower, such ERISA Affiliate, the PBGC, a Plan participant (other than notices relating to an individual participant’s benefits) or the Plan administrator with respect thereto: that a Reportable Event has occurred; that an accumulated funding deficiency has been incurred or an application is to be made to the Secretary of the Treasury for a waiver or modification of the minimum funding standard (including any required installment payments) or an extension of any amortization period under Section 412 of the Code with respect to a Plan; that a Plan having an Unfunded Current Liability has been or is to be terminated, reorganized, partitioned or declared insolvent under Title IV of ERISA (including the giving of written notice thereof); that a Plan has an Unfunded Current Liability that has or will result in a lien under ERISA or the Code; that proceedings will be or have been instituted to terminate a Plan having an Unfunded Current Liability (including the giving of written notice thereof); that a proceeding has been instituted against the Borrower or an ERISA Affiliate pursuant to Section 515 of ERISA to collect a delinquent contribution to a Plan; that the PBGC has notified the Borrower or any ERISA Affiliate of its intention to appoint a trustee to administer any Plan; that the Borrower or any ERISA Affiliate has failed to make a required installment or other payment pursuant to Section 412 of the Code with respect to a Plan; or that the Borrower or any ERISA Affiliate has incurred or will incur (or has been notified in writing that it will incur) any liability (including any contingent or secondary liability) to or on account of a Plan pursuant to Section 409, 502(i),

​ 100

​ 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code.

(b)        Promptly following any request therefor, the Borrower will deliver to the Administrative Agent copies of (i) any documents described in Section 101(k) of ERISA that the Borrower and any of its Subsidiaries may request with respect to any Multiemployer Plan and (ii) any notices described in Section 101(l) of ERISA that the Borrower and any of its Restricted Subsidiaries may request with respect to any Multiemployer Plan; provided that if the Borrower or any of its Restricted Subsidiaries has not requested such documents or notices from the administrator or sponsor of the applicable Multiemployer Plan, the Borrower or the applicable Restricted Subsidiaries shall promptly make a request for such documents or notices from such administrator or sponsor and shall provide copies of such documents and notices promptly after receipt thereof; and provided further that if the Borrower or any of its Restricted Subsidiaries has not requested such documents or notices from the administrator or sponsor of the applicable Multiemployer Plan, the Borrower or the applicable Restricted Subsidiaries shall not be required to make a request for such documents or notices more than once during any one twelve month period.

Section 9.8      Maintenance of Properties.  The Borrower will, and will cause its Restricted Subsidiaries to, except in each case where the failure to so comply would not reasonably be expected to result in a Material Adverse Effect:

(a)        operate its Oil and Gas Properties and other material properties or cause such Oil and Gas Properties and other material properties to be operated in a careful and efficient manner in accordance with the practices of the industry and in compliance with all applicable Contractual Requirements and all applicable Requirements of Law, including applicable proration requirements and Environmental Laws, and all applicable Requirements of Law of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom;

(b)        keep and maintain all property material to the conduct of its business in good working order and condition, ordinary wear and tear excepted, and preserve, maintain and keep in good repair, working order and efficiency (ordinary wear and tear excepted) all of its material Oil and Gas Properties and other material properties, including all equipment, machinery and facilities; and

(c)        to the extent a Credit Party is not the operator of any property described in clauses (a) and (b), the Borrower shall use commercially reasonable efforts to cause the operator to comply with this Section 9.8.

Section 9.9      Transactions with Affiliates.  The Borrower will, and will cause its Restricted Subsidiaries to, conduct any transaction or series of related transactions involving aggregate payments or consideration in excess of $2,000,000 with any of its Affiliates on terms that are substantially as favorable to the Borrower or such Restricted Subsidiary as it would obtain at the time in a comparable arm’s-length transaction with a Person that is not an Affiliate, as

​ 101

​ determined by the partners, board of directors or managers of the Borrower in good faith; provided that the foregoing restrictions shall not apply to:

(a)        the consummation of the Transactions, including the payment of Transaction Expenses;

(b)        equity issuances, repurchases, retirements, redemptions or other acquisitions or retirements of Equity Interests by the Borrower permitted under Article X;

(c)        loans, advances and other transactions between or among the Borrower, any Subsidiary or any joint venture (regardless of the form of legal entity) in which the Borrower or any Subsidiary has invested (and which Subsidiary or joint venture would not be an Affiliate of the Borrower or such Subsidiary, but for the Borrower’s or such Subsidiary’s ownership of Equity Interests in such joint venture or such Subsidiary) to the extent permitted under Section 10.15;

(d)        employment and severance arrangements and health, disability and similar insurance or benefit plans between the Borrower and the Subsidiaries and their respective directors, officers, employees or consultants (including management and employee benefit plans or agreements, subscription agreements or similar agreements pertaining to the repurchase of Equity Interests pursuant to put/call rights or similar rights with current or former employees, officers, directors or consultants and equity option or incentive plans and other compensation arrangements) in the ordinary course of business or as otherwise approved by the general partner,  board of directors or managers of the Borrower (or any direct or indirect parent thereof);

(e)        Restricted Payments, Investments, Dispositions, redemptions, repurchases and other actions permitted under Article X;

(f)        any issuance of Equity Interests or other payments, awards or grants in cash, securities, Equity Interests or otherwise pursuant to, or the funding of, employment arrangements, equity options and equity ownership plans approved by the general partner, board of directors or board of managers of the Borrower (or any direct or indirect parent thereof);

(g)        transactions with joint ventures for the purchase or sale of goods, equipment and services entered into in the ordinary course of business and in a manner consistent with prudent business practices followed by companies in the oil and gas industry;

(h)        any transaction in respect of which the Borrower delivers to the Administrative Agent a letter addressed to the general partner, board of directors or managers of the Borrower from an accounting, appraisal or investment banking firm, in each case of nationally-recognized standing that is in the good faith determination of the Borrower qualified to render such letter, which letter states that such transaction is (i) fair, from a financial point of view, to the Borrower or the applicable Restricted Subsidiary or (ii) on terms, taken as a whole, that are no less favorable to the Borrower or the applicable Restricted Subsidiary than would be obtained in a comparable arm’s length transaction with a Person that is not an Affiliate;

​ 102

​ (i)         customary agreements and arrangements with oil and gas royalty trusts and master limited partnership agreements that comply with the affiliate transaction provisions of such royalty trust or master limited partnership agreement;

(j)         transactions pursuant to agreements to be entered into by various Credit Parties and their Subsidiaries in connection with any Drop-Down Acquisition and the transactions related thereto,

(k)        transactions between or among the Borrower and its Restricted Subsidiaries;

(l)         transactions pursuant to the Management Services Agreement and any amendments, restatements, supplements or other modifications thereto that are not, taken as a whole, materially less favorable to the Borrower and the Restricted Subsidiaries than such agreement as in effect on the Funding Date; or

(m)       any transaction with an Affiliate if such transaction has been approved by the conflicts committee of the General Partner and, prior to the consummation of such transaction, the Administrative Agent is advised in writing of such transaction and the conflicts committee of the General Partner’s approval of such transaction.

Section 9.10   End of Fiscal Years; Fiscal Quarters.  The Borrower will, for financial reporting purposes, cause each of its fiscal years and fiscal quarters to end on dates consistent with past practice; provided, however, that the Borrower may, upon written notice to the Administrative Agent change the financial reporting convention specified above to any other financial reporting convention reasonably acceptable to the Administrative Agent, in which case the Borrower and the Administrative Agent will, and are hereby authorized by the Lenders to, make any adjustments to this Agreement that are necessary in order to reflect such change in financial reporting.

Section 9.11    Additional Guarantors, Grantors and Collateral .

(a)        Subject to any applicable limitations set forth in the Guarantee or the Security Documents, the Borrower will cause (i) any Restricted Subsidiary (other than any Excluded Subsidiary) formed or otherwise purchased, designated or acquired after the Effective Date (including pursuant to a Permitted Acquisition) and (ii) any Restricted Subsidiary of the Borrower that ceases to be an Excluded Subsidiary, in each case within thirty (30) days from the date of such formation, acquisition, designation or cessation, as applicable (or such longer period as the Administrative Agent may agree in its reasonable discretion) to execute a supplement to each of the Guarantee and the Pledge Agreement, substantially in the form required by the respective agreement, in order to become a Guarantor under the Guarantee and a pledgor under the Pledge Agreement.

(b)        Subject to any applicable limitations set forth in the Security Documents, the Borrower will pledge, and, if applicable, will cause each other Subsidiary Guarantor (or Person required to become a Subsidiary Guarantor pursuant to Section 9.11(a)) to pledge, to the Administrative Agent, for the benefit of the Secured Parties, (i) all of the Equity Interests of each Restricted Subsidiary that is not an Excluded Subsidiary directly owned by the Borrower or any Subsidiary Guarantor (or Person required to become a

​ 103

​ Guarantor pursuant to Section 9.11(a)), in each case, formed or otherwise purchased or acquired after the Effective Date, pursuant to a supplement to the Pledge Agreement in substantially the form required by the Pledge Agreement and (ii) except with respect to intercompany Indebtedness, all evidences of Indebtedness for borrowed money in a principal amount in excess of $1,000,000 (individually) that is owing to the Borrower or any Guarantor (or Person required to become a Guarantor pursuant to Section 9.11(a)) to the extent such Indebtedness is evidenced by a promissory note, pursuant to a security agreement in the form reasonably prescribed by the Administrative Agent.

(c)        The Borrower agrees that all Indebtedness of (i) the Borrower that is owing to any Credit Party (or a Person required to become a Subsidiary Guarantor pursuant to Section 9.11(a)) and (ii) any Credit Party (or a Person required to become a Subsidiary Guarantor pursuant to Section 9.11(a)) owing to the Borrower shall be evidenced by the Intercompany Note, which Intercompany Note shall be required to be pledged to the Administrative Agent, for the benefit of the Secured Parties, pursuant to a security agreement in the form prescribed by the Administrative Agent.

(d)        In connection with each redetermination (but not any adjustment) of the Borrowing Base, the Borrower shall review the applicable Reserve Report, if any, and the list of current Mortgaged Properties, to ascertain whether the PV-9 of the Mortgaged Properties (calculated at the time of redetermination) meets the Collateral Coverage Minimum after giving effect to exploration and production activities, acquisitions, Dispositions and production. In the event that the PV-9 of the Mortgaged Properties (calculated at the time of redetermination) does not meet the Collateral Coverage Minimum after giving effect to exploration and production activities, acquisitions, Dispositions and production, then the Borrower shall, and shall cause its Credit Parties to, grant, within 60 days of delivery of the certificate required under Section 9.14(b) (or such longer period as the Administrative Agent may agree in its reasonable discretion), to the Administrative Agent as security for the Obligations a first-priority Lien (subject only to Permitted Liens) on additional Oil and Gas Properties not already subject to a Lien of the Security Documents such that, after giving effect thereto, the PV-9 of the Mortgaged Properties (calculated at the time of redetermination) meets the Collateral Coverage Minimum. All such Liens will be created and perfected by and in accordance with the provisions of the Security Documents, including, if applicable, any additional deeds of trust, mortgages and security agreements.

Section 9.12    Use of Proceeds.

(a)        The Borrower and its Restricted Subsidiaries will use the proceeds of Loans for the acquisition and development of Oil and Gas Properties, the acquisition of Equity Interests in Restricted Subsidiaries to the extent permitted by Section 10.15, the making of Restricted Payments permitted by Section 10.8 and for working capital and other general partnership purposes of the Borrower and its Restricted Subsidiaries (including Permitted Acquisitions).

(b)        The Borrower and its Restricted Subsidiaries will use Letters of Credit for general partnership purposes and to support deposits required under purchase agreements

​ 104

​ pursuant to which the Borrower or its Restricted Subsidiaries may acquire Oil and Gas Properties and other assets.

Section 9.13    Further Assurances.

(a)        Subject to the applicable limitations set forth in the Security Documents, the Borrower will, and will cause each other Credit Party to, execute any and all further documents, financing statements, agreements and instruments, and take all such further actions (including the filing and recording of financing statements, fixture, filings, assignments of as-extracted collateral, mortgages, deeds of trust and other documents) that the Administrative Agent or the Majority Lenders may reasonably request, in order to grant, preserve, protect and perfect the validity and priority of the security interests created or intended to be created by the applicable Security Documents as first-priority Liens (subject only to Permitted Liens), all at the expense of the Borrower.

(b)        Notwithstanding anything herein to the contrary, if the Administrative Agent and the Borrower reasonably determine in writing that the cost of creating or perfecting any Lien on any property is excessive in relation to the benefits afforded to the Lenders thereby, then such property may be excluded from the Collateral for all purposes of the Credit Documents. In addition, notwithstanding anything to the contrary in this Agreement, the Security Documents, or any other Credit Document, (i) the Administrative Agent may grant extensions of time for or waivers of the requirements of the creation or perfection of security interests in or the obtaining of title opinions or other title information, legal opinions, appraisals, flood insurance and surveys with respect to particular assets (including extensions beyond the Amendment No. 2 Effective Date for the perfection of security interests in the assets of the Credit Parties on such date) where it reasonably determines, in consultation with the Borrower, that perfection or obtaining of such items is not required by law or cannot be accomplished without undue effort or expense by the time or times at which it would otherwise be required by this Agreement or the other Credit Documents, (ii) Liens required to be granted from time to time pursuant to this Agreement and the Security Documents shall be subject to exceptions and limitations set forth in the Security Documents and, to the extent appropriate in any applicable jurisdiction, as otherwise agreed between the Administrative Agent and the Borrower and (iii) the Administrative Agent and the Borrower may make such modifications to the Security Documents, and execute and/or consent to such easements, covenants, rights of way or similar instruments (and Administrative Agent may agree to subordinate the lien of any mortgage to any such easement, covenant, right of way or similar instrument or record or may agree to recognize any tenant pursuant to an agreement in a form and substance reasonably acceptable to the Administrative Agent), as are reasonable or necessary and otherwise permitted by this Agreement and the other Credit Documents.

Section 9.14    Reserve Reports.

(a)        The Borrower shall deliver to the Administrative Agent the Reserve Reports required by Sections 2.14, 2.15 and 2.16 hereof at the times specified therein.

​ 105

​ (b)        With the delivery of each Reserve Report, the Borrower shall provide to the Administrative Agent a Reserve Report Certificate from an Authorized Officer of the Borrower certifying that in all material respects:

(i)         in the case of Reserve Reports prepared by or under the supervision of the chief engineer of the Borrower (or an engineer having similar qualifications and responsibilities employed by the Borrower), such Reserve Report has been prepared, except as otherwise specified therein, in accordance with the procedures used in the immediately preceding Reserve Report;

(ii)       the information contained in the Reserve Report and any other information delivered in connection therewith is true and correct in all material respects;

(iii)      except as set forth in an exhibit to such certificate, the representations and warranties in Section 8.15(a) are true and correct as of the date of such Reserve Report Certificate;

(iv)       none of the Borrowing Base Properties have been Disposed of since the date of the last Borrowing Base determination except those Borrowing Base Properties listed on such certificate as having been Disposed of; and

(v)        the certificate shall also attach, as schedules thereto, a list of all Borrowing Base Properties evaluated by such Reserve Report that are Collateral and demonstrating that the PV-9 of the Collateral (calculated at the time of delivery of such Reserve Report) meets the Collateral Coverage Minimum.

Section 9.15    Title Information.  Within 60 days of the date of delivery to the Administrative Agent of each Reserve Report required by Sections 2.14 and 2.15. the Borrower will deliver title information in form and substance reasonably acceptable to the Administrative Agent under the circumstances in light of the Borrower’s business and operations so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, title information on at least 60% of the PV-9 of the PDP Reserves evaluated in such Reserve Report which title information is reasonably satisfactory to the Administrative Agent in light of the business and operations of the Borrower.

Section 9.16    Consolidated Cash Balance Information.  If any Loans are outstanding, then (a) upon the request of the Administrative Agent (within two (2) Business Days of such request) or (b) on the last Business Day of any week (or, if a Default, Event of Default or Borrowing Base Deficiency has occurred and is continuing, on any Business Day) on which the Borrower has any Excess Cash on such Business Day, the Borrower shall provide to the Administrative Agent, within two (2) Business Days of any such day, summary and balance statements, in a form provided to the Borrower by the applicable financial institution or in a form otherwise reasonably acceptable to the Administrative Agent, for each Deposit Account, Securities Account or other account in which any Cash Balance is held or to which any Cash Balance is credited, together with a written statement setting forth a reasonably detailed calculation of

​ 106

​ amounts excluded from the definition of Excess Cash pursuant to the parenthetical set forth in the definition thereof.

Section 9.17    Control Agreements.  For each Deposit Account or Securities Account that the Borrower or any Credit Party maintains as of the Amendment No. 2 Effective Date (other than Excluded Accounts) the Borrower and other Credit Party will, by no later than 30 days after the Amendment No. 2 Effective Date (or such longer period agreed to by the Administrative Agent), either (a) cause such account to be subject to a deposit account control agreement or securities account control agreement, as applicable, in form and substance satisfactory to the Administrative Agent naming the Administrative Agent as the secured party thereunder for the benefit of the Lenders, or (b) close such account and transfer any funds therein to an account that otherwise meets the requirements of this Section 9.17.  From and after the Amendment No. 2 Effective Date, neither the Borrower nor any other Credit Party shall deposit any funds or securities or other assets into any Deposit Account or Securities Account (other than Excluded Accounts) unless such Deposit Account or Securities Account is subject to a deposit account control agreement or securities account control agreement, as applicable, in form and substance satisfactory to the Administrative Agent and naming the Administrative Agent as the secured party thereunder for the benefit of the Lenders; provided that, the Borrower shall have thirty (30) days (or such longer period as Administrative Agent may determine in its sole discretion) following the Amendment No. 2 Effective Date to execute any such account control agreement establishing a perfected Lien on such accounts.  Each deposit control agreement will provide that the depositary bank will comply with instructions originated by the Administrative Agent directing dispositions of funds in the Deposit Account without further consent by the applicable Credit Party.  Each securities account control agreement will provide that the securities intermediary will comply with entitlement orders originated by the Administrative Agent without further consent by the applicable Credit Party.  The Administrative Agent agrees that it will not issue any such instructions or entitlement orders or otherwise exercise any control right granted under any such deposit account control agreement or securities account control agreement unless (a) an Event of Default has occurred or (b) the Notes and the Loans then outstanding have become due and payable in whole (and not merely in part), whether at the due date thereof, by acceleration or otherwise.

Section 9.18    Unrestricted Subsidiaries **.**The Borrower will:

(a)        cause the management, business and affairs of its Subsidiaries to be conducted in such a manner (including, without limitation, by keeping separate books of account, furnishing separate financial statements of Unrestricted Subsidiaries to creditors and potential creditors thereof and by not permitting properties of the Borrower and the Restricted Subsidiaries to be commingled) so that each Unrestricted Subsidiary that is a corporation or limited liability company will be treated as an entity separate and distinct from the Borrower and the Restricted Subsidiaries;

(b)        not, and will not permit any of the Restricted Subsidiaries to, incur, assume, guarantee or be or become liable for any Indebtedness of any of the Unrestricted Subsidiaries, other than (i) non-recourse pledges of Equity Interests in Unrestricted Subsidiaries granted to secure Indebtedness of Unrestricted Subsidiaries and (ii) Investments permitted under this Agreement; and

​ 107

​ (c)        not permit any Unrestricted Subsidiary to hold any Equity Interest in, or any Indebtedness of, the Borrower or any Restricted Subsidiary.

Section 9.19  Compliance with Anti-Corruption Laws, Anti-Money Laundering Laws and Sanctions.  Borrower and the Restricted Subsidiaries will comply in all respects with applicable Anti-Corruption Laws, Anti-Money Laundering Laws and Sanctions.

ARTICLE X

NEGATIVE COVENANTS

A deviation from the provisions of this Article X shall not constitute an Event of Default under this Agreement if such deviation is consented to in writing by the Administrative Agent and Majority Lenders prior to the date of deviation. The Borrower hereby covenants and agrees that on the Amendment No. 2 Effective Date and thereafter, until the Total Commitment and each Letter of Credit have terminated (unless such Letters of Credit have been collateralized or other arrangements in respect thereof have been made on terms and conditions reasonably satisfactory to each applicable Issuing Bank following the termination of the Total Commitment) and the Loans and Unpaid Drawings, together with interest, fees and all other Obligations incurred hereunder (other than Hedging Obligations, Cash Management Obligations or contingent indemnification obligations not then due and payable), are paid in full,  Borrower will comply with the covenants contained in this Article X.

Section 10.1    Liens.  The Borrower shall not, and shall not permit any Restricted Subsidiary to, create, incur, assume or permit to exist any Lien, security interest or other encumbrance on any of its Properties, except Permitted Liens.

Section 10.2   Sale of Assets.  The Borrower shall not, and shall not permit any of its Restricted Subsidiaries to, sell lease, assign, transfer or otherwise dispose of (each of the foregoing, a “Disposition”), any of its Property, except that:

(a)        the Borrower and its Restricted Subsidiaries may Dispose of inventory and other goods held for sale, including Hydrocarbons, obsolete, worn out, used or surplus equipment, vehicles and other assets in the ordinary course of business (including equipment that is no longer necessary for the business of the Borrower or its Restricted Subsidiaries or is replaced by equipment of at least comparable value and use);

(b)        the Borrower and its Restricted Subsidiaries may Dispose of any Oil and Gas Properties (and including, but without limitation, Dispositions in respect of production payments, net profits interests, operating agreements, farm-outs, joint exploration and development agreements and other agreements customary in the oil and gas industry for the purpose of developing such Oil and Gas Properties or Equity Interests in Restricted Subsidiaries owning Borrowing Base Properties); provided that such Disposition is for Fair Market Value; provided, further, that in connection with any Disposition of Borrowing Base Properties or Equity Interests in Restricted Subsidiaries owning Borrowing Base Properties, in each case included in the most recently delivered Reserve Report, no later than five Business Days prior to the date of consummation of any such Disposition (or such shorter period as may be consented to by the Administrative Agent in its sole discretion)

​ 108

​ the Borrower shall provide notice to the Administrative Agent of such Disposition and the Borrowing Base Properties so Disposed, the Borrowing Base shall be adjusted, if applicable, in accordance with the provisions of Section 2.17(a); provided, further, that to the extent that the Borrower is notified by the Administrative Agent that a Borrowing Base Deficiency could result from an adjustment to the Borrowing Base resulting from such Disposition, after the consummation of such Disposition(s), the Borrower shall have received net cash proceeds, or shall have cash on hand, sufficient to eliminate any such potential Borrowing Base Deficiency;

(c)        the Borrower and its Restricted Subsidiaries may Dispose of property or assets to the Borrower or to a Restricted Subsidiary;

(d)        the Borrower and its Restricted Subsidiaries may make Dispositions of Hydrocarbon Interests and related assets to which no Proved Reserves are attributable and farm-outs of undeveloped acreage to which no Proved Reserves are attributable and assignments in connection with such farm-outs;

(e)        the Borrower and its Restricted Subsidiaries may effect any transaction permitted by Section 10.1, Section 10.5 (excluding Section 10.5(iv)), Section 10.8 and Section 10.15;

(f)        the Borrower and its Restricted Subsidiaries may Dispose of Liquid Investments or cash in the ordinary course;

(g)        the Borrower and its Restricted Subsidiaries may (i) enter into licenses of intellectual property in the ordinary course of business and (ii) Dispose of or abandon intellectual property that is no longer used or useful in the operation of the business;

(h)        the expiration or lapse of leases, exploration tenement licenses and subleases or sublicenses in the ordinary course of business shall be permitted;

(i)         the Borrower and its Restricted Subsidiaries may make other Dispositions not consisting of Borrowing Base Properties that have a Fair Market Value not to exceed an aggregate amount of $5,000,000 in any fiscal year.

Upon the Borrower’s request, the Administrative Agent will promptly release its Liens and security interests on all property that the Borrower is selling, leasing, transferring or otherwise disposing of in compliance with this Section 10.2.

Section 10.3    Debt to EBITDAX Ratio.  Commencing with the fiscal quarter ending December 31, 2020, the Borrower will not allow the Debt to EBITDAX Ratio to exceed 3.5 to 1.0 as of the end of each fiscal quarter.

Section 10.4    Current Ratio.  The Borrower will not permit the ratio of Current Assets of the Borrower and its consolidated Restricted Subsidiaries to the Current Liabilities of the Borrower and its consolidated Restricted Subsidiaries to be less than 1.0 to 1.0, calculated at the end of each fiscal quarter, commencing with the fiscal quarter ending December 31, 2020.

​ 109

​ Section 10.5    Consolidations and Mergers.  The Borrower will not, and will not permit any of the Restricted Subsidiaries to, consolidate or merge with or into any other Person, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), or dispose of all or substantially all its business, assets or other properties, except that:

(i)         the Borrower may merge or consolidate with another Person if the Borrower is the surviving entity in such merger;

(ii)       any Restricted Subsidiary may consolidate or merge into or with, or be liquidated into, Borrower (if the Borrower is the surviving entity in such consolidation merger) or any other Restricted Subsidiary; provided that if such consolidation or merger involves a Guarantor, a Guarantor shall be the surviving Person;

(iii)      any Restricted Subsidiary may dispose of all or substantially all of its assets (upon voluntary liquidation, dissolution, winding up or otherwise) to the Borrower or any other Restricted Subsidiary;

(iv)       dispositions permitted by Section 10.2 (excluding Section 10.2(e));

(v)        any Restricted Subsidiary may merge with or into the Person such Restricted Subsidiary was formed to acquire in connection with a Permitted Acquisition, provided that (i) a Subsidiary Guarantor shall be the continuing or surviving entity or (ii) the continuing or surviving entity shall become a Subsidiary Guarantor in accordance with Section 9.11 in connection therewith); and

(vi)       any Person may merge into the Borrower or any of its Restricted Subsidiaries in connection with a Permitted Acquisition; provided that (i) in the case of a merger involving the Borrower or a Subsidiary Guarantor, the continuing or surviving Person shall be the Borrower or such Subsidiary Guarantor and (ii) the continuing or surviving Person shall be the Borrower or a Restricted Subsidiary;

provided that, in each case, after giving effect thereto, no Event of Default shall have occurred and be continuing.

Section 10.6    [ Reserved ].

Section 10.7    Indebtedness.  The Borrower will not, and will not permit any of the Restricted Subsidiaries to, incur, create, assume or in any manner become or be liable with respect to any Indebtedness, except that the foregoing restrictions shall not apply to:

(a)        the Obligations arising under this Agreement or the other Credit Documents;

(b)        Indebtedness of (i) the Borrower or any Guarantor owing to the Borrower or any Subsidiary; provided that any such Indebtedness owing by a Credit Party to a Subsidiary that is not a Guarantor shall be subject to subordination terms contained in the Intercompany Note, (ii) any Subsidiary that is not a Guarantor owing to any other

​ 110

​ Subsidiary that is not a Guarantor and (iii) to the extent permitted by Section 10.15, any Subsidiary that is not a Guarantor owing to the Borrower or any Guarantor; provided that all such Indebtedness incurred pursuant to this clause (b) shall be represented by the Intercompany Note and pledged to the Administrative Agent for the benefit of the Secured Parties as Collateral pursuant to the terms of a security agreement in the form reasonably prescribed by the Administrative Agent;

(c)        Indebtedness which, in the aggregate, together with all other Indebtedness permitted by this Section 10.7(c), does not exceed $5,000,000 in principal amount outstanding;

(d)        Indebtedness in respect of Capital Leases or purchase money financings in an aggregate principal amount outstanding at any time not to exceed $5,000,000;

(e)        Indebtedness consisting of the financing of insurance premiums in the ordinary course of business;

(f)        [Reserved]

(g)        Indebtedness in respect of Permitted Additional Debt; provided that (i) immediately after giving effect to the incurrence or issuance thereof, (A) the Borrower shall be in Pro Forma Compliance with the covenants in Section 10.3 and Section 10.4 and (B) the Borrowing Base shall be adjusted as set forth in Section 2.18(c) and (ii) if the Credit Parties would not be in compliance with the Collateral Coverage Minimum immediately after giving effect to the incurrence of such Permitted Additional Debt, then one or more Credit Parties shall have executed and delivered Security Documents, such that the Borrower shall be in compliance with the Collateral Coverage Minimum within 15 days (or such later date as the Administrative Agent may reasonably agree) of the date of incurrence of such Permitted Additional Debt, and thereafter, at all times during the period that any Permitted Additional Debt is outstanding.

Section 10.8   Restricted Payments.  The Borrower will not, and will not permit any Restricted Subsidiary to, declare or pay any dividend or distribution (whether in cash, securities or other property) or purchase, redeem or otherwise acquire for value any of its Equity Interests now or hereafter outstanding, return any capital to the holders of its Equity Interests or make any distribution of its assets to the holders of its Equity Interests (each a “Restricted Payment”), except that:

(a)        each of the Borrower and OpCo may make Restricted Payments (excluding redemptions of Preferred Equity and the OpCo Preferred Units, as applicable) to its respective Equity Holders, if and to the extent that (i) such Restricted Payment is paid within 60 days after the date of declaration thereof, (ii) as of the date of such declaration of such Restricted Payment, no Event of Default or Borrowing Base Deficiency existed, (iii) as of the date of such declaration, if such dividend or distribution had been made as of such date of declaration, immediately after giving effect thereto, no Event of Default or Borrowing Base Deficiency would have existed, (iv) immediately after such Restricted Payment is made, the Borrower shall have Liquidity in an amount that is not less than ten

​ 111

​ percent (10%) of the Loan Limit, (v) immediately after giving effect to such Restricted Payment, the Debt to EBITDAX Ratio of the Borrower, determined on a basis described in the definition of “Pro Forma Compliance”, shall be less than 3.0 to 1.0; (vi) any such Restricted Payment in respect of the Kimbell Common Units is not in excess of an amount equal to the Borrower’s Projected Cash Available For Distribution for the most recently ended fiscal quarter, at the time of such Restricted Payment, as set forth in a certificate of a Financial Officer of the Borrower delivered to the Administrative Agent before or at the time of declaration of such payment or as set forth in the Borrower’s public disclosures made before or at the time of declaration of such payment and (vii) solely with respect to Restricted Payments by OpCo to the holders of OpCo Common Units, such Restricted Payment is made ratably to all holders of OpCo Common Units;

(b)        each of the Borrower and OpCo may make Restricted Payments consisting of redemptions of the Apollo Group Preferred Units and the OpCo Preferred Units, as applicable:

(i)         provided that, immediately after giving effect to such Restricted Payment, (A) no Event of Default or Borrowing Base Deficiency exists, (B) immediately after giving effect to such Restricted Payment, the Borrower shall have Liquidity in an amount that is not less than ten percent (10%) of the Loan Limit and (C) immediately after giving effect to such Restricted Payment, the Debt to EBITDAX Ratio of the Borrower, determined on a basis described in the definition of “Pro Forma Compliance” shall not exceed 3.25 to 1.0, or

(ii)       with an amount equal to the net cash proceeds derived from (A) the issuance of Equity Interests consisting of the Borrower’s common stock or (B) the issuance of Equity Interests consisting of Preferred Equity on terms reasonably satisfactory to the Majority Lenders and in any event on terms and conditions no less favorable to the Borrower than the Apollo Group Preferred Units, and, when taken as a whole, such Restricted Payment is made within sixty (60) days after the issuance of the Equity Interests that is made under sub-clause (A) or sub-clause (B) above.

(c)        the Borrower and Opco may declare and pay dividends or distributions with respect to its Equity Interests (including dividends or distributions with respect to the Apollo Group Preferred Units and the OpCo Preferred Units, as applicable) payable solely in additional Equity Interests (including additional Apollo Group Preferred Units and the OpCo Preferred Units, as applicable, as payment in kind but excluding other Disqualified Capital Stock);

(d)  the Borrower and OpCo may consummate any Kimbell Class B/OpCo Unit for Kimbell Common Unit Exchange;

(e)        the Borrower may make Restricted Payments pursuant to and in accordance with equity option plans or other benefit plans for management, employees, directors and consultants of the Borrower and its Subsidiaries;

​ 112

​ (f)        OpCo may make Restricted Payments to the Borrower with respect to its Equity Interests; and

(g)        Restricted Subsidiaries of the Borrower may declare and pay dividends or distributions ratably with respect to their Equity Interests to its direct parent that is the Borrower or a Subsidiary Guarantor.

Section 10.9    Preferred Equity Units.  The Borrower shall not issue any Preferred Equity except for (a) the Apollo Group Preferred Units (including Apollo Group Preferred Units issued as payment in kind), (b) Preferred Equity issued to redeem the Apollo Group Preferred Units to the extent permitted by Section 10.8(b) and (c) the dividend and the liquidation preferences with respect to the general partner interests in the Borrower and the Kimbell Class B Units as described in the Tax Change Memorandum (as defined in Amendment No.1).  The Borrower shall not permit (i) any Restricted Subsidiary to issue any preferred Equity Interests other than the OpCo Preferred Units or (ii) OpCo to issue or permit to be held by any Person (other than the Borrower) any Equity Interests having voting rights more favorable to the holders thereof than the voting rights applicable to the OpCo Common Units on and as of the date the Tax Change Transactions are consummated.

Section 10.10  Hedge Transactions .

(a)        The Borrower shall not, and shall not permit any of its Restricted Subsidiaries to, enter into any Hedge Transactions other than:

(i)         Hedge Transactions with respect to interest rates that are entered into in the ordinary course of business and not for purposes of speculation that (A) result in any Indebtedness of the Borrower or any of its Restricted Subsidiaries that is subject to a floating interest rate to be effectively subject to a fixed interest rate or that otherwise mitigate or minimize the Borrower’s or such Restricted Subsidiary’s exposure to fluctuations in the applicable floating interest rate, (B) at the time each such Hedge Transaction is entered into, do not cause the aggregate notional amount of all outstanding Hedge Transactions with respect to interest rates to exceed one hundred percent (100%) of the then outstanding principal balance of such floating rate Indebtedness; and (C) do not have a scheduled term that extends beyond the scheduled maturity date of the floating rate Indebtedness related to such Hedge Transaction and (D) do not require the Borrower or any Restricted Subsidiary to post money, assets or any other property as security against the event of its non-performance, other than to the extent, if any, permitted under Section 10.1; and

(ii)       Hedge Transactions with respect to hydrocarbon prices that are entered into in the ordinary course of business for hedging risk and not for purposes of speculation and that do not (determined separately for each new Hedge Transaction as of the date such Hedge Transaction is entered into) (a)  have Hedge Termination Dates longer than thirty six (36) months from the effective date of the Hedge Transaction, and in no event will any such Hedge Termination Date exceed one (1) year beyond the Maturity Date and (b)  cause the aggregate notional

​ 113

​ volumes of Hydrocarbons under all such Hedge Transactions then in effect, calculated separately for each of crude oil, natural gas and natural gas liquids for each month to which such new Hedge Transaction applies, to exceed (i) 80% of Borrower’s and its Restricted Subsidiaries’ anticipated production of Proved Reserves that, in accordance with the Petroleum Industry Standards, are classified as “Proved Developed Producing Reserves” during any of the 36 months following such date, as determined based on the most recent Reserve Report delivered pursuant to Sections 2.14 and 2.15 hereof, or (ii) zero thereafter, provided, however, In calculating such 80% limit, all purchased put options or price floors shall be excluded, so long as such put options or floors do not require payments by the Borrower and its Restricted Subsidiaries other than those due at the time of purchase. The limits in the foregoing sentence shall be calculated separately for Hedge Transactions that hedge basis risk with respect to anticipated production and those that hedge price risk with respect to anticipated production.  To the extent, if any, that Borrower uses crude oil hedges to hedge natural gas liquids, such crude oil hedges shall be treated as hedges of natural gas liquids rather than hedges of crude oil.  Any Hedge Transaction permitted under this Section 10.10(b) shall be with a counterparty that is either (i) the Administrative Agent or any Lender or an Affiliate of the Administrative Agent or any Lender or (ii) a third party approved in writing by the Administrative Agent with a credit rating of BBB+ or better by S&P, and any successor thereto, or a rating of Baa1 or better by Moody’s and any successor thereto.

(b)        The Borrower shall not effect any Hedge Termination unless (i) the Borrower shall give the Administrative Agent 5 days’ prior written notice of any such Hedge Termination (other than a “Termination Event” or “Event of Default” under a Hedge Transaction as to which the Borrower cannot give advance notice, in which case the Borrower shall give prompt written notice of such Hedge Termination), and (ii) if such Hedge Termination causes a Borrowing Base Deficiency, the Borrower shall make any mandatory prepayments required by Section 2.17.

(c)        The Borrower shall not, and shall not permit any Restricted Subsidiary to, enter into any Hedge Transaction which contains any requirement, agreement or covenant for the Borrower or any Restricted Subsidiary to post collateral or margin to secure their obligations under such Hedge Transaction or to cover market exposures; provided, however, that the foregoing shall not prohibit or be deemed to prohibit the Obligations from being secured by the Security Documents.

Section 10.11  Passive Status of Borrower/OpCo.  Notwithstanding anything to the contrary contained herein or in any other Credit Document:

(a)        OpCo shall not engage in any operating or business activities or other transactions other than its direct or indirect ownership of Equity Interest in its Restricted Subsidiaries and shall not directly hold Equity Interests of any Person other than such Restricted Subsidiaries; provided that the following shall be permitted activities of OpCo: (i) the maintenance of its legal existence (including the ability to incur fees, costs and expenses relating to such maintenance), (ii) the performance of its obligations with respect

​ 114

​ to the Credit Documents, (iii) payment of Taxes, (iv) conduct of financial audits as provided hereunder, (v) providing indemnification to officers, managers and directors, (vi) making Restricted Payments to holders of its Equity Interests to the extent permitted by Section 10.8, (vii) activities related to Hedge Transactions with Hedge Banks permitted hereunder and Cash Management Agreements, and (viii) transactions pursuant to the Management Services Agreement.

(b)        The Borrower shall not engage in any operating or business activities or other transactions other than its ownership of Equity Interest in OpCo and shall not directly hold Equity Interests of any Person other than OpCo; provided that the following shall be permitted activities of the Borrower: (i) the maintenance of its legal existence (including the ability to incur fees, costs and expenses relating to such maintenance), (ii) the performance of its obligations with respect to the Credit Documents, (iii) payment of Taxes, (iv) conduct of financial audits as provided hereunder, (v) providing indemnification to officers, managers and directors, (vi) conduct business related to the listing of its Equity Interests on a national exchange, (vii) making Restricted Payments to holders of its Equity Interests to the extent permitted by Section 10.8, (viii) activities related to Hedge Transactions permitted hereunder and Cash Management Services and (ix) transactions pursuant to the Management Services Agreement.

Section 10.12  Amendment of Organizational Documents.

(a)        The Borrower will not amend or modify its organizational documents in a manner that would have a Material Adverse Effect without obtaining the prior written consent of the Administrative Agent; provided that for purposes of clarity, it is understood and agreed that the foregoing shall not prohibit changes to the organizational form of the Borrower to the extent not otherwise prohibited hereunder.

(b)        The Borrower will not, and will not permit any of its Restricted Subsidiaries, at any time on or after the Amendment No. 1 Effective Date, to amend modify or supplement (or enter into any agreement that has the effect of amending, modifying or supplementing, other than, for the avoidance of doubt, in connection with entry into the Preferred Equity Transaction, as such term is defined in Amendment No. 1) the terms of any Preferred Equity or the terms of any preferred Equity Interests of any Restricted Subsidiary to the extent that the same could reasonably be expected to be materially adverse to the Lenders (it being understood that (i) any increase in the distribution rate (whether in cash or paid in kind), (ii) any change to any mandatory redemption provision or put rights (or the addition of other mandatory redemption provisions or put rights), (iii) any change to the terms of thereof which results in any such Preferred Equity or preferred Equity Interests constituting indebtedness under GAAP and (iv) any modification of any covenant included in any such Preferred Equity or preferred Equity Interests that makes such covenant materially more restrictive as to the Borrower or any of its Restricted Subsidiaries (or any modification that adds a covenant that results in any such Preferred Equity or preferred Equity Interests being materially more restrictive as to the Borrower or any of its Restricted Subsidiaries), in each case, shall be deemed to be materially adverse to the Lenders).

​ 115

​ (c)        The Borrower will not permit OpCo to amend, modify or supplement (or enter into any agreement that has the effect of amending, modifying or supplementing) its organizational documents (including its certificate or articles of incorporation and the bylaws) in a manner that could reasonably be expected to be materially adverse to the Lenders (it being understood that (i) changes to the organizational form of OpCo from a limited liability company or changes to the management of OpCo by the Borrower  and (ii) changes to permit distributions in respect of the OpCo Common Units to be paid to the Borrower on a less than ratable basis, in each case, shall be deemed to be materially adverse to the Lenders.

Section 10.13  Sanctions.  The Borrower will not directly or indirectly, use the proceeds of any Credit Event, or lend, contribute or otherwise make available such proceeds to any Subsidiary, joint venture partner or other individual or entity, to fund any activities of or business with any individual or entity, or in any Designated Jurisdiction that, at the time of such funding, is the subject of Sanctions, or in any other manner that will result in a violation by any Lender, Administrative Agent, or Issuing Bank, of Sanctions or any Anti-Corruption Laws or Anti-Money Laundering Laws.

Section 10.14  New Accounts.  Subject to Section 9.17, the Borrower will not, and will not permit any other Credit Party to deposit, credit or otherwise transfer any Cash Receipts, securities, financial assets or any other property into, any Deposit Account or Securities Account other than (x) Deposit Accounts and Securities Accounts maintained with the Administrative Agent, (y) Excluded Accounts and (z) such Deposit Account or Securities Account in respect of which the Administrative Agent, for the benefit of the Secured Parties, shall have a perfected Lien prior to the transfer or other deposit of any Cash Receipts, securities, financial assets or any other property of any Credit Party therein.

Section 10.15  Limitation on Investments.  The Borrower shall not, nor shall it permit any of its Restricted Subsidiaries to, make or permit to exist any loans, advances, or capital contributions to any other Person, or purchase any Equity Interests or evidences of indebtedness of any Person (such loans, advances, capital contributions to, purchases of Equity Interests (including the making of any acquisition of Equity Interests), or purchase of any evidences of indebtedness of any Person, collectively, “Investments”), except:

(a)        Investments constituting Liquid Investments at the time initially made;

(b)        the creation or acquisition of any Restricted Subsidiaries (or of any Person who by virtue of such Investment becomes a Restricted Subsidiary) in compliance with Section 9.11;

(c)        Investments in the direct ownership of Oil and Gas Properties and Investments made in the ordinary course of business as a means of actively exploiting, exploring for, acquiring, developing, processing, gathering, marketing or transporting Hydrocarbons through agreements, transactions, interests or arrangements which provide for the sharing of risks or costs, jointly with third parties, including entering into operating agreements, working interests, royalty interests, mineral leases, processing agreements, farmouts, farm-in agreements, division orders, contracts for the sale, transportation or

​ 116

​ exchange of oil and natural gas, unitization and pooling declarations and agreements and area of mutual interest agreements, production sharing agreements or other similar or customary agreement, transactions, properties, interest and investments and expenditures in connection therewith; provided that (i) no such Investment includes an Investment in any Equity Interest in a Person, (ii) any Indebtedness incurred or Lien granted or permitted to exist pursuant to such Investments is otherwise permitted under Section 10.1 and Section 10.7, respectively, and (iii) such Investments are taken into account in computing the net revenue interests and working interests of the Borrower or any of its Restricted Subsidiaries set forth in the most recent Reserve Report;

(d)        Accounts receivable arising in the ordinary course of business;

(e)        Permitted Acquisitions;

(f)        Investments by the Borrower in any Guarantor or by any Guarantor in the Borrower or in any other Guarantor;

(g)        Investments consisting of Hedge Transactions permitted under Section 10.10;

(h)        Investments (including, without limitation, capital contributions) in general or limited partnerships or other types of entities (each a “venture”) entered into by the Borrower or one of its Restricted Subsidiaries with others in the ordinary course of business; provided that (i) no Default or Event of Default exists at the time of, or would exist after making any such Investment, (ii) any such venture is engaged exclusively in oil and gas exploration, development, production, processing and related activities, including transportation, (iii) the interest in such venture is acquired in the ordinary course of business and on fair and reasonable terms and (iv) such venture interests acquired and capital contributions made (valued as of the date such interest was acquired or the contribution made) do not exceed, in the aggregate at any time outstanding an amount equal to $10,000,000;

(i)         Investments in stock, obligations or securities received in settlement of debts arising from Investments permitted under this Section 10.15 owing to the Borrower or any of its Subsidiaries as a result of a bankruptcy or other insolvency proceeding of the obligor;

(j)         Investments in Persons primarily engaged in the oil and gas business made with cash otherwise permitted to be used for Restricted Payments in accordance with Section 10.8; provided that no Investment may be made pursuant to this clause (j) unless immediately after giving effect thereto (i) no Default or Borrowing Base Deficiency would exist, (ii) the Borrower shall have Liquidity in an amount that is not less than ten percent (10%) of the Loan Limit and (iii) after giving effect to such Investment, the Debt to EBITDAX ratio of the Borrower, determined on a basis described in the definition of “Pro Forma Compliance” shall be less than 3.0 to 1.0;

(k)        loans and advances to officers, directors, employees and consultants of the Borrower or any of its Restricted Subsidiaries as permitted by applicable law provided that

​ 117

​ the aggregate principal amount thereof outstanding at any time shall not exceed $1,000,000;

(l)         (i) Investments existing on, or made pursuant to legally binding written commitments in existence on, the Amendment No. 2 Effective Date as set forth on Schedule 10.15, (ii) Investments existing on the Effective Date of the Borrower or any Restricted Subsidiary in any other Subsidiary and (iii) any extensions, renewals or reinvestments thereof, so long as the amount of any Investment made pursuant to this clause (l) is not increased at any time above the amount of such Investment set forth on Schedule 10.15;

(m)       Investments held by a Person acquired (including by way of merger or consolidation) on or after the Amendment No. 2 Effective Date otherwise in accordance with this Section 10.15 to the extent that such Investments were not made in contemplation of or in connection with such acquisition, merger or consolidation and were in existence on the date of such acquisition, merger or consolidation;

(n)        Investments consisting of Dispositions, consolidations and mergers, Indebtedness and Restricted Payments permitted under Sections 10.2 (other than Section 10.2(e)), 10.5, 10.7 and 10.8; and

(o)        Investments made to repurchase or retire Equity Interests of the Borrower owned by any employee or any stock ownership plan or key employee stock ownership plan of the Borrower (or any direct or indirect parent thereof);

(p)        Investments constituting non-cash proceeds of Dispositions of assets to the extent such Disposition is permitted by Section 10.2;

(q)        Investments to the extent that payment for such Investments is made with Equity Interests (other than Disqualified Capital Stock) of the Borrower;

(r)        Investments in Unrestricted Subsidiaries not to exceed $10,000,000 (measured as of the time made) in the aggregate at any time; and

(s)        Investments made by the Borrower and its Restricted Subsidiaries in any fiscal year and not otherwise permitted under this Section 10.15 in an aggregate amount not to exceed $10,000,000 (measured as of the time made) in such fiscal year.

Section 10.16  Change in Business.  The Borrower will not fundamentally and substantively alter the character of its business, taken as a whole, from the business conducted by it on the Effective Date, and other business activities incidental, reasonably related, complementary or ancillary to any of the foregoing.

Section 10.17  Designation of Restricted and Unrestricted Subsidiaries.

(a)        Unless designated as an Unrestricted Subsidiary on Schedule 8.12 as of the date hereof or thereafter, in compliance with Section 10.17(b) or (d), any Person that

​ 118

​ becomes a Subsidiary of the Borrower or any of its Restricted Subsidiaries shall be classified as a Restricted Subsidiary.

(b)        The Borrower may designate by written notification thereof to the Administrative Agent, any Restricted Subsidiary (other than OpCo), including a newly or to be formed or newly or to be acquired Subsidiary, as an Unrestricted Subsidiary if (i) prior, and immediately after giving effect, to such designation, neither a Default nor a Borrowing Base Deficiency would exist, (ii) such designation is deemed to be an Investment in an Unrestricted Subsidiary in an amount equal to the Fair Market Value as of the date of such designation of the Borrower’s and its Restricted Subsidiaries’ direct ownership interests in such Subsidiary and such Investment would be permitted to be made at the time of such designation under Section 10.15 and (iii) the Borrower shall be in Pro Forma Compliance after giving effect to such designation. Except as provided in this Section 10.17(b), no Restricted Subsidiary may be designated as an Unrestricted Subsidiary.

(c)        The Borrower may designate any Unrestricted Subsidiary to be a Restricted Subsidiary if immediately after giving effect to such designation, (i) the representations and warranties of the Borrower and its Restricted Subsidiaries contained in each of the Credit Documents are true and correct in all material respects on and as of such date as if made on and as of the date of such redesignation (or, if stated to have been made expressly as of an earlier date, were true and correct in all material respects as of such date), (ii) no Default exists, (iii) the Borrower complies with the requirements of Section 9.11 and Section 9.18, (iv) the Borrower and/or one or more Restricted Subsidiaries owns all of the Equity Interests in such Subsidiary and (v) the Borrower shall be in Pro Forma Compliance after giving effect to such designation. Any such designation shall be treated as a cash dividend to the Borrower in an amount equal to the lesser of the fair market value of the Borrower’s and its Restricted Subsidiaries’ direct ownership interests in such Subsidiary or the amount of the Borrower’s and its Restricted Subsidiaries’ aggregate investment previously made for purposes of the limitation on Investments under Section 10.15. Upon the designation of an Unrestricted Subsidiary as a Restricted Subsidiary, all Investments previously made in such Unrestricted Subsidiary shall no longer be counted in determining any limitation on Investments under Section 10.15.

(d)        Each Subsidiary of an Unrestricted Subsidiary shall automatically be designated as an Unrestricted Subsidiary.

(e)        Upon designation of a Restricted Subsidiary as an Unrestricted Subsidiary in compliance with Section 10.17(b), (i) such Subsidiary shall be automatically released from all obligations, if any, under the Credit Documents, including the Guarantee and all other applicable Security Documents and (ii) all Liens granted pursuant to the Guarantee and all other applicable Security Documents on the property of, and the Equity Interests in, such Unrestricted Subsidiary shall be automatically released.

​ 119

​ ARTICLE XI

EVENTS OF DEFAULT

Upon the occurrence of any of the following specified events (each an “Event of Default”):

Section 11.1    Payments.  The Borrower shall (a) default in the payment when due of any principal of the Loans or (b) default, and such default shall continue for three (3) Business Days, in the payment when due of any interest on the Loans or any Unpaid Drawings, fees or of any other amounts owing hereunder or under any other Credit Document (other than any amount referred to in clause (a) above).

Section 11.2    Representations, Etc.  Any representation, warranty or statement made or deemed made by any Credit Party herein or in any other Credit Document or any certificate delivered or required to be delivered pursuant hereto or thereto shall prove to be untrue in any material respect on the date as of which made or deemed made.

Section 11.3    Covenants.  Any Credit Party shall:

(a)        default in the due performance or observance by it of any term, covenant or agreement contained in Section 9.1(d)(i) and 9.5 (solely with respect to the Borrower), Section 9.17 or Article X; or

(b)        default in the due performance or observance by it of any term, covenant or agreement (other than those referred to in Section 11.1 or 11.2 or clause (a) of this Section 11.3) contained in this Agreement or any Security Document and such default shall continue unremedied for a period of at least thirty (30) days after receipt of written notice thereof by the Borrower from the Administrative Agent.

Section 11.4    Default Under Other Agreements.  (i) The Borrower or any of its Restricted Subsidiaries shall default in any payment with respect to any Material Indebtedness (other than the Indebtedness described in Section 11.1) beyond the period of grace, if any, provided in the instrument of agreement under which such Indebtedness was created, (ii) the Borrower or any of its Restricted Subsidiaries shall default in the observance or performance of any agreement or condition relating (other than a payment default) to any such Material Indebtedness or contained in any instrument or agreement evidencing, securing or relating thereto, or any other event (other than a payment default) shall occur or condition exist (other than (x) secured Indebtedness that becomes due as a result of a Disposition (including as a result of a casualty event) of the property or assets securing such Indebtedness permitted under this Agreement or (y) as a result of delivery of a notice of voluntary prepayment or redemption permitted under this Agreement), the effect of which default or other event or condition is to cause, or to permit the holder or holders of such Material Indebtedness (or a trustee or agent on behalf of such holder or holders) to cause, any such Indebtedness to become due or to be repurchased, prepaid, defeased or redeemed (automatically or otherwise), or an offer to repurchase, prepay, defease or redeem such Indebtedness to be made, prior to its stated maturity or (iii) a default or other event or condition (other than termination events or equivalent events (other than alternative termination events, solely to the extent such alternative termination event is caused by a Credit Party) pursuant to the terms of such Hedge Transactions) shall occur and be continuing under any Hedging Transaction between any Credit

​ 120

​ Party and any Person which results in a net payment being due by such Credit Party in excess of $10,000,000 and such payment is not paid when due (after giving effect to any applicable grace periods), unless in the case of each of (i)-(iii) of the foregoing, such holder or holders shall have (or through its or their trustee or agent on its or their behalf) waived such default in a writing to the Borrower.

Section 11.5    Bankruptcy, Etc.  The Borrower or any Guarantor shall commence a voluntary case, proceeding or action concerning itself under Title 11 of the United States Code (the “Bankruptcy Code”) or any other applicable Debtor Relief Law; or an involuntary case, proceeding or action is commenced against the Borrower or any Guarantor and the petition is not dismissed or stayed within 60 days after commencement of the case, proceeding or action, or the Borrower or the applicable Guarantor consents to the institution of such case, proceeding or action prior to such 60-day period, or any order of relief or other order approving any such case, proceeding or action is entered; or a custodian (as defined in the Bankruptcy Code), receiver, receiver manager, trustee, conservator, liquidator, examiner, rehabilitator, administrator or similar Person is appointed for, or takes charge of, the Borrower or all or any substantial portion of the property or business thereof; or the Borrower suffers any appointment of any custodian, receiver, receiver manager, trustee, conservator, liquidator, examiner, rehabilitator, administrator or the like for it or any substantial part of its property or business to continue undischarged or unstayed for a period of 60 days; or the Borrower makes a general assignment for the benefit of creditors.

Section 11.6    ERISA .

(a)        (i) Any Plan shall fail to satisfy the minimum funding standard required for any plan year or part thereof or a waiver of such standard or extension of any amortization period is sought or granted under Section 412 of the Code; (ii) any Plan is or shall have been terminated or is the subject of termination proceedings under ERISA (including the giving of written notice thereof); (iii) an event shall have occurred or a condition shall exist in either case entitling the PBGC to terminate any Plan or to appoint a trustee to administer any Plan (including the giving of written notice thereof); (iv) any Plan shall have an accumulated funding deficiency (whether or not waived); and (v) the Borrower or any ERISA Affiliate has incurred or is likely to incur a liability to or on account of a Plan under Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code (including the giving of written notice thereof); and

(b)        there would result from any event or events set forth in clause (i) of this Section 11.6 the imposition of a lien, the granting of a security interest, or a liability, or the reasonable likelihood of incurring a lien, security interest or liability; and

(c)        such lien, security interest or liability will or would be reasonably likely to have a Material Adverse Effect.

Section 11.7    Guarantee.  The Guarantee or any material provision thereof shall cease to be in full force or effect (other than pursuant to the terms hereof and thereof) or any Guarantor or any other Credit Party shall assert in writing that any such Guarantor’s obligations under the Guarantee are not to be in effect or are not to be legal, valid and binding obligations (other than pursuant to the terms hereof or thereof).

​ 121

​ Section 11.8    Security Documents.  Any of the mortgages, deeds of trust, security agreements or assignments of production or any other Security Document pursuant to which assets of the Borrower and the Credit Parties are pledged as Collateral or any material provision thereof shall cease to be in full force or effect (other than pursuant to the terms hereof or thereof) or any grantor thereunder or any other Credit Party shall assert in writing that any grantor’s obligations under the mortgages, deeds of trust, security agreements or assignments of production or any other Security Document are not in effect or not legal, valid and binding obligations (other than pursuant to the terms hereof or thereof).

Section 11.9    Judgments.  One or more monetary judgments or decrees shall be entered against the Borrower or a Guarantor involving a liability of an amount exceeding $15,000,000 in the aggregate for all such judgments and decrees for the Borrower and the Guarantors (to the extent not paid or covered by insurance provided by a carrier not disputing coverage), which judgments are not discharged or effectively waived or stayed for a period of 60 consecutive days.

Section 11.10  Change of Control.  A Change of Control shall have occurred.

Then, and in any such event, and at any time thereafter, if any Event of Default shall then be continuing, the Administrative Agent may and, upon the written request of the Majority Lenders, shall, by written notice to the Borrower, take any or all of the following actions, without prejudice to the rights of the Administrative Agent or any Lender to enforce its claims against the Borrower or any other Credit Party, except as otherwise specifically provided for in this Agreement (provided that, if an Event of Default specified in Section 11.5 shall occur, the result that would occur upon the giving of written notice by the Administrative Agent as specified in clauses (a), (b) and (c) below shall occur automatically without the giving of any such notice): (a) declare the Total Commitment terminated, whereupon the Commitment of each Lender shall forthwith terminate immediately and any fees theretofore accrued shall forthwith become due and payable without any other notice of any kind; (b) declare the principal of and any accrued interest and fees in respect of any or all Loans and any or all Obligations owing hereunder to be, whereupon the same shall become, forthwith due and payable without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower; and/or (c) demand cash collateral in respect of any outstanding Letter of Credit pursuant to Section 3.8(b) in an amount equal to the aggregate Stated Amount of all Letters of Credit issued and then outstanding. In addition, after the occurrence and during the continuance of an Event of Default, the Administrative Agent and the Lenders will have all other rights and remedies available at law and equity.

Section 11.11  Application of Proceeds.  Any amount received by the Administrative Agent from any Credit Party (or from proceeds of any Collateral) following any acceleration of the Obligations under this Agreement or any Event of Default with respect to the Borrower under Section 11.5 shall be applied:

First, to payment of that portion of the Obligations constituting fees, indemnities, expenses and other amounts (including fees, disbursements and other charges of counsel payable under Section 13.5 and amounts payable under Article II) payable to the Administrative Agent in such Person’s capacity as such;

​ 122

​ Second, to payment of that portion of the Obligations constituting fees, indemnities and other amounts (other than principal, interest and Letter of Credit Fees) payable to the Lenders and the Issuing Banks (including fees, disbursements and other charges of counsel payable under Section 13.5) arising under the Credit Documents and amounts payable under Article II, ratably among them in proportion to the respective amounts described in this clause Second payable to them;

Third, to payment of that portion of the Obligations constituting accrued and unpaid Letter of Credit Fees, interest on the Loans and interest on Unpaid Drawings, ratably among the Lenders and the Issuing Banks in proportion to the respective amounts described in this clause Third payable to them;

Fourth, (i) to payment of that portion of the Obligations constituting unpaid principal of the Loans, the Unpaid Drawings and Obligations then owing under Hedge Transactions and Cash Management Agreements and (ii) to Cash Collateralize that portion of Letters of Credit outstanding comprising the aggregate undrawn amount of Letters of Credit to the extent not otherwise Cash Collateralized by the Borrower pursuant to Section 3.8, ratably among the Lenders, the Issuing Banks, the Hedge Banks and the Cash Management Banks in proportion to the respective amounts described in this clause Fourth held by them; provided that (x) any such amounts applied pursuant to the foregoing clause (ii) shall be paid to the Administrative Agent for the ratable account of the applicable Issuing Bank to Cash Collateralize such Letters of Credit Outstanding, (y) subject to Section 3.8, amounts used to Cash Collateralize the aggregate undrawn amount of Letters of Credit pursuant to this clause Fourth shall be applied to satisfy drawings under such Letters of Credit as they occur and (z) upon the expiration of any Letter of Credit, the pro rata share of Cash Collateral attributable to such expired Letter of Credit shall be distributed in accordance with this clause Fourth;

Fifth, to the payment of all other Obligations of the Credit Parties owing under or in respect of the Credit Documents that are due and payable to the Administrative Agent and the other Secured Parties on such date, ratably based upon the respective aggregate amounts of all such Obligations owing to the Administrative Agent and the other Secured Parties on such date; and

Last, the balance, if any, after all of the Obligations have been paid in full, to the Borrower or as otherwise required by Requirements of Law.

Subject to Section 3.8, amounts used to Cash Collateralize the aggregate undrawn amount of Letters of Credit pursuant to clause Fourth above shall be applied to satisfy drawings under such Letters of Credit as they occur. If any amount remains on deposit as Cash Collateral after all Letters of Credit have either been fully drawn or expired, such remaining amount shall be applied to the other Obligations, if any, in the order set forth above.

Notwithstanding the foregoing, amounts received from the Borrower or any Credit Party that is not an “eligible contract participant” under the Commodity Exchange Act shall not be applied to any Excluded Swap Obligations (it being understood, that in the event that any amount is applied to Obligations other than Excluded Swap Obligations as a result of this clause, the

​ 123

​ Administrative Agent shall make such adjustments as it determines are appropriate to distributions pursuant to clause second above from amounts received from “eligible contract participants” under the Commodity Exchange Act to ensure, as nearly as possible, that the proportional aggregate recoveries with respect to Obligations described in clause second above by the holders of any Excluded Swap Obligations are the same as the proportional aggregate recoveries with respect to other Obligations pursuant to clause second above).

ARTICLE XII

THE ADMINISTRATIVE AGENT

Section 12.1    Appointment.

(a)        Each Lender hereby irrevocably designates and appoints the Administrative Agent as the agent of such Lender under this Agreement and the other Credit Documents and irrevocably authorizes the Administrative Agent, in such capacity, to take such action on its behalf under the provisions of this Agreement and the other Credit Documents and to exercise such powers and perform such duties as are expressly delegated to the Administrative Agent by the terms of this Agreement and the other Credit Documents, together with such other powers as are reasonably incidental thereto. The provisions of this Article XII (other than Section 12.1(b) with respect to the Lead Arranger, the Syndication Agent, the Joint Lead Arrangers, and the Co-Documentation Agents and Section 12.9 with respect to the Borrower) are solely for the benefit of the Administrative Agent and the Lenders, and the Borrower shall not have rights as third party beneficiary of any such provision. Notwithstanding any provision to the contrary elsewhere in this Agreement, the Administrative Agent shall not have any duties or responsibilities, except those expressly set forth herein, or any fiduciary relationship with any Lender, and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement or any other Credit Document or otherwise exist against the Administrative Agent.

(b)        Neither the Lead Arranger, the Syndication Agent, the Joint Lead Arrangers nor the Co-Documentation Agents, in their capacities as such, shall have any obligations, duties or responsibilities under this Agreement but shall be entitled to all benefits of this Article XII.

(c)        Except for notices, reports and other documents and information expressly required to be furnished to the Lenders and the Issuing Banks by the Administrative Agent hereunder, the Administrative Agent shall have no duty or responsibility to provide any Lender or Issuing Bank with any credit or other information concerning the affairs, financial condition or business of the Borrower or any other Credit Party (or any of their Affiliates) that may come into the possession of the Administrative Agent or any of its Affiliates.  Each Lender and Issuing Bank acknowledges that Willkie Farr & Gallagher LLP is acting as counsel to the Administrative Agent only.  Each other party hereto will consult with its own legal counsel to the extent that it deems necessary in connection with the Credit Documents and the matters contemplated therein.

(d)        The Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers

​ 124

​ expressly contemplated hereby or by the other Credit Documents that the Administrative Agent is required to exercise in writing as directed by the Majority Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Article XII) and in all cases the Administrative Agent shall be fully justified in failing or refusing to act hereunder or under any other Credit Documents unless it shall (a) receive written instructions from the Majority Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Article XII) specifying the action to be taken and (b) be indemnified to its satisfaction by the Lenders against any and all liability and expenses that may be incurred by it by reason of taking or continuing to take any such action.  The instructions as aforesaid and any action taken or failure to act pursuant thereto by the Administrative Agent shall be binding on all of the Lenders and Issuing Banks.  If a Default or Event of Default has occurred and is continuing, then the Administrative Agent shall take such action with respect to such Default or Event of Default as shall be directed by the requisite Lenders in the written instructions (with indemnities) described in this Section 12.1, provided that, unless and until the Administrative Agent shall have received such directions and indemnities, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders and Issuing Banks.  In no event, however, shall the Administrative Agent be required to take any action that the Administrative Agent determines exposes the Administrative Agent to liability or that is contrary to this Agreement, the Credit Documents or applicable law.  The Administrative Agent shall not be liable for any action taken or not taken by it with the consent or at the request of the Majority Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Article XII) and otherwise the Administrative Agent shall not be liable for any action taken or not taken by it hereunder or under any other Credit Document or under any other document or instrument referred to or provided for herein or therein or in connection herewith or therewith INCLUDING ITS OWN ORDINARY NEGLIGENCE, except for its own gross negligence or willful misconduct

Section 12.2   Exculpatory Provisions.  Neither the Administrative Agent nor any of its officers, directors, employees, agents, attorneys-in-fact or Affiliates shall be (a) liable for any action lawfully taken or omitted to be taken by any of them under or in connection with this Agreement or any other Credit Document (except for its or such Person’s own gross negligence or willful misconduct, as determined in the final judgment of a court of competent jurisdiction, in connection with its duties expressly set forth herein) or (b) responsible in any manner to any of the Lenders or any participant for any recitals, statements, representations or warranties made by any of the Borrower, any other Credit Party or any officer thereof contained in this Agreement or any other Credit Document or in any certificate, report, statement or other document referred to or provided for in, or received by the Administrative Agent under or in connection with, this Agreement or any other Credit Document or for the value, validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement, any other Credit Document or any Collateral, or, except with respect to any physical certificate or instrument representing pledged debt securities or pledged stock (in each case, as defined in the Security Agreement) in the possession of the Administrative Agent, the existence, value, perfection or priority of any Lien or security interest created or purported to be created under the Security Documents, the financial condition of any Credit Party or for any failure of the Borrower or any other Credit Party to perform its obligations

​ 125

​ hereunder or thereunder. The Administrative Agent shall not be under any obligation to any Lender to ascertain or to inquire as to the observance or performance of any of the agreements contained in, or conditions of, this Agreement or any other Credit Document, or to inspect the properties, books or records of any Credit Party or any Affiliate thereof.

Section 12.3    Reliance by the Administrative Agent.  The Administrative Agent shall be entitled to rely, and shall be fully protected in relying, upon any writing, resolution, notice, consent, certificate, affidavit, letter, telecopy, telex or teletype message, statement, order or other document or instruction believed by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons and upon advice and statements of legal counsel (including counsel to the Borrower), independent accountants and other experts selected by the Administrative Agent. The Administrative Agent may deem and treat the Lender specified in the Register with respect to any amount owing hereunder as the owner thereof for all purposes unless a written notice of assignment, negotiation or transfer thereof shall have been filed with the Administrative Agent. The Administrative Agent shall be fully justified in failing or refusing to take any action under this Agreement or any other Credit Document unless it shall first receive such advice or concurrence of the Majority Lenders as it deems appropriate or it shall first be indemnified to its satisfaction by the Lenders against any and all liability and expense that may be incurred by it by reason of taking or continuing to take any such action. The Administrative Agent shall in all cases be fully protected in acting, or in refraining from acting, under this Agreement and the other Credit Documents in accordance with a request of the Majority Lenders, and such request and any action taken or failure to act pursuant thereto shall be binding upon all the Lenders and all future holders of the Loans; provided that the Administrative Agent shall not be required to take any action that, in its opinion or in the opinion of its counsel, may expose it to liability or that is contrary to any Credit Document or applicable Requirements of Law. For purposes of determining compliance with the conditions specified in Article VI and Article VII on the Amendment No. 2 Effective Date, each Lender that has signed this Agreement shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received notice from such Lender prior to the proposed Amendment No. 2 Effective Date specifying its objection thereto.

Section 12.4    Notice of Default.  The Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default hereunder unless the Administrative Agent has received notice from a Lender or the Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. In the event that the Administrative Agent receives such a notice, it shall give notice thereof to the Lenders. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be reasonably directed by the Majority Lenders; provided that unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders except to the extent that this Agreement requires that such action be taken only with the approval of the Majority Lenders or each individual lender, as applicable.

Section 12.5     Non-Reliance on the Administrative Agent and Other Lenders.  Each Lender expressly acknowledges that neither the Administrative Agent nor any of its officers,

​ 126

​ directors, employees, agents, attorneys-in-fact or Affiliates has made any representations or warranties to it and that no act by the Administrative Agent hereinafter taken, including any review of the affairs of the Borrower or any other Credit Party, shall be deemed to constitute any representation or warranty by the Administrative Agent to any Lender or any Issuing Bank. Each Lender and each Issuing Bank represents to the Administrative Agent that it has, independently and without reliance upon the Administrative Agent or any other Lender, and based on such documents and information as it has deemed appropriate, made its own appraisal of and investigation into the business, operations, property, financial and other condition and creditworthiness of the Borrower and each other Credit Party and made its own decision to make its Advances hereunder and enter into this Agreement. Each Lender also represents that it will, independently and without reliance upon the Administrative Agent or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit analysis, appraisals and decisions in taking or not taking action under this Agreement and the other Credit Documents, and to make such investigation as it deems necessary to inform itself as to the business, operations, property, financial and other condition and creditworthiness of the Borrower and any other Credit Party. Except for notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent hereunder, the Administrative Agent shall not have any duty or responsibility to provide any Lender with any credit or other information concerning the business, assets, operations, properties, financial condition, prospects or creditworthiness of the Borrower or any other Credit Party that may come into the possession of the Administrative Agent or any of its officers, directors, employees, agents, attorneys-in-fact or Affiliates.

Section 12.6     Indemnification.  The Lenders severally agree to indemnify the Administrative Agent and its Related Parties in their capacities as such (to the extent not reimbursed by the Credit Parties and without limiting the obligation of the Credit Parties to do so), ratably according to their respective portions of the Commitments or Loans, as applicable, outstanding in effect on the date on which indemnification is sought (or, if indemnification is sought after the date upon which the Commitments shall have terminated and the Loans shall have been paid in full, ratably in accordance with their respective portions of the Total Outstandings in effect immediately prior to such date), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time occur (including at any time following the payment of the Loans) be imposed on, incurred by or asserted against the Administrative Agent in any way relating to or arising out of the Commitments, this Agreement, any of the other Credit Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by the Administrative Agent or its Related Parties under or in connection with any of the foregoing; provided that no Lender shall be liable to the Administrative Agent or its Related Parties for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from such Administrative Agent’s or the Related Parties’ gross negligence, bad faith or willful misconduct as determined by a final judgment of a court of competent jurisdiction; provided, further, that no action taken in accordance with the directions of the Majority Lenders shall be deemed to constitute gross negligence, bad faith or willful misconduct for purposes of this Section 12.6. In the case of any investigation, litigation or proceeding giving rise to any liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time occur (including at any time following the payment

​ 127

​ of the Loans), this Section 12.6 applies whether any such investigation, litigation or proceeding is brought by any Lender or any other Person. Without limitation of the foregoing, each Lender shall reimburse the Administrative Agent upon demand for its ratable share of any costs or out-of-pocket expenses (including attorneys’ fees) incurred by such Administrative Agent in connection with the preparation, execution, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice rendered in respect of rights or responsibilities under, this Agreement, any other Credit Document, or any document contemplated by or referred to herein, to the extent that it is not reimbursed for such expenses by or on behalf of the Borrower; provided that such reimbursement by the Lenders shall not affect the Borrower’s continuing reimbursement obligations with respect thereto. If any indemnity furnished to the Administrative Agent for any purpose shall, in the opinion of the Administrative Agent, be insufficient or become impaired, the Administrative Agent may call for additional indemnity and cease, or not commence, to do the acts indemnified against until such additional indemnity is furnished; provided, in no event shall this sentence require any Lender to indemnify the Administrative Agent or its Related Parties against any liability, obligation, loss, damage, penalty, action, judgment, suit, cost, expense or disbursement in excess of such Lender’s pro rata portion thereof; and provided further, this sentence shall not be deemed to require any Lender to indemnify the Administrative Agent or its Related Parties against any liability, obligation, loss, damage, penalty, action, judgment, suit, cost, expense or disbursement resulting from the Administrative Agent’s or the Related Parties’ gross negligence, bad faith or willful misconduct. The agreements in this Section 12.6 shall survive the payment of the Loans and all other amounts payable hereunder.

Section 12.7    The Administrative Agent in Its Individual Capacity.  The Administrative Agent and its Affiliates may make loans to, accept deposits from and generally engage in any kind of business with the Borrower and any other Credit Party as though the Administrative Agent were not the Administrative Agent hereunder and under the other Credit Documents. With respect to the Loans made by it, the Administrative Agent shall have the same rights and powers under this Agreement and the other Credit Documents as any Lender and may exercise the same as though it were not the Administrative Agent, and the terms “Lender” and “Lenders” shall include the Administrative Agent in its individual capacity.

Section 12.8     Successor Agents.  The Administrative Agent may at any time give notice of its resignation to the Lenders, the Issuing Banks and the Borrower. If the Administrative Agent becomes a Defaulting Lender, then such Administrative Agent may be removed as the Administrative Agent, at the reasonable request of the Borrower and the Majority Lenders. Upon receipt of any such notice of resignation or removal, as the case may be, the Majority Lenders shall have the right, subject to the consent of the Borrower (not to be unreasonably withheld or delayed) so long as no Default under Section 11.1 or 11.5 is continuing, to appoint a successor, which shall be a bank with an office in the United States, or an Affiliate of any such bank with an office in the United States. If, in the case of a resignation of a retiring Administrative Agent, no such successor shall have been so appointed by the Majority Lenders and shall have accepted such appointment within 30 days after the retiring Agent gives notice of its resignation, then the retiring Administrative Agent may on behalf of the Lenders and the Issuing Banks, appoint a successor Agent meeting the qualifications set forth above. Whether or not a successor has been appointed, such resignation shall become effective at the end of such 30-day period.  In the event that no successor administrative agent shall have accepted such appointment within 30 days, such

​ 128

​ resignation shall nonetheless be effective and the Majority Lenders shall act as Administrative Agent hereunder.  Upon the acceptance of a successor’s appointment as the Administrative Agent hereunder, and upon the execution and filing or recording of such financing statements, or amendments thereto, and such other instruments or notices, as may be necessary or desirable, or as the Majority Lenders may request, in order to continue the perfection of the Liens granted or purported to be granted by the Security Documents, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired) Administrative Agent, and the retiring Administrative Agent shall be discharged from all of its duties and obligations hereunder or under the other Credit Documents (if not already discharged therefrom as provided above in this Section 12.8). The fees payable by the Borrower (following the effectiveness of such appointment) to the Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the retiring Administrative Agent’s resignation hereunder and under the other Credit Documents, the provisions of this Article XII (including Section 12.6) and Section 13.5 shall continue in effect for the benefit of such retiring Administrative Agent, and its Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring Administrative Agent was acting as the Administrative Agent.

Any resignation of any Person as Administrative Agent pursuant to this Section 12.8 shall also constitute its resignation as Issuing Bank. Upon the acceptance of a successor’s appointment as Administrative Agent hereunder, (a) such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring Issuing Bank, (b) the retiring Issuing Bank shall be discharged from all of its respective duties and obligations hereunder or under the other Credit Documents, and (c) the successor Issuing Bank shall issue letters of credit in substitution for the Letters of Credit, if any, outstanding at the time of such succession or make other arrangements satisfactory to the retiring Issuing Bank to effectively assume the obligations of the retiring Issuing Bank with respect to such Letters of Credit.

Section 12.9    Withholding Tax.  To the extent required by any applicable Requirement of Law, the Administrative Agent may withhold from any payment to any Lender an amount equivalent to any applicable withholding tax. If the Internal Revenue Service or any authority of the United States or other jurisdiction asserts a claim that the Administrative Agent did not properly withhold tax from amounts paid to or for the account of any Lender for any reason (including because the appropriate form was not delivered, was not properly executed, or because such Lender failed to notify the Administrative Agent of a change in circumstances that rendered the exemption from, or reduction of, withholding tax ineffective), such Lender shall indemnify the Administrative Agent (to the extent that the Administrative Agent has not already been reimbursed by any applicable Credit Party and without limiting the obligation of any applicable Credit Party to do so) fully for all amounts paid, directly or indirectly, by the Administrative Agent as Tax or otherwise, including penalties, additions to Tax and interest, together with all expenses incurred, including legal expenses, allocated staff costs and any out of pocket expenses. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under this Agreement or any other Credit Document against any amount due to the Administrative Agent under this Section 12.9. For the avoidance of doubt, for purposes of this Section 12.9, the term “Lender” includes any Issuing Bank.

​ 129

​ Section 12.10  Security Documents and Guarantee.  Each Secured Party hereby further authorizes the Administrative Agent, on behalf of and for the benefit of Secured Parties, to be the agent for and representative of the Secured Parties with respect to the Collateral and the Security Documents. Subject to Section 13.1, without further written consent or authorization from any Secured Party or the Administrative Agent, as applicable, may (a) execute any documents or instruments necessary in connection with a Disposition of assets permitted by this Agreement, (b) release any Lien encumbering any item of Collateral that is the subject of such Disposition of assets or with respect to which Majority Lenders (or such other Lenders as may be required to give such consent under Section 13.1) have otherwise consented or (c) release any applicable Guarantor from the Guarantee in connection with such Disposition or with respect to which Majority Lenders (or such other Lenders as may be required to give such consent under Section 13.1) have otherwise consented. The Lenders and the Issuing Banks (including in their capacities as potential Cash Management Banks and potential Hedge Banks) irrevocably agree that (x) the Administrative Agent may, without any further consent of any Lender, enter into or amend any intercreditor agreement with the representatives of the holders of Indebtedness that is permitted to be secured by a Lien on the Collateral that is permitted under this Agreement, (y) the Administrative Agent may rely exclusively on a certificate of an Authorized Officer of the Borrower as to whether any such other Liens are permitted and (z) any such intercreditor agreement referred to in clause (x) above, entered into by the Administrative Agent, shall be binding on the Secured Parties. Furthermore, the Lenders and the Issuing Banks (including in their capacities as potential Cash Management Bank and potential Hedge Banks) hereby authorize the Administrative Agent to subordinate any Lien on any property granted to or held by the Administrative Agent under any Credit Document to the holder of any Lien on such property that is a Permitted Lien; provided that prior to any such request, the Borrower shall have in each case delivered to the Administrative Agent a certificate of an Authorized Officer of the Borrower certifying that such subordination is permitted under this Agreement.

Section 12.11  Right to Realize on Collateral and Enforce Guarantee.  Anything contained in any of the Credit Documents to the contrary notwithstanding, the Borrower, the Administrative Agent and each Secured Party hereby agree that (a) no Secured Party shall have any right individually to realize upon any of the Collateral or to enforce the Guarantee, it being understood and agreed that all powers, rights and remedies hereunder may be exercised solely by the Administrative Agent, on behalf of the Secured Parties in accordance with the terms hereof and all powers, rights and remedies under the Security Documents may be exercised solely by the Administrative Agent, and (b) in the event of a foreclosure by the Administrative Agent on any of the Collateral pursuant to a public or private sale or other disposition, the Administrative Agent or any Lender may be the purchaser or licensor of any or all of such Collateral at any such sale or other disposition and the Administrative Agent, as agent for and representative of the Secured Parties (but not any Lender or Lenders in its or their respective individual capacities unless the Majority Lenders shall otherwise agree in writing) shall be entitled, for the purpose of bidding and making settlement or payment of the purchase price for all or any portion of the Collateral sold at any such public sale, to use and apply any of the Obligations as a credit on account of the purchase price for any collateral payable by the Administrative Agent at such sale or other disposition.

Section 12.12  The Administrative Agent May File Proofs of Claim.  In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding, constituting an Event of Default under

​ 130

​ Section 11.5, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a)        to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Indebtedness that is owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel, to the extent due under Section 13.5) allowed in such judicial proceeding; and

(b)        to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, to the extent due under Section 13.5.

Nothing contained herein shall be deemed to authorize the Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Indebtedness or the rights of any Lender or to authorize the Administrative Agent to vote in respect of the claim of any Lender in any such proceeding.

Section 12.13  Credit Bidding.  The Secured Parties hereby irrevocably authorize Administrative Agent, at the direction of the Majority Lenders, to credit bid all or any portion of the Obligations (including by accepting some or all of the Collateral in satisfaction of some or all of the Obligations pursuant to a deed in lieu of foreclosure or otherwise) and in such manner purchase (either directly or through one or more acquisition vehicles) all or any portion of the Collateral (a) at any sale thereof conducted under the provisions of the Bankruptcy Code, including under Sections 363, 1123 or 1129 of the Bankruptcy Code, or any similar laws in any other jurisdictions to which a Person is subject, or (b) at any other sale, foreclosure or acceptance of collateral in lieu of debt conducted by (or with the consent or at the direction of) Administrative Agent (whether by judicial action or otherwise) in accordance with any applicable law.  In connection with any such credit bid and purchase, the Obligations shall be credit bid by Administrative Agent at the direction of the Majority Lenders on a ratable basis (with Obligations with respect to contingent or unliquidated claims receiving contingent interests in the acquired assets on a ratable basis that shall vest upon the liquidation of such claims in an amount proportional to the liquidated portion of the contingent claim amount used in allocating the contingent interests) for the asset or assets so purchased (or for the equity interests or debt instruments of the acquisition vehicle or vehicles that are issued in connection with such purchase).  In connection with any such bid Administrative Agent shall be authorized to form one or more

​ 131

​ acquisition vehicles and to assign any successful credit bid to such acquisition vehicle or vehicles in such manner as shall be approved by Majority Lenders.  Each of the Lenders, the Issuing Banks, the Cash Management Banks and the Hedge Banks agree to execute such documents and provide such information regarding itself (and/or any designee which will receive interests in or debt instruments issued by such acquisition vehicle) as Administrative Agent may reasonably request in connection with the formation of any acquisition vehicle, the formulation or submission of any credit bid or the consummation of the transactions contemplated by such credit bid.

Section 12.14  Sub-agents.  The Administrative Agent may perform any of its duties and exercise its rights and powers hereunder or under any other Credit Document by or through any one or more sub-agents appointed by the Administrative Agent.  The Administrative Agent and any such sub-agent may perform any of its duties and exercise its rights and powers through their respective Related Parties.  The exculpatory provisions of the preceding paragraphs will apply to any such sub-agent and to the Related Parties of the Administrative Agent and any such sub-agent, and will apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.  The Administrative Agent shall not be responsible for the negligence or misconduct of any sub-agents except to the extent that a court of competent jurisdiction determines in a final and non-appealable judgment that the Administrative Agent acted with gross negligence or willful misconduct in the selection of such sub-agents.

ARTICLE XIII

MISCELLANEOUS

Section 13.1    Amendments, Waivers and Releases .

(a)        Except as expressly set forth in this Agreement (including, without limitation, Section 2.9(d)), neither this Agreement nor any other Credit Document, nor any terms hereof or thereof, may be amended, supplemented or modified except in accordance with the provisions of this Section 13.1. The Majority Lenders may, or, with the written consent of the Majority Lenders, the Administrative Agent shall, from time to time, (i) enter into with the relevant Credit Party or Credit Parties written amendments, supplements or modifications hereto and to the other Credit Documents for the purpose of adding any provisions to this Agreement or the other Credit Documents or changing in any manner the rights of the Lenders or of the Credit Parties hereunder or thereunder or (ii) waive in writing, on such terms and conditions as the Majority Lenders or the Administrative Agent may specify in such instrument, any of the requirements of this Agreement or the other Credit Documents or any Default or Event of Default and its consequences; provided, however, that each such waiver and each such amendment, supplement or modification shall be effective only in the specific instance and for the specific purpose for which given; provided, further, that no such waiver and no such amendment, supplement or modification shall (A) forgive or reduce any portion of any Loan or reduce the stated rate (it being understood that only the consent of the Majority Lenders shall be necessary to waive any obligation of the Borrower to pay interest at the Default Rate or amend Section 2.7(e)), or forgive any portion, or extend the date for the payment, of any interest or fee payable hereunder (other than as a result of waiving the applicability of any post-default increase in interest rates and any change due to a change in the Borrowing Base or Available

​ 132

​ Commitment), or extend the final expiration date of any Lender’s Commitment (provided that it is being understood that waivers or modifications of conditions precedent, covenants, Defaults or Events of Default shall not constitute an increase of the Commitment of any Lender) or extend the final expiration date of any Letter of Credit beyond the L/C Maturity Date, or increase the amount of the Commitment of any Lender, or make any Loan, interest, fee or other amount payable in any currency other than Dollars, in each case without the written consent of each Lender directly and adversely affected thereby, or (B) amend, modify or waive any provision of this Section 13.1 in a manner that would reduce the voting rights of any Lender, or reduce the percentages specified in the definitions of the terms “Majority Lenders” or “Required Lenders,” consent to the assignment or transfer by the Borrower of its rights and obligations under any Credit Document to which it is a party, in each case without the written consent of each Lender directly and adversely affected thereby, or (C) amend the provisions of Section 11.11 or any analogous provision of any Security Document, in a manner that would by its terms alter the pro rata sharing of payments required thereby, without the prior written consent of each Lender directly and adversely affected thereby, or (D) amend, modify or waive any provision of Article XII without the written consent of the then-current Administrative Agent, or any other former Administrative Agent to whom Article XII then applies in a manner that directly and adversely affects such Person, or (E) amend, modify or waive any provision of Article III with respect to any Letter of Credit without the written consent of each Issuing Bank to whom Article III then applies in a manner that directly and adversely affects such Person, or (F) release all or substantially all of the Guarantors under the Guarantee (except as expressly permitted by the Guarantee or this Agreement) without the prior written consent of each Lender, or (G) release all or substantially all of the Collateral under the Security Documents (except as expressly permitted by the Security Documents or this Agreement) without the prior written consent of each Lender, or (H) increase the Borrowing Base without the written consent of the Lenders (other than Defaulting Lenders), decrease or maintain the Borrowing Base without the written consent of the Required Lenders (other than Defaulting Lenders) or otherwise modify Sections 2.14, 2.15, 2.16 or 2.17 if such modification would have the effect of increasing the Borrowing Base without the written consent of the Lenders (other than Defaulting Lenders); provided that a scheduled redetermination of the Borrowing Base under Section 2.14 may be postponed by the Required Lenders, or (J) affect the rights or duties of, or any fees or other amounts payable to, the Administrative Agent without the prior written consent of such Agent. Any such waiver and any such amendment, supplement or modification shall apply equally to each of the affected Lenders and shall be binding upon the Borrower, such Lenders, the Administrative Agent and all future holders of the affected Loans. In the case of any waiver, the Borrower, the Lenders and the Administrative Agent shall be restored to their former positions and rights hereunder and under the other Credit Documents, and any Default or Event of Default waived shall be deemed to be cured and not continuing; it being understood that no such waiver shall extend to any subsequent or other Default or Event of Default or impair any right consequent thereon. In connection with the foregoing provisions, the Administrative Agent may, but shall have no obligations to, with the concurrence of any Lender, execute amendments, modifications, waivers or consents on behalf of such Lender whose consent is required hereunder.

​ 133

​ (b)        Without the consent of any Lender or Issuing Bank, (i) the Credit Parties and the Administrative Agent may (in their respective sole discretion, or shall, to the extent required by any Credit Document) enter into any amendment, modification or waiver of any Credit Document, or enter into any new agreement or instrument, to effect the granting, perfection, protection, expansion or enhancement of any security interest in any Collateral or additional property to become Collateral for the benefit of the Secured Parties, or as required by local law to give effect to, or protect any security interest for the benefit of the Secured Parties, in any property or so that the security interests therein comply with applicable law or this Agreement or in each case to otherwise enhance the rights or benefits of any Lender under any Credit Document and (ii) if the Credit Parties and the Administrative Agent acting together identify any ambiguity, omission, mistake, typographical error or other defect in any provision of this Agreement (including this Section) or any other Credit Document (including the schedules and exhibits thereto), then the Administrative Agent and the Credit Parties shall be permitted to amend, modify or supplement such provision to cure such ambiguity, omission, mistake, typographical error or other defect, and such amendment shall become effective without any further action or consent of any other party to this Agreement.

Section 13.2     Notices.  Unless otherwise expressly provided herein, all notices and other communications provided for hereunder or under any other Credit Document shall be in writing (including by facsimile transmission). All such written notices shall be mailed, faxed or delivered to the applicable address, facsimile number or electronic mail address, and all notices and other communications expressly permitted hereunder to be given by telephone shall be made to the applicable telephone number, as follows:

(a)        if to the Borrower, the Administrative Agent or any Issuing Bank, to the address, facsimile number, electronic mail address or telephone number specified for such Person on Schedule 13.2 or to such other address, facsimile number, electronic mail address or telephone number as shall be designated by such party in a notice to the other parties; and

(b)        if to any other Lender, to the address, facsimile number, electronic mail address or telephone number specified in its Administrative Questionnaire or to such other address, facsimile number, electronic mail address or telephone number as shall be designated by such party in a notice to the Borrower, the Administrative Agent and the Issuing Banks.

All such notices and other communications shall be deemed to be given or made upon the earlier to occur of (i) actual receipt by the relevant party hereto and (ii) (A) if delivered by hand or by courier, when signed for by or on behalf of the relevant party hereto; (B) if delivered by mail, three Business Days after deposit in the mails, postage prepaid; (C) if delivered by facsimile, when sent and receipt has been confirmed by telephone; and (D) if delivered by electronic mail, when delivered; provided that notices and other communications to the Administrative Agent or the Lenders pursuant to Sections 2.1, 2.3, 2.5, 2.8, 4.2 and 5.1 shall not be effective until received.

The Borrower agrees that the Administrative Agent may, but shall not be obligated to, make the Communications (as defined below) available to the Issuing Banks and the other Lenders

​ 134

​ by posting the Communications on the Platform.    The Platform is provided “as is” and “as available.”  The Agent Parties (as defined below) do not warrant the adequacy of the Platform and expressly disclaim liability for errors or omissions in the Communications.  No warranty of any kind, express, implied or statutory, including any warranty of merchantability, fitness for a particular purpose, non-infringement of third-party rights or freedom from viruses or other code defects, is made by any Agent Party in connection with the Communications or the Platform.  In no event shall the Administrative Agent or any of its Related Parties (collectively, the “Agent Parties”) have any liability to the Borrower, any Lender or any other Person or entity for damages of any kind, including direct or indirect, special, incidental or consequential damages, losses or expenses (whether in tort, contract or otherwise) arising out of the Borrower’s or the Administrative Agent’s transmission of communications through the Platform, except for such Agent Party’s own gross negligence or willful misconduct.  “Communications” means, collectively, any notice, demand, communication, information, document or other material provided by or on behalf of the Borrower pursuant to any Credit Document or the transactions contemplated therein that is distributed to the Administrative Agent, any Lender or any Issuing Bank by means of electronic communications pursuant to this Section, including through the Platform.

Section 13.3    No Waiver; Cumulative Remedies.  No failure to exercise and no delay in exercising, on the part of the Administrative Agent or any Lender, any right, remedy, power or privilege hereunder or under the other Credit Documents shall operate as a waiver thereof, nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by Requirements of Law.

Section 13.4    Survival of Representations and Warranties.  All representations and warranties made hereunder, in the other Credit Documents and in any document, certificate or statement delivered pursuant hereto or in connection herewith shall survive the execution and delivery of this Agreement and the making of the Loans hereunder.

Section 13.5    Payment of Expenses; Indemnification.  The Borrower agrees (a) to pay or reimburse the Administrative Agent for all its reasonable and documented out-of-pocket costs and expenses incurred in connection with the preparation and execution and delivery of, and any amendment, waiver, supplement or modification to, this Agreement and the other Credit Documents and any other documents prepared in connection herewith or therewith, and the consummation and administration of the transactions contemplated hereby and thereby, including the reasonable fees, disbursements and other charges of Willkie Farr & Gallagher LLP, in its capacity as counsel to the Administrative Agent, and one counsel in each appropriate local jurisdiction (excluding any allocated costs of in-house counsel), (b) to pay or reimburse each Issuing Bank and the Administrative Agent for all its reasonable and documented out-of-pocket costs and expenses incurred in connection with the enforcement or preservation of any rights under this Agreement, the other Credit Documents and any such other documents, including the reasonable fees, disbursements and other charges of one counsel to the Administrative Agent, (c) to pay, indemnify and hold harmless each Lender, each Issuing Bank and the Administrative Agent from any and all recording and filing fees and (d) to pay, indemnify and hold harmless each Lender, Issuing Bank and the Administrative Agent and their respective Related Parties from and against

​ 135

​ any and all other liabilities, obligations, losses, damages, penalties, claims, demands, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever, whether or not such proceedings are brought by the Borrower, any of its Related Parties or any other third Person, including reasonable and documented fees, disbursements and other charges of one primary counsel for all such Persons, taken as a whole, and, if necessary, by a single firm of local counsel in each appropriate jurisdiction for all such Persons, taken as a whole (unless there is an actual or perceived conflict of interest in which case each such Person may, with the consent of the Borrower (not to be unreasonably withheld or delayed), retain its own counsel), with respect to (i) the execution, delivery, enforcement, performance and administration of this Agreement, the other Credit Documents and any such other documents and (ii) any Loan or Letter of Credit or the use of the proceeds therefrom (including any refusal by any Issuing Bank to honor a demand for payment under a Letter of Credit if the documents presented in connection with such demand do not strictly comply with the terms of such Letter of Credit), including, without limitation, any of the foregoing relating to the violation of, noncompliance with or liability under any Environmental Law (other than by such indemnified person or any of its Related Parties (other than any trustee or advisor)) or to any actual or alleged presence, release or threatened release of Hazardous Materials involving or attributable to the Borrower, any of its Restricted Subsidiaries or any of the Oil and Gas Properties (all the foregoing in this clause (d), collectively, the “Indemnified Liabilities”); provided that the Borrower shall have no obligation hereunder to the Administrative Agent or any Lender or any of their respective Related Parties with respect to Indemnified Liabilities to the extent that such Indemnified Liabilities have resulted from (i) the gross negligence, bad faith or willful misconduct of the party to be indemnified or any of its Related Parties as determined by a final non-appealable judgment of a court of competent jurisdiction, (ii) any material breach of any Credit Document by any Lender or Issuing Bank or any of their Related Parties (other than the Administrative Agent, acting in its capacity as such, and its directors, officers, employees, agent and consultants) or (iii) disputes, claims, demands, actions, judgments or suits not arising from any act or omission by the Borrower or its Affiliates, brought by an indemnified Person against any other indemnified Person (other than disputes, claims, demands, actions, judgments or suits involving claims against the Administrative Agent in its capacity as such). No Person entitled to indemnification under clause (d) of this Section 13.5 shall be liable for any damages arising from the use by others of any information or other materials obtained through internet, electronic, telecommunications or other information transmission systems (including IntraLinks or SyndTrak Online) in connection with this Agreement, except to the extent that such damages have resulted from the willful misconduct, bad faith or gross negligence of the party to be indemnified or any of its Related Parties (as determined by a court of competent jurisdiction in a final and non-appealable decision), nor (except solely as a result of the indemnification obligations of the Borrower or any of its Restricted Subsidiaries set forth above) shall any such Person, the Borrower or any of its Restricted Subsidiaries have any liability for any special, punitive, indirect or consequential damages (including, without limitation, any loss of profits, business or anticipated savings) relating to this Agreement or any other Credit Document or arising out of its activities in connection herewith or therewith (whether before or after the Effective Date) other than any such damages or claims incurred or paid to a third party, or which are included in a third-party claim, and any out-of-pocket expenses related hereto. All amounts payable under this Section 13.5 shall be paid within ten (10) Business Days of receipt by the Borrower of an invoice relating thereto setting forth such expense in reasonable detail, accompanied, if requested by the Borrower, by reasonable supporting documentation. The agreements in this Section 13.5 shall survive repayment of the Loans and all

​ 136

​ other amounts payable hereunder. This Section 13.5 shall not apply with respect to any Taxes other than Taxes that represent liabilities, obligations, losses, damages, penalties, claims, demands, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever resulting from a non-Tax claim, which shall be governed exclusively by Section 5.4 and, to the extent set forth therein, Sections 2.10 and 3.5.

Section 13.6    Successors and Assigns; Participations and Assignments .

(a)        The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby (including any Affiliate of each Issuing Bank that issues any Letter of Credit), except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of the Administrative Agent and each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 13.6. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby (including any Affiliate of each Issuing Bank that issues any Letter of Credit) (the “Participants”) (to the extent provided in clause (c) of this Section 13.6) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, each Issuing Bank and the Lenders and each other Person entitled to indemnification under Section 13.5) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)        (i) Subject to the conditions set forth in clause (b)(ii) below, any Lender may at any time assign to one or more assignees (other than the Borrower, its Subsidiaries, any natural person or any Defaulting Lender) all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans (including participations in L/C Obligations) at the time owing to it) with the prior written consent of:

(A)     the Borrower; provided that no consent of the Borrower shall be required for an assignment if an Event of Default under Section 11.1 or Section 11.5 has occurred and is continuing or in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund; and

(B)      the Administrative Agent and each Issuing Bank (in each case, not to be unreasonably withheld or delayed).

(ii)       Assignments shall be subject to the following additional conditions:

(A)     except in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund or an assignment of the entire remaining amount of the assigning Lender’s Commitment or Loans, the amount of the Commitment or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Acceptance with respect to such assignment is delivered to the Administrative Agent)

​ 137

​ shall not be less than $5,000,000 and increments of $1,000,000 in excess thereof, unless each of the Borrower, each Issuing Bank and the Administrative Agent otherwise consents (which consents shall not be unreasonably withheld or delayed); provided that no such consent of the Borrower shall be required if an Event of Default under Section 11.1 or Section 11.5 has occurred and is continuing; provided, further, that contemporaneous assignments to a single assignee made by Affiliates of Lenders and related Approved Funds shall be aggregated for purposes of meeting the minimum assignment amount requirements stated above;

(B)      each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement;

(C)      the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Acceptance, together with a processing and recordation fee in the amount of $3,500; provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and recordation fee in the case of any assignment; and

(D)     the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire and applicable Tax forms (including those described in Section 5.4), as applicable.

(iii)      Subject to acceptance and recording thereof pursuant to clause (b)(iv) of this Section 13.6, from and after the effective date specified in each Assignment and Acceptance, the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Acceptance, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Acceptance, be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.10, 2.12, 3.5, 5.4 and 13.5). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 13.6 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with clause (c) of this Section 13.6.

(iv)       The Administrative Agent, acting for this purpose as an agent of the Borrower, shall maintain at the Administrative Agent’s Office a copy of each Assignment and Acceptance delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitment of, and principal amount (and stated interest amounts) of the Loans and L/C Obligations and any payment made by each Issuing Bank under any applicable Letter of Credit owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). Further, the Register shall contain the name and address of the Administrative Agent and

​ 138

​ the lending office through which each such Person acts under this Agreement. The entries in the Register shall be conclusive absent manifest error, and the Borrower, the Administrative Agent, each Issuing Bank and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower, each Issuing Bank, and, solely with respect to itself, each other Lender, at any reasonable time and from time to time upon reasonable prior notice.

(v)        Upon its receipt of a duly completed Assignment and Acceptance executed by an assigning Lender and an assignee, the assignee’s completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in clause (b) of this Section 13.6 (unless waived) and any written consent to such assignment required by clause (b) of this Section 13.6, the Administrative Agent shall accept such Assignment and Acceptance and record the information contained therein in the Register.

(c)        (i) Any Lender may, without the consent of the Borrower, the Administrative Agent or any Issuing Bank, sell participations to one or more banks or other entities other than any Defaulting Lender, the Borrower or any Subsidiary of the Borrower (each, a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans owing to it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent, each Issuing Bank and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement or any other Credit Document; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in clause (A) or (B) of the second proviso of the second sentence of Section 13.1(a) that affects such Participant, provided that the Participant shall have no right to consent to any modification to the percentages specified in the definition of the term “Majority Lenders” or “Required Lenders.”  Subject to clause (c)(ii) of this Section 13.6, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.10, 2.12, 3.5 and 5.4 to the same extent as if it were a Lender (subject to the limitations and requirements of those Sections and Section 13.7) as though it were a Lender and had acquired its interest by assignment pursuant to clause (b) of this Section 13.6). To the extent permitted by Requirements of Law, each Participant also shall be entitled to the benefits of Section 13.8(b) as though it were a Lender; provided such Participant agrees to be subject to Section 13.8(a) as though it were a Lender.

(ii)       A Participant shall not be entitled to receive any greater payment under Sections 2.10, 2.12, 3.5 or 5.4 than the applicable Lender would have been entitled to

​ 139

​ receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent (which consent shall not be unreasonably withheld); provided that the Participant shall be subject to the provisions in Section 2.11 as if it were an assignee under clauses (a) and (b) of this Section 13.6. Each Lender that sells a participation shall, acting solely for this purpose as a nonfiduciary agent of the Borrower, maintain a register on which it enters the name and address of each participant and the principal amounts (and related interest amounts) of each participant’s interest in the Loans or other obligations under this Agreement (the “Participant Register”). The entries in the Participant Register shall be conclusive, absent manifest error, and each party hereto shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. No Lender shall have any obligation to disclose all or any portion of the Participant Register to any Person (including the identity of any Participant or any information relating to a Participant’s interest in any commitments, loans, letters of credit or its other obligations under any Credit Document) except to the extent that such disclosure is necessary to establish that such commitment, loan, letter of credit or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations.

(d)        Any Lender may, without the consent of the Borrower, any Issuing Bank or the Administrative Agent, at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or any central bank having jurisdiction over such Lender, and this Section 13.6 shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto. In order to facilitate such pledge or assignment or for any other reason, the Borrower hereby agrees that, upon request of any Lender at any time and from time to time after the Borrower has made its initial borrowing hereunder, the Borrower shall provide to such Lender, at the Borrower’s own expense, a promissory note, substantially in the form of Exhibit C, evidencing the Loans owing to such Lender.

(e)        Subject to Section 13.16, the Borrower authorizes each Lender to disclose to any Participant, secured creditor of such Lender or assignee (each, a “Transferee”) and any prospective Transferee any and all financial information in such Lender’s possession concerning the Borrower and its Affiliates that has been delivered to such Lender by or on behalf of the Borrower and its Affiliates pursuant to this Agreement or that has been delivered to such Lender by or on behalf of the Borrower and its Affiliates in connection with such Lender’s credit evaluation of the Borrower and its Affiliates prior to becoming a party to this Agreement.

(f)        The words “execution,” “signed,” “signature,” and words of like import in any Assignment and Acceptance shall be deemed to include electronic signatures or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any

​ 140

​ applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the Texas Uniform Electronics Transactions Act or any other similar state laws based on the Uniform Electronic Transactions Act.

(g)        Notwithstanding anything to the contrary contained herein, any Lender may, at any time, assign all or a portion of its rights and obligations under this Agreement in respect of its Loans to an Affiliated Lender; provided that an Affiliated Lender shall make a representation and warranty to such assigning Lender that at the time of the assignment such Affiliated Lender is not in possession of any material non-public information (within the meaning of United States securities laws) with respect to the Borrower and its Subsidiaries that has not been disclosed to such assigning Lender or the Lenders generally (other than because any such Lender has elected not to receive such material non-public information); provided further that, by its acquisition of Loans, an Affiliated Lender shall be deemed to have acknowledged and agreed that:

(i)         it shall not have any right to (A) attend (including by telephone) any meeting or discussions (or portion thereof) among the Administrative Agent or any Lender to which representatives of the Borrower are not then present, (B) receive any information or material prepared by the Administrative Agent or any Lender or any communication by or among Administrative Agent and one or more Lenders, except to the extent such information or materials have been made available to the Borrower or its representatives (and in any case, other than the right to receive notices of prepayments and other administrative notices in respect of its Loans required to be delivered to Lenders pursuant to Article II), or (C) make or bring (or participate in, other than as a passive participant in or recipient of its pro rata benefits of) any claim, in its capacity as a Lender, against the Administrative Agent or any other Lender with respect to any duties or obligations or alleged duties or obligations of such Agent or any other such Lender under the Credit Documents;

(ii)       except with respect to any amendment, modification, waiver, consent or other action described in clause (i) of the second proviso of the second sentence of Section 13.1(a) or that alters an Affiliated Lender’s pro rata share of any payments given to all Lenders, the Loans held by an Affiliated Lender shall be disregarded in both the numerator and denominator in the calculation of any Lender vote (and shall be deemed to have been voted in the same percentage as all other applicable Lenders that are not Affiliated Lenders voted if necessary to give legal effect to this paragraph) under any Credit Document;

(iii)      the aggregate principal amount of Loans held at any one time by Affiliated Lenders may not exceed 30% of the aggregate principal amount of all Loans outstanding at such time under this Agreement; and

(iv)       no Loan proceeds shall be used by such Affiliated Lender to purchase such Loans.

​ 141

​ Section 13.7    Replacements of Lenders under Certain Circumstances .

(a)        The Borrower shall be permitted to replace any Lender that becomes a Defaulting Lender, with a replacement bank, lending institution or other financial institution; provided that (A) such replacement does not conflict with any Requirement of Law, (B) no Event of Default under Section 11.1 or 11.5 shall have occurred and be continuing at the time of such replacement, (C) the replacement bank or institution shall purchase, at par, all Loans and the Borrower shall pay all other amounts (other than any disputed amounts), pursuant to Section 2.9, 3.5 or 5.4, as the case may be) owing to such replaced Lender prior to the date of replacement, (D) the replacement bank or institution, if not already a Lender, and the terms and conditions of such replacement, shall be reasonably satisfactory to the Administrative Agent, (E) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 13.6(b) (provided that the Borrower shall be obligated to pay the registration and processing fee referred to therein) and (F) any such replacement shall not be deemed to be a waiver of any rights that the Borrower, the Administrative Agent or any other Lender shall have against the replaced Lender.

(b)        If any Lender (such Lender, a “Non-Consenting Lender”) (x) has failed to consent to a proposed amendment, determination, waiver, discharge or termination that pursuant to the terms of Section 13.1 requires the consent of all of the Lenders affected and with respect to which the Majority Lenders shall have granted their consent or (y) did not consent to increase the Borrowing Base then in effect when the Required Lenders provided their consent to such increase pursuant to Sections 2.15 or 2.16,, then, in each case, provided no Event of Default then exists, the Borrower shall have the right (unless such Non-Consenting Lender grants such consent) to replace such Non-Consenting Lender by requiring such Non-Consenting Lender to assign its Loans and its Commitments hereunder to one or more assignees reasonably acceptable to the Administrative Agent; provided that: (i) all Obligations of the Borrower owing to such Non-Consenting Lender being replaced (other than principal and interest) shall be paid in full to such Non-Consenting Lender concurrently with such assignment, and (ii) the replacement Lender shall purchase the foregoing by paying to such Non-Consenting Lender a price equal to the principal amount thereof plus accrued and unpaid interest thereon. In connection with any such assignment, the Borrower, Administrative Agent, such Non-Consenting Lender and the replacement Lender shall otherwise comply with Section 13.6.

(c)        Notwithstanding anything herein to the contrary, each party hereto agrees that any assignment pursuant to the terms of this Section 13.7 may be effected pursuant to an Assignment and Acceptance executed by the Borrower, the Administrative Agent and the assignee and that the Lender making such assignment need not be a party thereto.

Section 13.8    Adjustments; Set-off .

(a)        If any Lender (a “Benefited Lender”) shall at any time receive any payment in respect of any principal of or interest on all or part of the Loans made by it, or the participations in Letter of Credit Obligations held by it, or receive any collateral in respect thereof (whether voluntarily or involuntarily, by set-off, pursuant to events or proceedings

​ 142

​ of the nature referred to in Section 11.5, or otherwise), in a greater proportion than any such payment to or collateral received by any other Lender entitled thereto, if any, in respect of such other Lender’s Loans, or interest thereon, such Benefited Lender shall (i) notify the Administrative Agent of such fact, and (ii) purchase for cash at face value from the other Lenders a participating interest in such portion of each such other Lender’s Loans, or shall provide such other Lenders with the benefits of any such collateral, or the proceeds thereof, as shall be necessary to cause such Benefited Lender to share the excess payment or benefits of such collateral or proceeds ratably in accordance with the aggregate principal of and accrued interest on their respective Loans and other amounts owing them; provided, however, that (A) if all or any portion of such excess payment or benefits is thereafter recovered from such Benefited Lender, such purchase shall be rescinded, and the purchase price and benefits returned, to the extent of such recovery, but without interest and (B) the provisions of this paragraph shall not be construed to apply to (1) any payment made by the Borrower or any other Credit Party pursuant to and in accordance with the terms of this Agreement and the other Credit Documents or (2) any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans, Commitments or participations in Drawings to any assignee or participant. Each Credit Party consents to the foregoing and agrees, to the extent it may effectively do so under Requirements of Law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against such Credit Party rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of such Credit Party in the amount of such participation.

(b)        After the occurrence and during the continuance of an Event of Default, in addition to any rights and remedies of the Lenders provided by Requirements of Law, each Lender shall have the right, without prior notice to the Borrower, any such notice being expressly waived by the Borrower to the extent permitted by applicable Requirements of Law, upon any amount becoming due and payable by the Borrower hereunder or under any Credit Document (whether at the stated maturity, by acceleration or otherwise) to set-off and appropriate and apply against such amount any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Lender or any branch or agency thereof to or for the credit or the account of the Borrower. Each Lender agrees promptly to notify the Borrower (and the Credit Parties, if applicable) and the Administrative Agent after any such set-off and application made by such Lender; provided that the failure to give such notice shall not affect the validity of such set-off and application.

Section 13.9    Counterparts.  This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts (including by facsimile or other electronic transmission, i.e. a “pdf” or a “tif”), and all of said counterparts taken together shall be deemed to constitute one and the same instrument. A set of the copies of this Agreement signed by all the parties shall be lodged with the Borrower and the Administrative Agent.  Delivery of an executed counterpart of a signature page of this Agreement, any other Credit Document and/or any document, amendment, approval, consent, information, notice (including, for the avoidance of doubt, any notice delivered pursuant to Section 13.2), certificate, request, statement, disclosure or authorization related to this Agreement, any other Credit Document and/or the transactions

​ 143

​ contemplated hereby and/or thereby (each an “Ancillary Document”) that is an Electronic Signature transmitted by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page shall be effective as delivery of a manually executed counterpart of this Agreement, such other Credit Document or such Ancillary Document, as applicable.  The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to this Agreement, any other Credit Document and/or any Ancillary Document shall be deemed to include Electronic Signatures, deliveries or the keeping of records in any electronic form (including deliveries by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page), each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be; provided that nothing herein shall require the Administrative Agent to accept Electronic Signatures in any form or format without its prior written consent and pursuant to procedures approved by it; provided, further, without limiting the foregoing, (i) to the extent the Administrative Agent has agreed to accept any Electronic Signature, the Administrative Agent and each of the Lenders shall be entitled to rely on such Electronic Signature purportedly given by or on behalf of the Borrower or any other Loan Party without further verification thereof and without any obligation to review the appearance or form of any such Electronic signature and (ii) upon the request of the Administrative Agent or any Lender, any Electronic Signature shall be promptly followed by a manually executed counterpart.  Without limiting the generality of the foregoing, the Borrower and each Loan Party hereby (i) agrees that, for all purposes, including without limitation, in connection with any workout, restructuring, enforcement of remedies, bankruptcy proceedings or litigation among the Administrative Agent, the Lenders, the Borrower and the Loan Parties, Electronic Signatures transmitted by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page and/or any electronic images of this Agreement, any other Credit Document and/or any Ancillary Document shall have the same legal effect, validity and enforceability as any paper original, (ii) the Administrative Agent and  each of the Lenders may, at its option, create one or more copies of this Agreement, any other Credit Document and/or any Ancillary Document in the form of an imaged electronic record in any format, which shall be deemed created in the ordinary course of such Person’s business, and destroy the original paper document (and all such electronic records shall be considered an original for all purposes and shall have the same legal effect, validity and enforceability as a paper record), (iii) waives any argument, defense or right to contest the legal effect, validity or enforceability of this Agreement, any other Credit Document and/or any Ancillary Document based solely on the lack of paper original copies of this Agreement, such other Credit Document and/or such Ancillary Document, respectively, including with respect to any signature pages thereto and (iv) waives any claim against any Lender-Related Person for any Liabilities arising solely from the Administrative Agent’s and/or any Lender’s reliance on or use of Electronic Signatures and/or transmissions by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page, including any Liabilities arising as a result of the failure of the Borrower and/or any Loan Party to use any available security measures in connection with the execution, delivery or transmission of any Electronic Signature.

Section 13.10  Severability.  Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

​ 144

​ Section 13.11  Integration.  This Agreement and the other Credit Documents represent the agreement of the Borrower, the Guarantors, the Administrative Agent and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Borrower, the Guarantors, the Administrative Agent nor any Lender relative to subject matter hereof not expressly set forth or referred to herein or in the other Credit Documents.

Section 13.12  GOVERNING LAW.  THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF TEXAS.

Section 13.13 Submission to Jurisdiction; Waivers.  Each party hereto hereby irrevocably and unconditionally:

(a)        submits for itself and its property in any legal action or proceeding relating to this Agreement and the other Credit Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the exclusive general jurisdiction of the courts of the State of Texas and the courts of the United States for the Northern District of Texas, in each case located in Tarrant County, and appellate courts from any thereof;

(b)        consents that any such action or proceeding shall be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

(c)        agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to such Person at its address set forth on Schedule 13.2 at such other address of which the Administrative Agent shall have been notified pursuant to Section 13.2;

(d)        agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by Requirements of Law or shall limit the right to sue in any other jurisdiction;

(e)        waives, to the maximum extent not prohibited by law, any right it may have to claim or recover in any legal action or proceeding referred to in this Section 13.13 any special, exemplary, punitive or consequential damages; and

(f)        agrees that a final judgment in any action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law.

Section 13.14  Acknowledgments.  The Borrower hereby acknowledges that:

​ 145

​ (a)        it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Credit Documents;

(b)        (i) the Facility provided for hereunder and any related arranging or other services in connection therewith (including in connection with any amendment, waiver or other modification hereof or of any other Credit Document) are an arm’s-length commercial transaction between the Borrower and the other Credit Parties, on the one hand, and the Administrative Agent and the Lenders on the other hand, and the Borrower and the other Credit Parties are capable of evaluating and understanding and understand and accept the terms, risks and conditions of the transactions contemplated hereby and by the other Credit Documents (including any amendment, waiver or other modification hereof or thereof); (ii) in connection with the process leading to such transaction, each of the Administrative Agent and the Lenders is and has been acting solely as a principal and is not the financial advisor, agent or fiduciary for any of the Borrower, any other Credit Parties or any of their respective Affiliates, equity holders, creditors or employees or any other Person; none of the Administrative Agent, the Lead Arranger, the  Syndication Agent, any of the Joint Lead Arrangers  or any Co-Documentation Agent nor any Lender has assumed or will assume an advisory, agency or fiduciary responsibility in favor of the Borrower or any other Credit Party with respect to any of the transactions contemplated hereby or the process leading thereto, including with respect to any amendment, waiver or other modification hereof or of any other Credit Document (irrespective of whether the Administrative Agent, the Lead Arranger, the Syndication Agent, the Joint Lead Arrangers, any Co-Documentation Agent or any Lender has advised or is currently advising any of the Borrower, the other Credit Parties or their respective Affiliates on other matters) and none of the Administrative Agent, the Lead Arranger, the Syndication Agent, any Co-Documentation Agent, any Joint Lead Arranger or any Lender has any obligation to any of the Borrower, the other Credit Parties or their respective Affiliates with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Credit Documents; (iii) the Administrative Agent and its Affiliates, and each Lender and its Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its respective Affiliates, and none of the Administrative Agent or any Lender has any obligation to disclose any of such interests by virtue of any advisory, agency or fiduciary relationship; and (iv) none of the Administrative Agent or any Lender has provided and none will provide any legal, accounting, regulatory or tax advice with respect to any of the transactions contemplated hereby (including any amendment, waiver or other modification hereof or of any other Credit Document) and the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate. The Borrower hereby waives and releases, to the fullest extent permitted by law, any claims that it may have against the Administrative Agent with respect to any breach or alleged breach of agency or fiduciary duty; and

(c)        no joint venture is created hereby or by the other Credit Documents or otherwise exists by virtue of the transactions contemplated hereby among the Lenders or among the Borrower, on the one hand, and any Lender, on the other hand.

​ 146

​ Section 13.15   WAIVERS OF JURY TRIAL.  THE BORROWER, THE ADMINISTRATIVE AGENT, EACH ISSUING BANK AND EACH LENDER HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER CREDIT DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN.

Section 13.16   Confidentiality.  The Administrative Agent, any Issuing Bank and each other Lender shall hold all information not marked as “public information” and furnished by or on behalf of the Borrower or any of its Subsidiaries or Affiliates in connection with such Lender’s evaluation of whether to become a Lender hereunder or obtained by such Lender, the Administrative Agent or any Issuing Bank pursuant to the requirements of this Agreement (“Confidential Information”), confidential in accordance with its customary procedure for handling confidential information of this nature and in any event may make disclosure (i) as required or requested by any Governmental Authority, self-regulatory agency or representative thereof or pursuant to legal process or applicable Requirements of Law, (ii) to such Lender’s or the Administrative Agent’s, any Issuing Bank’s attorneys, professional advisors, independent auditors, trustees, agents or Affiliates (and any Affiliate’s attorneys, professional advisors, independent auditors, trustees or agents), in each case who need to know such information in connection with the administration of the Credit Documents and are informed of the confidential nature of such information, (iii) to an investor or prospective investor in a securitization that agrees its access to information regarding the Credit Parties, the Loans and the Credit Documents is solely for purposes of evaluating an investment in a securitization and who agrees to treat such information as confidential, or to another Lender (iv) to a trustee, collateral manager, servicer, backup servicer, noteholder or secured party in connection with the administration, servicing and reporting on the assets serving as collateral for a securitization and who agrees to treat such information as confidential, (v) to a nationally recognized ratings agency that requires access to information regarding the Credit Parties, the Loans and Credit Documents in connection with ratings issued with respect to a securitization, and (vi) to the extent such Confidential Information becomes public other than by reason of disclosure by such Person in breach of this Agreement; provided that unless specifically prohibited by applicable Requirements of Law, each Lender, the Administrative Agent, any Issuing Bank shall endeavor to notify the Borrower (without any liability for a failure to so notify the Borrower) of any request made to such Lender, the Administrative Agent or any Issuing Bank, as applicable, by any governmental, regulatory or self-regulatory agency or representative thereof (other than any such request in connection with an examination of the financial condition of such Lender by such governmental agency) for disclosure of any such non-public information prior to disclosure of such information; provided further that in no event shall any Lender, the Administrative Agent or any Issuing Bank be obligated or required to return any materials furnished by the Borrower or any Subsidiary. In addition, each Lender and the Administrative Agent may provide Confidential Information to prospective Transferees or to any pledgee referred to in Section 13.6 or to prospective direct or indirect contractual counterparties in Hedge Transactions to be entered into in connection with Loans made hereunder as long as such Person is advised of and agrees to be bound by the provisions of this Section 13.16 or confidentiality provisions at least as restrictive as those set forth in this Section 13.16.

​ 147

​ Section 13.17  Release of Collateral and Guarantee Obligations .

(a)        The Lenders hereby irrevocably agree that the Liens granted to the Administrative Agent by the Credit Parties on any Collateral shall be automatically released (i) in full, as set forth in clause (b) below, (ii) upon the Disposition of such Collateral (including as part of or in connection with any other Disposition permitted hereunder) to any Person other than another Credit Party, to the extent such Disposition is made in compliance with the terms of this Agreement (and the Administrative Agent may rely conclusively on a certificate to that effect provided to it by any Credit Party upon its reasonable request without further inquiry), (iii) to the extent such Collateral is comprised of property leased to a Credit Party, upon termination or expiration of such lease, (iv) if the release of such Lien is approved, authorized or ratified in writing by the Majority Lenders (or such other percentage of the Lenders whose consent may be required in accordance with Section 13.1), (v) to the extent the property constituting such Collateral is owned by any Guarantor, upon the release of such Guarantor from its obligations under the Guarantee, (vi) upon the designation of any Restricted Subsidiary as an Unrestricted Subsidiary in accordance with the terms of this Agreement, and (vii) as required by the Administrative Agent to effect any Disposition of Collateral in connection with any exercise of remedies of the Administrative Agent pursuant to the Security Documents. Any such release shall not in any manner discharge, affect or impair the Obligations or any Liens (other than those being released) upon (or obligations (other than those being released) of the Credit Parties in respect of) all interests retained by the Credit Parties, including the proceeds of any Disposition, all of which shall continue to constitute part of the Collateral except to the extent otherwise released in accordance with the provisions of the Credit Documents. The Lenders hereby authorize the Administrative Agent to execute and deliver any instruments, documents and agreements necessary or desirable to evidence and confirm the release of any Collateral pursuant to the foregoing provisions of this paragraph, all without the further consent or joinder of any Lender. In connection with any release hereunder, the Administrative Agent shall promptly (and the Lenders hereby authorize the Administrative Agent to) take such action and execute any such documents as may be reasonably requested by the Borrower and at the Borrower’s expense in connection with the release of any Liens created by any Credit Document.

(b)        Notwithstanding anything to the contrary contained herein or any other Credit Document, when all Obligations (other than Hedging Obligations, Cash Management Obligations or contingent indemnification obligations not then due and payable) have been paid in full in cash or equivalents thereof, the Commitments have terminated and the Letters of Credit have terminated (unless such Letters of Credit have been collateralized or other arrangements in respect thereof have been made on terms and conditions reasonably satisfactory to each applicable Issuing Bank following the termination of the Commitments), upon request of the Borrower, the Administrative Agent shall (without notice to, or vote or consent of, any Secured Party) take such actions as shall be required to release its security interest in all Collateral, and to release all obligations under any Credit Document. Any such release of Obligations shall be deemed subject to the provision that such Obligations shall be reinstated if after such release any portion of any payment in respect of the Obligations guaranteed thereby shall be rescinded or must otherwise be restored or returned upon the insolvency, bankruptcy, dissolution, liquidation

​ 148

​ or reorganization of the Borrower or any Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Borrower or any Guarantor or any substantial part of its property, or otherwise, all as though such payment had not been made.

Section 13.18  USA PATRIOT Act.  The Administrative Agent and each Lender hereby notify the Borrower that pursuant to the requirements of the USA PATRIOT Act (Title III of Pub. L. 107¬56 (signed into law October 26, 2001)) (the “Patriot Act”) it is required to obtain, verify and record information that identifies each Credit Party, which information includes the name and address of each Credit Party and other information that will allow the Administrative Agent and such Lender to identify each Credit Party in accordance with the Patriot Act.

Section 13.19  Payments Set Aside.  To the extent that any payment by or on behalf of the Borrower is made to the Administrative Agent or any Lender, or the Administrative Agent or any Lender exercises its right of setoff, and such payment or the proceeds of such setoff or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required (including pursuant to any settlement entered into by the Administrative Agent or such Lender in its discretion) to be repaid to a trustee, receiver or any other party, in connection with any proceeding or otherwise, then (i) to the extent of such recovery, the obligation or part thereof originally intended to be satisfied shall be revived and continued in full force and effect as if such payment had not been made or such setoff had not occurred, and (ii) each Lender severally agrees to pay to the Administrative Agent upon demand its applicable share of any amount so recovered from or repaid by the Administrative Agent, plus interest thereon from the date of such demand to the date such payment is made at a rate per annum equal to the applicable Overnight Rate from time to time in effect.

Section 13.20   Reinstatement.  This Agreement shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Obligations is rescinded or must otherwise be restored or returned by the Administrative Agent or any other Secured Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Borrower, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Borrower or any substantial part of its property, or otherwise, all as though such payments had not been made.

Section 13.21   Disposition of Proceeds.  The Security Documents contain an assignment by the Borrower and/or the Guarantors unto and in favor of the Administrative Agent for the benefit of the Lenders of all of the Borrower’s or each Guarantor’s interest in and to their as-extracted collateral in the form of production and all proceeds attributable thereto which may be produced from or allocated to the Mortgaged Property. The Security Documents further provide in general for the application of such proceeds to the satisfaction of the Obligations described therein and secured thereby. Notwithstanding the assignment contained in such Security Documents, until the occurrence of an Event of Default, (i) the Administrative Agent and the Lenders agree that they will neither notify the purchaser or purchasers of such production nor take any other action to cause such proceeds to be remitted to the Administrative Agent or the Lenders, but the Lenders will instead permit such proceeds to be paid to the Borrower and its Restricted Subsidiaries and (ii) the Lenders hereby authorize the Administrative Agent to take such actions

​ 149

​ as may be necessary to cause such proceeds to be paid to the Borrower and/or such Restricted Subsidiaries.

Section 13.22  Collateral Matters; Hedge Transactions.  The benefit of the Security Documents and of the provisions of this Agreement relating to any Collateral securing the Obligations shall also extend to and be available on a pro rata basis pursuant to terms agreed upon in the Credit Documents to (i) any Hedge Bank or (ii) any Cash Management Bank. No Person shall have any voting rights under any Credit Document solely as a result of the existence of obligations owed to it under or in respect of any such Hedge Transaction or Cash Management Agreement.

Section 13.23  Agency of the Borrower for the Other Credit Parties.  Each of the other Credit Parties hereby appoints the Borrower as its agent for all purposes relevant to this Agreement and the other Credit Documents, including the giving and receipt of notices and the execution and delivery of all documents, instruments and certificates contemplated herein and therein and all modifications hereto and thereto.

Section 13.24 Acknowledgement and Consent to Bail-In of Affected Financial Institutions.  Notwithstanding anything to the contrary in any Credit Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Affected Financial Institution arising under any Credit Document, to the extent such liability is unsecured, may be subject to the Write-Down and Conversion Powers of the applicable Affected Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)        the application of any Write-Down and Conversion Powers by the applicable Affected Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an Affected Financial Institution; and

(b)        the effects of any Bail-in Action on any such liability, including, if applicable:

(i)         a reduction in full or in part or cancellation of any such liability;

(ii)       a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Credit Document; or

(iii)      The variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any applicable Affected Resolution Authority.

​ 150

​ Section 13.25  Acknowledgement Regarding Any Supported QFCs.

To the extent that the Credit Documents provide support, through a guarantee or otherwise, for any Hedge Agreement or any other agreement or instrument that is a QFC (such support, “QFC Credit Support”, and each such QFC, a “Supported QFC”), the parties acknowledge and agree as follows with respect to the resolution power of the Federal Deposit Insurance Corporation under the Federal Deposit Insurance Act and Title II of the Dodd-Frank Wall Street Reform and Consumer Protection Act (together with the regulations promulgated thereunder, the “U.S. Special Resolution Regimes”) in respect of such Supported QFC and QFC Credit Support (with the provisions below applicable notwithstanding that the Credit Documents and any Supported QFC may in fact be stated to be governed by the laws of the State of New York and/or of the United States or any other state of the United States):

(a)        In the event a Covered Entity that is party to a Supported QFC (each, a “Covered Party”) becomes subject to a proceeding under a U.S. Special Resolution Regime, the transfer of such Supported QFC and the benefit of such QFC Credit Support (and any interest and obligation in or under such Supported QFC and such QFC Credit Support, and any rights in property securing such Supported QFC or such QFC Credit Support) from such Covered Party will be effective to the same extent as the transfer would be effective under the U.S. Special Resolution Regime if the Supported QFC and such QFC Credit Support (and any such interest, obligation and rights in property) were governed by the laws of the United States or a state of the United States. In the event a Covered Party or a BHC Act Affiliate of a Covered Party becomes subject to a proceeding under a U.S. Special Resolution Regime, Default Rights under the Credit Documents that might otherwise apply to such Supported QFC or any QFC Credit Support that may be exercised against such Covered Party are permitted to be exercised to no greater extent than such Default Rights could be exercised under the U.S. Special Resolution Regime if the Supported QFC and the Credit Documents were governed by the laws of the United States or a state of the United States. Without limitation of the foregoing, it is understood and agreed that rights and remedies of the parties with respect to a Defaulting Lender shall in no event affect the rights of any Covered Party with respect to a Supported QFC or any QFC Credit Support.

(b)        As used in this Section 13.25, the following terms have the following meanings: “BHC Act Affiliate” of a party means an “affiliate” (as such term is defined under, and interpreted in accordance with, 12 U.S.C. 1841(k)) of such party.  “Covered Entity” means any of the following: (i) a “covered entity” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 252.82(b); (ii) a “covered bank” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 47.3(b); or (iii) a “covered FSI” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 382.2(b).  “Default Right” has the meaning assigned to that term in, and shall be interpreted in accordance with, 12 C.F.R. §§ 252.81, 47.2 or 382.1, as applicable.  “QFC” has the meaning assigned to the term “qualified financial contract” in, and shall be interpreted in accordance with, 12 U.S.C. 5390(c)(8)(D).

Section 13.26   Amendment.  The Borrower, the Administrative Agent, the Issuing Banks and the Lenders have agreed that this Agreement is an amendment of the Existing Credit

​ 151

​ Agreement, that the terms and provisions hereof supersede the terms and provisions of the Existing Credit Agreement, and that this Agreement is not a new or substitute credit agreement or novation of the Existing Credit Agreement.  The Obligations of Borrower and the other Loan Parties evidenced under this Agreement and the other Credit Documents are given in renewal, extension and modification, but not in extinguishment, novation or discharge, of the “Obligations” under and as defined in the Existing Credit Agreement. From and after the Amendment No. 2 Effective Date, (i) all references to the Existing Credit Agreement (or to any amendment, supplement, modification or amendment and restatement thereof) in the Credit Documents (other than this Agreement) shall be deemed to refer to the Existing Credit Agreement as amended hereby and (ii) all references to any section (or subsection) of the Existing Credit Agreement in any Credit Document (other than this Agreement) shall be amended to be references to the corresponding provisions of this Agreement.

[Signature Pages Follow]

​ 152

​ IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of this Agreement to be duly executed and delivered as of the date first above written.

​	​	​	​
​	BORROWER:
​	​	​	​
​	KIMBELL ROYALTY PARTNERS, LP,<br>a Delaware limited partnership
​	​	​	​
​	​	​	​
​	By:	Kimbell Royalty GP, LLC, a Delaware limited liability company, its general partner
​	​	​
​	​	​	​
​	​	By:	​
​	​	​	Matthew S. Daly,
​	​	​	Chief Operating Officer and Secretary

​

​

​ [Signature Page to Credit Agreement]

​ ​

​	ADMINISTRATIVE AGENT :
​	​	​	​
​	CITIBANK, N.A., as a Lender, Administrative Agent, Issuing Bank, Lead Arranger and Syndication Agent
​	​	​	​
​	By:	​
​	​	Name: Jeff Ard
​	​	Title: Vice President

​

​

​ [Signature Page to Credit Agreement]

​ EXHIBIT A

FORM OF NOTICE OF BORROWING

​

​ Exhibit A

​ EXHIBIT “B” TO CREDIT AGREEMENT FORM OF GUARANTEE

​

​ Exhibit B

​ EXHIBIT C

​

FORM OF REVOLVING PROMISSORY NOTE

​

​ Exhibit C

​ EXHIBIT D

FORM OF COMPLIANCE CERTIFICATE

​

​ Exhibit D

​ EXHIBIT E

FORM OF ASSIGNMENT

AND ASSUMPTION

​

​ Exhibit E

​ EXHIBIT F-1

FORM OF U.S. TAX

COMPLIANCE CERTIFICATE

​

​ Exhibit F-1

​ EXHIBIT F-2

FORM OF U.S. TAX

COMPLIANCE CERTIFICATE

​

​ Exhibit F-2

​ EXHIBIT F-3

FORM OF U.S. TAX

COMPLIANCE CERTIFICATE

​

​ Exhibit F-3

​ EXHIBIT F-4

FORM OF U.S. TAX

COMPLIANCE CERTIFICATE

​

​ Exhibit F-4

​ EXHIBIT G-1

FORM OF ELECTED COMMITMENT INCREASE CERTIFICATE

​

​ Exhibit G-1

​ EXHIBIT G-2

FORM OF ADDITIONAL LENDER CERTIFICATE

​

​ Exhibit G-2

​ EXHIBIT H

FORM OF INTERCOMPANY NOTE

​

​ Exhibit H

​ Schedule 1(a)

​

​ Schedule 1(a)

​ Schedule 8.4

​

Litigation

​

​ Schedule 8.4 to Credit Agreement

​ Schedule 8.9

​

Financial Disclosures

​

​ Schedule 8.9 to Credit Agreement

​ Schedule 8.12

​

Subsidiaries

​

​ Schedule 8.12 to Credit Agreement

​ Schedule 8.18

Amendment No. 2 Effective Date Hedge Transactions

​

​ Schedule 8.18 to Credit Agreement

​ Schedule 8.23

Amendment No. 2 Effective Date Accounts

​

​ Schedule 8.23 to Credit Agreement

​ Schedule 10.15

Investments

​

​ Schedule 10.15 to Credit Agreement

​ Schedule 13.2

Notice Addresses and Commitments

(a)        Lenders’ Commitment

​	​	​	​
Lender	Maximum Facility<br>Amount	Commitment /<br>Elected Commitment	Commitment<br>Percentage
Citibank, N.A.	$68,000,000	$36,000,000	13.6%
BBVA USA	$68,000,000	$36,000,000	13.6%
Frost Bank	$68,000,000	$36,000,000	13.6%
Truist Bank	$68,000,000	$36,000,000	13.6%
Credit Suisse AG, Cayman Islands Branch	$40,500,000	$21,500,000	8.1%
JPMorgan Chase Bank, N.A.	$40,500,000	$21,500,000	8.1%
KeyBank, N.A.	$40,500,000	$21,500,000	8.1%
Royal Bank of Canada	$40,500,000	$21,500,000	8.1%
Independent Financial	$37,500,000	$20,000,000	7.5%
UMB Bank, N.A.	$28,500,000	$15,000,000	5.7%
Total Commitment / Aggregate Elected Commitment Amount:	$500,000,000	$265,000,000	100.0%

​

​ Schedule 13.2 to Credit Agreement

​ (b)        Administrative Agent’s and Lenders’ Addresses

​	​	​
Lender	Lending Office	Address for Notice
Citibank, N.A. and Administrative Agent	Citibank, N.A., as Administrative<br><br>One Penn’s Way<br><br>OPS II<br><br>New Castle, DE 19720<br><br>Attn: Agency Operations<br><br>Phone: (302) 894-6010<br><br>Fax: (646) 274-5080<br><br>Borrower inquiries only: AgencyABTFSupport@citi.com<br><br>Borrower notifications: GlAgentOfficeOps@Citi.com<br><br>​<br><br>with a copy to:<br>Citibank, N.A.<br>811 Main Street<br><br>Suite 4000<br><br>Houston, TX 77002<br><br>Attn: Jeff Ard<br><br>Email: Jeff.ard@Citi.com<br><br>​	Citibank, N.A<br><br>811 Main Street<br><br>Suite 4000<br><br>Houston, TX 77002<br><br>Attention: Jeff Ard<br>Email: Jeff.ard@Citi.com<br><br>​<br><br>with a copy to:<br><br>​<br><br>Citibank, N.A.<br><br>811 Main Street<br><br>Suite 4000<br><br>Houston, TX 77002<br><br>Attention: Garrison Reeves<br><br>Email: garrison.reeves@citi.com<br><br>​
BBVA USA	BBVA<br><br>2200 Post Oak Blvd., 17^th^ Floor<br><br>Houston, Texas 77056<br><br>​	Business/Credit:<br><br>​<br><br>BBVA<br><br>2200 Post Oak Blvd., 17^th^ Floor<br><br>Houston, Texas 77056<br><br>Attn: Daniel Ferreyra<br><br>Phone No.: (713) 993-8584<br><br>Email: Daniel.ferreyra@bbva.com<br><br>​<br><br>with a copy to:<br><br>​<br><br>2200 Post Oak Blvd., 17^th^ Floor<br><br>Houston, Texas 77056<br><br>Attn: Zack Wildermuth<br><br>Phone No.: (281) 734-8566<br><br>Email: Zach.wildermuth@bbva.com<br><br>​

​

​ Schedule 13.2 to Credit Agreement

​ ​

​	​	Admin/Operations:<br><br>​<br><br>BBVA<br><br>2200 Post Oak Blvd., 21^st^ Floor<br><br>Houston, Texas 77056<br><br>Attn: Eric Martin<br><br>Phone No.: (713) 881-0639<br><br>Fax No.: (866) 327-4936<br><br>Email: Ldfcenergyoil&gas.us@bbva.com<br><br>​<br><br>with a copy to:<br><br>​<br><br>BBVA<br><br>2200 Post Oak Blvd., 21^st^ Floor<br><br>Houston, Texas 77056<br><br>Attn: Sandra Vega<br><br>Phone No.: (713) 993-8502<br><br>Fax No.: (866) 327-4936<br><br>Email: Ldfcenergyoil&gas.us@bbva.com<br><br>​
Credit Suisse AG, Cayman Islands Branch	Credit Suisse AG,<br><br>Cayman Islands Branch<br><br>Eleven Madison Avenue<br><br>New York, New York 10010<br><br>Phone No.: (212) 538-4044<br><br>Fax No.: (212) 325-8615	Credit:<br><br>​<br><br>Credit Suisse AG,<br><br>Cayman Islands Branch<br><br>Eleven Madison Avenue<br><br>New York, New York 10010<br><br>Attention: Nupur Kumar<br><br>Phone No.: (212) 538-4044<br><br>Fax No.: (212) 325-8615<br><br>E-Mail: nupur.kumar@credit-suisse.com<br><br>​<br><br>with a copy to:<br><br>​<br><br>Credit Suisse AG,<br><br>Cayman Islands Branch<br><br>Eleven Madison Avenue<br><br>New York, New York 10010<br><br>Attention: Christopher Zybrick<br><br>Phone No.: (212) 325-7703<br><br>E-Mail: christopher.zybrick@credit-suisse.com<br><br>​<br><br>​

​

​ Schedule 13.2 to Credit Agreement

​ ​

​	​	​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​
​	​	Deal Administrator:<br><br>​<br><br>Credit Suisse AG,<br><br>Cayman Islands Branch<br><br>Eleven Madison Avenue<br><br>New York, New York 10010<br><br>Attention: DA<br><br>Phone No.: (919) 994-6174<br><br>Fax No.: (866) 469-3871<br><br>E-Mail: 18664693871@docs.LDSPROD.com<br><br>​<br><br>with a copy to:<br><br>​<br><br>Credit Suisse AG,<br><br>Cayman Islands Branch<br><br>Eleven Madison Avenue<br><br>New York, New York 10010<br><br>Attention: Corporate Bank Participations<br><br>Fax No.: (866) 469-3871<br><br>E-Mail: 18664693871@docs.LDSPROD.com<br><br>Financial Info/Compliance:<br><br>​<br><br>Credit Suisse AG,<br><br>Cayman Islands Branch<br><br>7033 Louis Stephens Drive<br><br>Research Triangle Park, NC 27560<br><br>Attention: Sarah Bennett<br><br>Phone No.: (919) 994-1648<br><br>E-Mail: sarah.bennett@credit-suisse.com<br><br>​
Frost Bank	Frost Bank<br><br>640 Taylor Street<br><br>Fort Worth, Texas 76102<br><br>Attention: Alex Zemkoski<br><br>​	Frost Bank<br><br>640 Taylor Street<br><br>Fort Worth, Texas 76102<br><br>Attention: Alex Zemkoski<br><br>Fax No. (817) 420-5090<br><br>Email: alex.zemkoski@frostbank.com<br><br>​<br><br>with a copy to:<br><br>Frost Bank<br><br>100 West Houston Street, RB-2<br><br>San Antonio, Texas 78205<br><br>Fax No. (210) 220-4258<br><br>​

​

​ Schedule 13.2 to Credit Agreement

​ ​

Independent Financial	Independent Financial<br><br>1300 S. University Drive, Suite 100<br><br>Fort Worth, Texas 76107<br><br>​	Business/Credit:<br><br>Independent Financial<br><br>1300 S. University Drive, Suite 100<br><br>Fort Worth, Texas 76107<br><br>Attention: Alex Zemkoski<br><br>Phone No.: (844) 426.7918<br><br>Fax No.: (817) 870-1725<br><br>E-Mail: AZemkoski@ibtx.com<br><br>​<br><br>with a copy to:<br><br>Independent Financial<br><br>1300 S. University Drive, Suite 100<br><br>Fort Worth, Texas 76107<br><br>Attention: Philip Mortimer<br><br>Phone No.: (817) 426-7976<br><br>Fax No.: (817) 870-1725<br><br>E-Mail: PMortimer@ibtx.com<br><br>Admin/Operations:<br><br>Independent Financial<br><br>1600 Redbud Blvd.<br><br>McKinney, Texas 75070<br><br>Attention: Special Servicing<br><br>Phone No.: (844) 767-3774<br><br>Fax No.: (469) 301-2600<br><br>E-Mail: SpecialServicing@ibtx.com<br><br>​<br><br>with a copy to:<br><br>Independent Financial<br><br>1600 Redbud Blvd.<br><br>McKinney, Texas 75070<br><br>Attention: Loan Ops<br><br>Phone No.: (844) 767-3774<br><br>Fax No.: (469) 301-2600<br><br>E-Mail: LoanOps@ibtx.com
JPMorgan Chase Bank, N.A.	JPMorgan Chase Bank, N.A.<br><br>712 Main Street, Floor 5<br><br>Houston, Texas 77002	Business/Credit:<br><br>JPMorgan Chase Bank, N.A.<br><br>712 Main Street, Floor 5

​

​ Schedule 13.2 to Credit Agreement

​ ​

​	​	Houston, Texas 77002<br><br>Attention: Carly Lim<br><br>Phone No.: (713) 216-3270<br><br>Fax No.: (713) 216-7770<br><br>E-Mail: Carly.l.lim@chase.com<br><br>​<br><br>with a copy to:<br><br>JPMorgan Chase Bank, N.A.<br><br>712 Main Street, Floor 5<br><br>Houston, Texas 77002<br><br>Attention: Jacqueline Johnson<br><br>Phone No.: (713) 216-7726<br><br>Fax No.: (713) 216-7770<br><br>E-Mail: Jacqueline.d.johnson@chase.com<br><br>Admin/Operations:<br><br>JPMorgan Chase Bank, N.A.<br><br>10 South Dearborn L2<br><br>Chicago, Illinois 60603<br><br>Attention: CLS Non Agented Servicing Team (Rajesh Gadige)<br><br>Phone No.: +91 (806) 790-5009<br><br>E-Mail: cls.chicago.non.agented.servicing@jpmchase.com<br><br>​
KeyBank, N.A.	KeyBank, N.A.<br><br>600 Travis Street<br><br>Houston, Texas 77002<br><br>​	Business/Credit:<br><br>KeyBank, N.A.<br><br>600 Travis Street<br><br>Houston, Texas 77002<br><br>Attention: Benjamin Brollier<br><br>Phone No.: (713) 221-6193<br><br>E-Mail: Benjamin.Brollier@key.com<br><br>Admin/Operations:<br><br>KeyBank, N.A.<br><br>600 Travis Street<br><br>Houston, Texas 77002<br><br>Attention: Key Agency Services<br><br>Fax No.: (216) 370-5997<br><br>​

​

​ Schedule 13.2 to Credit Agreement

​

​	​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​	​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​<br><br>​
Royal Bank of Canada	Royal Bank of Canada<br><br>New York Branch<br><br>Three World Financial Center<br><br>200 Vesey Street<br><br>New York, NY 10281-8098<br><br>Attn: Nicola Henry<br><br>Phone No.: (877) 332-7455<br><br>Fax No.: (212) 428-2372<br><br>Email: RBCNewYorkGLA1@rbc.com	Royal Bank of Canada<br><br>New York Branch<br><br>Three World Financial Center<br><br>200 Vesey Street<br><br>New York, NY 10281-8098<br><br>Attn: Nicola Henry<br><br>Phone No.: (416) 974-2460<br><br>Fax No.: (212) 428-2372<br><br>E-Mail: Nicola.c.henry@rbccm.com<br><br>​<br><br>with a copy to:<br><br>​<br><br>Royal Bank of Canada New York Branch<br><br>Three World Financial Center<br><br>200 Vesey Street<br><br>New York, NY 10281-8098<br><br>Attn: Rashmi Chandangoudar<br><br>Fax No.: (212) 428-2372<br><br>E-Mail: Rashmi.chandangoudar@rbccm.com<br><br>​
Truist Bank	Truist Bank<br><br>333 Clay Street, Suite 3800<br><br>Houston, Texas 77002<br><br>​	Business/Credit:<br><br>Truist Bank<br><br>333 Clay Street, Suite 3800<br><br>Houston, Texas 77002<br><br>Attention: Parul Abella<br><br>Phone No.: (713) 797-2142<br><br>E-Mail: Parul.abella@bbandt.com<br><br>​<br><br>with a copy to:<br><br>Truist Bank<br><br>333 Clay Street, Suite 3800<br><br>Houston, Texas 77002<br><br>Attention: James Giordano<br><br>Phone No.: (713) 425-0829<br><br>Fax No.: (888) 707-4162<br><br>E-Mail: jgiordano@bbandt.com<br><br>Admin/Operations:<br><br>Truist Bank<br><br>303 Peach Tree Street<br><br>Atlanta, Georgia<br><br>​

​

​ Schedule 13.2 to Credit Agreement

​ ​

​	​	​<br><br>​<br><br>​<br><br>​<br><br>​
​	​	Attention: Tracinda McGhee-McCoy<br><br>Phone No.: (404) 588-7188<br><br>Fax No.: (844) 279-6613<br><br>E-Mail: Tracinda.GACCS.Rightfax@suntrust.com<br><br>​
UMB Bank, N.A.	UMB Bank<br><br>777 Main Street, Suite 500<br><br>Fort Worth, Texas 76102<br><br>​	Business/Credit:<br><br>UMB Bank, N.A.<br><br>777 Main Street, Suite 500<br><br>Fort Worth, Texas 76102<br><br>Attention: Erica Spencer<br><br>Phone No.: (817) 334-4613<br><br>Fax No. (817) 810-0272<br><br>E-Mail: Erica.Spencer@umb.com<br><br>​<br><br>with a copy to:<br><br>UMB Bank, N.A.<br><br>2323 Ross Ave., Suite 100<br><br>Dallas, Texas 75201<br><br>Attention: Zachary Leard<br><br>Phone No.: (214) 387-3004<br><br>Fax No. (817) 810-0272<br><br>E-Mail: Zachary.Leard@umb.com<br><br>Admin/Operations:<br><br>UMB Bank, N.A.<br><br>1008 Oak Street<br><br>Kansas City, Missouri 64106<br><br>Attention: Dana True<br><br>Phone No.: (816) 860-1921<br><br>Fax No. (816) 860-3177<br><br>E-Mail: Dana.true@umb.com<br><br>​<br><br>with a copy to:<br><br>UMB Bank, N.A.<br><br>1008 Oak Street<br><br>Kansas City, Missouri 64106<br><br>Attention: Vaughnda Ritchie<br><br>Phone No.: (816) 860-7019<br><br>E-Mail: Vaughnda.ritchie@umb.com<br><br>​

​

​

​ Schedule 13.2 to Credit Agreement

​ (c)        Borrower’s Address

​	​
Borrower	Address for Notice
Kimbell Royalty Partners, LP	Kimbell Royalty Partners, LP<br>777 Taylor Street, Suite 810<br>Fort Worth, Texas 76102<br>Attention: Matthew S. Daly<br><br>Email: matt@kimbellrp.com

​ Schedule 13.2 to Credit Agreement

Exhibit 21.1

​

Subsidiaries of Kimbell Royalty Partners, LP

​

​	​	​
Entity Name	​	Jurisdiction
Cirrus Minerals, LLC	​	Delaware
Haymaker Greenfield, LLC	​	Delaware
Haymaker Holding Company, LLC	​	Delaware
Haymaker Properties GP, LLC	​	Delaware
Haymaker Properties, LP	​	Delaware
Hochstetter, L.P.	​	Texas
Kimbell Intermediate GP, LLC	​	Delaware
Kimbell Intermediate Holdings, LLC	​	Delaware
Kimbell Merger Sub, LLC	​	Delaware
Kimbell Royalty Holdings, LLC	​	Delaware
Kimbell Royalty Operating, LLC	​	Delaware
Mustang Minerals, LLC	​	Delaware
Oakwood Minerals I, L.P.	​	Texas
OGM Partners I	​	Texas
Phillips Energy Partners, LLC	​	Delaware
Phillips Energy Partners II, LLC	​	Delaware
Phillips Energy Partners III, LLC	​	Delaware
RCPTX, Ltd.	​	Texas
Rivercrest Royalties Holdings II, LLC	​	Delaware
Rivercrest Royalties, LLC	​	Delaware
Rochester Minerals, L.P.	​	Texas
Springbok Energy Partners, LLC	​	Delaware
Springbok Energy Partners II, LLC	​	Delaware

​

Exhibit 23.1

​

​

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated February 25, 2021, with respect to the consolidated financial statements included in the Annual Report of Kimbell Royalty Partners, LP on Form 10-K for the year ended December 31, 2020. We consent to the incorporation by reference of said report in the Registration Statements of Kimbell Royalty Partners, LP on Form S-3 (File Nos. 333-226425, 333-229417, 333-230986, 333-236341 and 333-238330) and Forms S-8 (File Nos. 333-217986 and 333-228678).

/s/ GRANT THORNTON LLP

Dallas, Texas

February 25, 2021

Exhibit 23.2

​	​	​	​
		​	​
​	TBPE REGISTERED ENGINEERING FIRM F-1580	​	​
​	633 SEVENTEENTH STREET SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 623-9147

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Registration Nos. 333-217986 and 333-228678) and Form S-3 (Registration Nos. 333-226425, 333-229417, 333-230986, 333-236341 and 333-238330) of Kimbell Royalty Partners, LP of our letter dated January 12, 2021, relating to estimates of proved reserves, future production and income attributable certain royalty interests of Kimbell Royalty Partners, LP as of December 31, 2020.

​

​

		/s/ Ryder Scott Company, L.P.
​	​	RYDER SCOTT COMPANY, L.P.
​	​	TBPE Firm Registration No. F-1580
​	​

Denver, Colorado

February 25, 2021

Exhibit 31.1

​

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

​

I, Robert D. Ravnaas, certify that:

​

1.	I have reviewed this Annual Report on Form 10-K of Kimbell Royalty Partners, LP;

​

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

​

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

​

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

​

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

​

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

​

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

​

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

​

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

​

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

​

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

​

​	​
Date: February 25, 2021	/s/ Robert D. Ravnaas
​	Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP<br><br>(Principal Executive Officer)

​

Exhibit 31.2

​

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

​

I, R. Davis Ravnaas, certify that:

​

1.	I have reviewed this Annual Report on Form 10-K of Kimbell Royalty Partners, LP;

​

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

​

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

​

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

​

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

​

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

​

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

​

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

​

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

​

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

​

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

​

​	​
Date: February 25, 2021	/s/ R. Davis Ravnaas
​	President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP<br><br>(Principal Financial Officer)

​

Exhibit 32.1

​

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

​

In connection with the Annual Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-K for the year ended December 31, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Ravnaas, Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

​

(1)      The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

​

(2)      The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

​

​

​	​
Date: February 25, 2021	/s/ Robert D. Ravnaas
​	Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP<br><br>(Principal Executive Officer)

​

Exhibit 32.2

​

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

​

In connection with the Annual Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-K for the year ended December 31, 2020, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Davis Ravnaas, Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

​

(1)  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

​

(2)  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

​

​

​	​
Date: February 25, 2021	/s/ R. Davis Ravnaas
​	President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP<br><br>(Principal Financial Officer)

​

​ Exhibit 99.1

​

​

​

​

​

​

​

KIMBELL ROYALTY PARTNERS, LP

​

​

​

Estimated

​

Future Reserves and Income

​

Attributable to Certain

​

Royalty Interests

​

​

​

​

SEC Parameters

​

​

​

​

​

​

As of

​

December 31, 2020

​

​

​

​

​

​

​

​

​

/s/ Scott J. Wilson
Scott J. Wilson, P.E., MBA
Colorado License No. 36112
Senior Vice President

​

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

​

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

​ ​

​	​	​	​
		​	​
​	TBPE REGISTERED ENGINEERING FIRM F-1580	​	​
​	633 17TH STREET SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

​

​

​

​

​	January 12, 2021

​

​

Kimbell Royalty Partners, LP

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

​

Ladies and Gentlemen:

​

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain royalty interests of Kimbell Royalty Partners, LP, (KRP) as of December 31, 2020.  The diverse inventory of properties is located primarily in the state of Texas, but with additional properties in 25 other states.  The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on January 12, 2021 and presented herein, was prepared for public disclosure by KRP in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

​

The properties evaluated by Ryder Scott represents all of the total net proved liquid and gas reserves of KRP as of December 31, 2020.

​

The estimated reserves and future net income amounts presented in this report, as of December 31, 2020, are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.  Actual future prices may vary considerably from the prices required by SEC regulations.  The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized as follows.

​

​

​

SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799
633 17TH STREET, SUITE 1700	DENVER, COLORADO 80202	TEL (303) 339-8110

​

Kimbell Royalty Partners, LP

January 12, 2021

Page 2

​

​

​

​

​

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Royalty Interests of

Kimbell Royalty Partners, LP

​

As of December 31, 2020

​

​		Proved Developed<br>Producing
Net Reserves	​	​	​
Oil/Condensate – MBarrels	​	​	12,294
Plant Products – MBarrels	​	​	6,085
Gas – MMCF	​	​	144,233
​	​	​	​
Income Data ($M)	​	​	​
Future Gross Revenue	​	$	666,406
Deductions	​	​	16,947
Future Net Income (FNI)	​	$	649,459
​	​	​	​
Discounted FNI @ 10%	​	$	295,311

​

​

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBarrels).  All gas volumes are reported on an “as sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.  In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

​

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM^ Petroleum Economics and Reserves Software, a copyrighted program of Halliburton.  Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.  Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding.  The rounding differences are not material.

​

The future gross revenue is after the deduction of production taxes.  Since the evaluation includes only royalty interests, the only deductions included in the cash flows are ad valorem taxes, while the normal direct costs of operating the wells are used only to estimate economic lives.  The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

​

Liquid hydrocarbon reserves account for approximately 73 percent and gas reserves account for the remaining 27 percent of total future gross revenue from proved reserves.

​

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.  Future net income was discounted at four other discount rates which were also compounded monthly.  These results are shown in summary form as follows.

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Kimbell Royalty Partners, LP

January 12, 2021

Page 3

​

​

​		Discounted Future Net Income (M)
​	​	As of December 31, 2020
Discount Rate	​	​		​
Percent	​	​		​
​	​	​	​	​
4	​	​	434,088	​
6	​	​	373,757	​
8	​	​	329,323	​
12	​	​	268,449	​

All values are in US Dollars.

​

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

​

Reserves Included in This Report

​

The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

​

The proved reserves status categories are defined under the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.

​

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.  The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

​

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  At KRP’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

​

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.”  The proved reserves included herein were estimated using deterministic methods.  The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

​

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Kimbell Royalty Partners, LP

January 12, 2021

Page 4

​

​

agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

​

KRP’s operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

​

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which KRP owns a royalty interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

​

Estimates of Reserves

​

The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy.  These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves.  Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

​

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator.  Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

​

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Kimbell Royalty Partners, LP

January 12, 2021

Page 5

​

​

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

​

One hundred percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include decline curve analysis which utilized extrapolations of historical production and pressure data available through October 2020.  The data utilized in this analysis were furnished to Ryder Scott by KRP and were considered sufficient for the purpose thereof.

​

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data, which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

​

KRP has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In preparing our forecast of future proved production and income, we have relied upon data furnished by KRP with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by KRP.  We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

​

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.  The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.”  In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

​

Future Production Rates

​

For wells currently on production, our forecasts of future production rates are based on historical performance data.  If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Kimbell Royalty Partners, LP

January 12, 2021

Page 6

​

​

was anticipated.  An estimated rate of decline was then applied until depletion of the reserves.  If a decline trend has been established, this trend was used as the basis for estimating future production rates.

​

The future production rates from wells currently on production may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

​

Hydrocarbon Prices

​

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.  For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.  Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

​

KRP furnished us with the above mentioned average prices in effect on December 31, 2020.  These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.  In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements

​

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by KRP.  The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by KRP to determine these differentials.

​

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

​

​	​	​	​	​	​	​
Geographic Area	Product	Price<br>Reference	Average<br>Benchmark<br>Prices		Average<br>Proved<br>Realized<br>Prices
North America	​	​	​	​	​	​
​	Oil/Condensate	WTI Cushing	$	39.57/BBL	$	37.12/BBL
United States	Plant Products	WTI Cushing	$	39.57/BBL	$	9.06/BBL<br>(23% of WTI)
​	Gas	Henry Hub	$	1.985/MMBTU	$	1.34/MCF

​

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Kimbell Royalty Partners, LP

January 12, 2021

Page 7

​

​

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

​

Costs

​

Estimated operating costs for the leases and wells in this report were furnished by KRP and include only those costs directly applicable to the leases or wells.  Because KRP owns only royalty interests, the operating costs were utilized only to calculate the economic life of each entity.  The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by KRP.  No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

​

Current costs used by KRP were held constant throughout the life of the properties.

​

Standards of Independence and Professional Qualification

​

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937.  Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada.  We have approximately eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.

​

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.  We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

​

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.  Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training.  Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

​

We are independent petroleum engineers with respect to KRP.  Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

​

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

​

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Kimbell Royalty Partners, LP

January 12, 2021

Page 8

​

​

Terms of Usage

​

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by KRP.

​

KRP makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act.  Furthermore, KRP has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference.  We have consented to the incorporation by reference in the registration statements on Forms S-3 and S-8 of KRP, of the references to our name, as well as to the references to our third party report for KRP, which appears in the December 31, 2020 annual report on Form 10-K of KRP.  Our written consent for such use is included as a separate exhibit to the filings made with the SEC by KRP.

​

We have provided KRP with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by KRP and the original signed report letter, the original signed report letter shall control and supersede the digital version.

​

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.

​

​	Very truly yours,
​	​
​	RYDER SCOTT COMPANY, L.P.
​	TBPE Firm Registration No. F-1580
​	​
​	/s/ Scott J. Wilson
​	​
​	Scott J. Wilson, P.E., MBA
​	Colorado License No. 36112
​	Senior Vice President

​

SJW (LPC)/pl

​

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

​ ​

Professional Qualifications of Primary Technical Person

​

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

​

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company.  For more information regarding Mr. Wilson's geographic and job specific experience, please refer to the Ryder Scott Company website at https://www.ryderscott.com/company/employees/denver-employees.

​

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors.  He is a registered Professional Engineer by exam in the States of Alaska, Colorado, Texas, and Wyoming.  He is also an active  member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE's Journal of Petroleum Technology.  He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers.  Mr. Wilson has published several technical papers, one chapter in Marine and Petroleum Geology and two in SPEE monograph 4, which was published in 2016.  He is the primary inventor on four US patents and won the 2017 Reservoir Description and Dynamics award for the SPE Rocky Mountain Region.

​

In addition to gaining experience and competency through prior work experience, several state Boards of Professional Engineers require a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills as part of his registration in four states.  As part of his continuing education, Mr. Wilson attends internally presented training as well as public forums relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register.  Mr. Wilson attends additional hours of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

​

Based on his educational background, professional training and more than 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

​

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

​ ​

PETROLEUM RESERVES DEFINITIONS

​

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

​

PREAMBLE

​

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

​

*Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.*All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

​

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

​

Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

​

Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

​

​

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

​

Reserves do not include quantities of petroleum being held in inventory.

​

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

​

RESERVES (SEC DEFINITIONS)

​

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

​

Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

​

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).

​

PROVED RESERVES (SEC DEFINITIONS)

​

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

​

Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

​

(i) The area of the reservoir considered as proved includes:

​

(A) The area identified by drilling and limited by fluid contacts, if any, and

​

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

​

​

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

​

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

​

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

​

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

​

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

​

​

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

​ ​

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

​

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

​

and

​

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

​

Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

​

DEVELOPED RESERVES (SEC DEFINITIONS)

​

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

​

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

​

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

​

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

​

Developed Producing (SPE-PRMS Definitions)

​

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

​

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

​

​ RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

​

​

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

​

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

​

Shut-In

Shut-in Reserves are expected to be recovered from:

(1)	completion intervals that are open at the time of the estimate but which have not  yet started producing;
(2)	wells which were shut-in for market conditions or pipeline connections; or
---	---
(3)	wells not capable of production for mechanical reasons.
---	---

​

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

​

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

​

UNDEVELOPED RESERVES (SEC DEFINITIONS)

​

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

​

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

​

*(i)*Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

​

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

​

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS