KRP 10-Q
Kimbell Royalty Partners, LP (KRP)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the quarterly period ended OR | |
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:
(Exact name of registrant as specified in its charter)
| 1311 |
|
(
(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 Act:
Title of each class: | Trading symbol(s) | Name of exchange on which registered: |
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.
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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.
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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
As of October 28, 2022, the registrant had outstanding
KIMBELL ROYALTY PARTNERS, LP
FORM 10-Q
TABLE OF CONTENTS
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PART I – FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited)
KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, | December 31, | |||||
2022 | 2021 | |||||
ASSETS | ||||||
Current assets | ||||||
Cash and cash equivalents | $ | | $ | | ||
Oil, natural gas and NGL receivables | | | ||||
Derivative assets | — | | ||||
Accounts receivable and other current assets | | | ||||
Total current assets | | | ||||
Property and equipment, net | | | ||||
Investment in affiliate (equity method) | | | ||||
Oil and natural gas properties | ||||||
Oil and natural gas properties, using full cost method of accounting ($ | | | ||||
Less: accumulated depreciation, depletion and impairment | ( | ( | ||||
Total oil and natural gas properties, net | | | ||||
Right-of-use assets, net | | | ||||
Derivative assets | — | | ||||
Loan origination costs, net | | | ||||
Assets of consolidated variable interest entities: | ||||||
Cash | | — | ||||
Investments held in trust | | — | ||||
Prepaid expenses | | — | ||||
Total assets | $ | | $ | | ||
LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY | ||||||
Current liabilities | ||||||
Accounts payable | $ | | $ | | ||
Other current liabilities | | | ||||
Derivative liabilities | | | ||||
Total current liabilities | | | ||||
Operating lease liabilities, excluding current portion | | | ||||
Derivative liabilities | | | ||||
Long-term debt | | | ||||
Other liabilities | | | ||||
Liabilities of consolidated variable interest entities: | ||||||
Other current liabilities | | — | ||||
Deferred underwriting commissions | | — | ||||
Total liabilities | | | ||||
Commitments and contingencies (Note 15) | ||||||
Mezzanine equity: | ||||||
Redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation | | — | ||||
Kimbell Royalty Partners, LP unitholders' equity: | ||||||
Common units ( | | | ||||
Class B units ( | | | ||||
Total Kimbell Royalty Partners, LP unitholders' equity | | | ||||
Noncontrolling (deficit) interest in OpCo | ( | | ||||
Total equity | | | ||||
Total liabilities, mezzanine equity and unitholders' equity | $ | | $ | | ||
The accompanying notes are an integral part of these consolidated financial statements.
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||
Revenue | ||||||||||||
Oil, natural gas and NGL revenues | $ | | $ | | $ | | $ | | ||||
Lease bonus and other income | | | | | ||||||||
Loss on commodity derivative instruments, net | ( | ( | ( | ( | ||||||||
Total revenues | | | | | ||||||||
Costs and expenses | ||||||||||||
Production and ad valorem taxes | | | | | ||||||||
Depreciation and depletion expense | | | | | ||||||||
Marketing and other deductions | | | | | ||||||||
General and administrative expense | | | | | ||||||||
Consolidated variable interest entities related: | ||||||||||||
General and administrative expense | | — | | — | ||||||||
Total costs and expenses | | | | | ||||||||
Operating income | | | | | ||||||||
Other income (expense) | ||||||||||||
Equity income in affiliate | | | | | ||||||||
Interest expense | ( | ( | ( | ( | ||||||||
Other income (expense) | | ( | | | ||||||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in trust account | | — | | — | ||||||||
Net income before income taxes | | | | | ||||||||
Income tax (benefit) expense | ( | — | | — | ||||||||
Net income | | | | | ||||||||
Distribution and accretion on Series A preferred units | — | ( | — | ( | ||||||||
Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interests in OpCo | ( | ( | ( | ( | ||||||||
Distribution on Class B units | ( | ( | ( | ( | ||||||||
Net income attributable to common units of Kimbell Royalty Partners, LP | $ | | $ | | $ | | $ | | ||||
Net income per unit attributable to common units of Kimbell Royalty Partners, LP | ||||||||||||
Basic | $ | | $ | | $ | | $ | | ||||
Diluted | $ | | $ | | $ | | $ | | ||||
Weighted average number of common units outstanding | ||||||||||||
Basic | | | | | ||||||||
Diluted | | | | | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY
(Unaudited)
Nine Months Ended September 30, 2022 | |||||||||||||||||||||
Noncontrolling | Noncontrolling | ||||||||||||||||||||
| Common Units |
| Amount |
| Class B Units |
| Amount | Interest | Interest | Total | |||||||||||
Balance at January 1, 2022 | | $ | | | $ | | $ | | $ | — | $ | | |||||||||
Costs associated with equity offering | — | ( | — | — | — | — | ( | ||||||||||||||
Conversion of Class B units to common units | | | ( | ( | ( | — | ( | ||||||||||||||
Restricted units repurchased for tax withholding | ( | ( | — | — | — | — | ( | ||||||||||||||
Unit-based compensation | | | — | — | — | — | | ||||||||||||||
Distributions to unitholders | — | ( | — | — | ( | — | ( | ||||||||||||||
Distribution on Class B units | — | ( | — | — | — | — | ( | ||||||||||||||
Proceeds from issuance of TGR public warrants | — | — | — | — | — | | | ||||||||||||||
Accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation | — | ( | — | — | ( | ( | ( | ||||||||||||||
Net income | — | | — | — | | — | | ||||||||||||||
Balance at March 31, 2022 | | | | | ( | — | | ||||||||||||||
Conversion of Class B units to common units | | | ( | ( | ( | — | ( | ||||||||||||||
Forfeitures of restricted units | ( | ( | — | — | — | — | ( | ||||||||||||||
Unit-based compensation | — | | — | — | — | — | | ||||||||||||||
Distributions to unitholders | — | ( | — | — | ( | — | ( | ||||||||||||||
Distribution on Class B units | — | ( | — | — | — | — | ( | ||||||||||||||
Accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation | — | ( | — | — | ( | — | ( | ||||||||||||||
Net income | — | | — | — | | — | | ||||||||||||||
Balance at June 30, 2022 | | | | | ( | — | | ||||||||||||||
Unit-based compensation | — | | — | — | — | — | | ||||||||||||||
Distributions to unitholders | — | ( | — | — | ( | — | ( | ||||||||||||||
Distribution on Class B units | — | ( | — | — | — | — | ( | ||||||||||||||
Net income | — | | — | — | | — | | ||||||||||||||
Balance at September 30, 2022 | | $ | | | $ | | $ | ( | $ | — | $ | | |||||||||
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY — (Continued)
(Unaudited)
Nine Months Ended September 30, 2021 | ||||||||||||||||||
Noncontrolling | ||||||||||||||||||
| Common Units |
| Amount |
| Class B Units |
| Amount | Interest | Total | |||||||||
Balance at January 1, 2021 | | $ | | | $ | | $ | | $ | | ||||||||
Restricted units repurchased for tax withholding | ( | ( | — | — | — | ( | ||||||||||||
Unit-based compensation | | | — | — | — | | ||||||||||||
Distributions to unitholders | — | ( | — | — | ( | ( | ||||||||||||
Distribution and accretion on Series A preferred units | — | ( | — | — | ( | ( | ||||||||||||
Distribution on Class B units | — | ( | — | — | — | ( | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at March 31, 2021 | | | | | | | ||||||||||||
Conversion of Class B units to common units | | | ( | ( | ( | ( | ||||||||||||
Restricted units repurchased for tax withholding | ( | ( | — | — | — | ( | ||||||||||||
Unit-based compensation | — | | — | — | — | | ||||||||||||
Distributions to unitholders | — | ( | — | — | ( | ( | ||||||||||||
Distribution and accretion on Series A preferred units | — | ( | — | — | ( | ( | ||||||||||||
Distribution on Class B units | — | ( | — | — | — | ( | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at June 30, 2021 | | | | | | | ||||||||||||
Redemption of Series A preferred units | — | ( | — | — | ( | ( | ||||||||||||
Unit-based compensation | — | | — | — | — | | ||||||||||||
Distributions to unitholders | — | ( | — | — | ( | ( | ||||||||||||
Distribution and accretion on Series A preferred units | — | ( | — | — | ( | ( | ||||||||||||
Distribution on Class B units | — | ( | — | — | — | ( | ||||||||||||
Net income | — | | — | — | | | ||||||||||||
Balance at September 30, 2021 | | $ | | | $ | | $ | | $ | | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | ||||||
2022 |
| 2021 | ||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||
Net income | $ | | $ | | ||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Depreciation and depletion expense | | | ||||
Amortization of right-of-use assets | | | ||||
Amortization of loan origination costs | | | ||||
Equity income in affiliate | ( | ( | ||||
Cash distribution from affiliate | | | ||||
Forfeiture of restricted units | ( | — | ||||
Unit-based compensation | | | ||||
(Gain) loss on derivative instruments, net of settlements | ( | | ||||
Changes in operating assets and liabilities: | ||||||
Oil, natural gas and NGL receivables | ( | ( | ||||
Accounts receivable and other current assets | | ( | ||||
Accounts payable | | | ||||
Other current liabilities | | | ||||
Operating lease liabilities | ( | ( | ||||
Consolidated variable interest entities related: | ||||||
Interest earned on marketable securities in trust account | ( | — | ||||
Other assets and liabilities | ( | — | ||||
Net cash provided by operating activities | | | ||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||
Purchases of property and equipment | ( | ( | ||||
Purchase of oil and natural gas properties | ( | ( | ||||
Cash distribution from affiliate | | | ||||
Consolidated variable interest entities related: | ||||||
Investments in marketable securities | ( | — | ||||
Net cash used in investing activities | ( | ( | ||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||
Costs associated with equity offering | ( | — | ||||
Redemption of Class B contributions on converted units | ( | ( | ||||
Redemption on Series A preferred units | — | ( | ||||
Distributions to common unitholders | ( | ( | ||||
Distribution to OpCo unitholders | ( | ( | ||||
Distribution and accretion on Series A preferred units | — | ( | ||||
Distribution on Class B units | ( | ( | ||||
Borrowings on long-term debt | | | ||||
Repayments on long-term debt | ( | ( | ||||
Payment of loan origination costs | ( | ( | ||||
Restricted units repurchased for tax withholding | ( | ( | ||||
Consolidated variable interest entities related: | ||||||
Proceeds from initial public offering of Kimbell Tiger Operating Company | | — | ||||
Payment of underwriting commissions with equity offering of Kimbell Tiger Operating Company, net of adjustments | ( | — | ||||
Net cash provided by (used in) financing activities | | ( | ||||
NET INCREASE IN CASH AND CASH EQUIVALENTS | | | ||||
CASH AND CASH EQUIVALENTS, beginning of period | | | ||||
CASH AND CASH EQUIVALENTS, end of period | $ | | $ | | ||
Supplemental cash flow information: | ||||||
Cash paid for interest | $ | | $ | | ||
Cash paid for taxes | $ | | $ | — | ||
Non-cash investing and financing activities: | ||||||
Noncash effect of Series A preferred unit redemption | $ | — | $ | | ||
Noncash deemed distribution to Series A preferred units | $ | — | $ | | ||
Recognition of tenant improvement asset | $ | | $ | | ||
Right-of-use assets obtained in exchange for operating lease liabilities | $ | — | $ | | ||
Consolidated variable interest entities related: | ||||||
Deferred underwriting commissions | $ | | $ | — | ||
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KIMBELL ROYALTY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
(Unaudited)
Nine Months Ended September 30, | ||||||
2022 |
| 2021 | ||||
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows | ||||||
Cash and cash equivalents | $ | | $ | | ||
Cash held at consolidated variable interest entities | | — | ||||
$ | | $ | | |||
The accompanying notes are an integral part of these consolidated financial statements.
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Unless the context otherwise requires, 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” or “OpCo” 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.
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.
On February 8, 2022, the Partnership announced the $
Kimbell Tiger Acquisition Corporation (“TGR”) was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”), which is a subsidiary of the Partnership, was created to assist TGR in sourcing, analyzing and consummating acquisition opportunities for that initial business combination.
TGR Sponsor and TGR have been consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021. This resulted in the consolidation of $
Basis of Presentation
The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”). As a result, the accompanying unaudited interim consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2021 (the “2021 Form 10-K”), which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the General Partner, the unaudited interim consolidated financial statements contain all adjustments necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP and all adjustments are of a normal recurring nature. The accompanying unaudited interim consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries. All material intercompany balances and transactions are eliminated in consolidation. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.
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Use of Estimates
Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates.
Segment Reporting
The Partnership operates in a operating and 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.
COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas
Coronavirus (“COVID-19”) remains a global health crisis and there continues to be considerable uncertainty regarding the ultimate impact of COVID-19 and its variants. Despite improvements in global economic activity levels and higher energy demand compared to 2021, the impact of COVID-19 continue to be unpredictable, including the impact of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. The Partnership is unable to reasonably estimate the period of time that related conditions could exist or the extent to which they could impact the Partnership’s business, results of operations, financial condition or cash flows. Commodity prices have risen from 2021; however, further negative impact from COVID-19 may require the Partnership to adjust its business plan.
The ultimate impact 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 remain dependent on a number of factors, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, the ability of the Organization of Petroleum Exporting Countries, Russia and other crude oil producing nations to manage the global crude oil supply, additional actions by businesses and governments in response to the pandemic, the economic downturn and the decrease in crude oil demand, the speed and effectiveness of responses to combat the virus and the time necessary to balance crude oil supply and demand to restore crude oil pricing. Although prices have recovered, the ongoing impact of COVID-19 on our business, employees and operations, including supply chain concerns, among others still continues to affect our industry.
Russia / Ukraine Conflict
In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Significant Accounting Policies
For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s 2021 Form 10-K, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the three and nine months ended September 30, 2022.
Consolidation
The Partnership analyzes whether it has a variable interest in an entity and whether that entity is a variable interest entity (“VIE”) to determine whether it is required to consolidate those entities. The Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of all entities with respect to which the Partnership serves as the sponsor, general partner or managing member, and general partner entities
8
not wholly owned by the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required.
In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.
For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.
VIEs of which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.
Investments Held in Trust by Consolidated Variable Interest Entities
Investments held in trust represent funds raised by TGR, a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 3). These funds are held in an actively-traded money market fund, which invests in U.S. Treasury securities. Investments held in trust are classified as trading securities and are presented on the balance sheet at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in other income (expense)—interest earned on marketable securities in trust account on the accompanying unaudited interim consolidated statements of operations. The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements.
Redeemable Non-Controlling Interest
Redeemable non-controlling interests represent the shares of TGR Class A common stock (as defined in Note 3) sold in the TGR IPO that are redeemable for cash by the public TGR shareholders concurrently with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests are initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. The carrying amount remains accreted to its full redemption value at September 30, 2022.
NOTE 3—ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY
Acquisitions
On December 7, 2021, the Partnership completed the acquisition of all of the equity interests in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”) for an aggregate purchase price of approximately $
9
approximately
Joint Venture
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 was
Special Purpose Acquisition Company
On July 29, 2021, TGR, the Partnership’s special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the SEC. On February 8, 2022, TGR consummated its initial public offering (the “TGR IPO”) of
In connection with the closing of the TGR IPO, TGR completed the sale of
In addition, TGR incurred $
In May 2021, prior to TGR’s IPO, TGR Sponsor paid $
In determining the accounting treatment of the Partnership’s equity interest in TGR, management concluded that TGR is a VIE as defined by Accounting Standards Codification Topic 810, “Consolidation.” A VIE is an entity in which equity investors at risk lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, the party who has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, as well as the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the entity. TGR Sponsor is the primary beneficiary of TGR as it has, through
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its equity interest, the right to receive benefits or the obligation to absorb losses from TGR, as well as the power to direct a majority of the activities that significantly impact TGR’s economic performance, including identification of a target for its Business Combination. As such, TGR is consolidated into the Partnership’s financial statements through TGR Sponsor.
Proceeds of $
The public unitholders’ ownership of TGR Class A common stock represents a redeemable non-controlling interest to the Partnership, which is classified outside of permanent unitholders’ equity as the TGR Class A common stock is redeemable at the option of the public unitholders in connection with the Business Combination. The carrying amount of the redeemable non-controlling interest is equal to the greater of (i) the initial carrying amount, increased or decreased for the redeemable non-controlling interest’s share of TGR’s net income or loss and distributions or (ii) the redemption value. The public unitholders of TGR Class A common stock will be entitled in certain circumstances to redeem their shares of TGR Class A common stock for a pro rata portion of the amount in the trust account at $
If TGR has not completed the Business Combination within such
As of September 30, 2022, the Partnership owned approximately
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NOTE 4—DERIVATIVES
Commodity 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.
As of September 30, 2022, 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 production based on the amount of debt and/or preferred equity as a percent of its enterprise value. As of September 30, 2022, these economic hedges constituted approximately
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 scheduled trading day for the first nearby month futures contract corresponding to the relevant contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the current period and are presented on a net basis within revenue in the accompanying unaudited interim consolidated statements of operations.
Interest Rate Swaps
On January 27, 2021, the Partnership entered into an interest rate swap with Citibank, N.A., New York (“Citibank”), which fixed the interest rate on $
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The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. Changes in fair value consisted of the following:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||
Beginning fair value of derivative instruments | $ | ( | $ | ( | $ | ( | $ | ( | ||||
Loss on derivative instruments | ( | ( | ( | ( | ||||||||
Net cash paid on settlements of derivative instruments | | | | | ||||||||
Ending fair value of derivative instruments | $ | ( | $ | ( | $ | ( | $ | ( | ||||
The following table presents the fair value of the Partnership’s derivative contracts for the periods indicated:
September 30, | December 31, | |||||||
Classification | Balance Sheet Location | 2022 | 2021 | |||||
Assets: | ||||||||
Current assets | Derivative assets | $ | — | $ | | |||
Long-term assets | Derivative assets | — | | |||||
Liabilities: | ||||||||
Current liabilities | Derivative liabilities | ( | ( | |||||
Long-term liabilities | Derivative liabilities | ( | ( | |||||
$ | ( | $ | ( | |||||
As of September 30, 2022, 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 | ||||||||
October 2022 - December 2022 | | $ | | $ | | $ | | ||||
January 2023 - December 2023 | | $ | | $ | | $ | | ||||
January 2024 - September 2024 | | $ | | $ | | $ | | ||||
Natural Gas Price Swaps
Notional | Weighted Average | Range (per MMBtu) | |||||||||
Volumes (MMBtu) | Fixed Price (per MMBtu) | Low | High | ||||||||
October 2022 - December 2022 | | $ | | $ | | $ | | ||||
January 2023 - December 2023 | | $ | | $ | | $ | | ||||
January 2024 - September 2024 | | $ | | $ | | $ | | ||||
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 unaudited interim consolidated balance sheets approximated fair value as of September 30, 2022 and December 31, 2021 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). |
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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 three and nine months ended September 30, 2022 and 2021.
The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy. Both the Partnership’s commodity derivative instruments and interest rate swap 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 | Total | |||||||||||
September 30, 2022 | |||||||||||||||
Assets | |||||||||||||||
Investments held in trust | $ | | $ | — | $ | — | $ | — | $ | | |||||
Liabilities | |||||||||||||||
Commodity derivative contracts | $ | — | $ | ( | $ | — | $ | — | $ | ( | |||||
December 31, 2021 | |||||||||||||||
Assets | |||||||||||||||
Interest rate swap contracts | $ | — | $ | | $ | — | $ | — | $ | | |||||
Liabilities | |||||||||||||||
Commodity derivative contracts | $ | — | $ | ( | $ | — | $ | — | $ | ( | |||||
NOTE 6—OIL AND NATURAL GAS PROPERTIES
Oil and natural gas properties consist of the following:
| September 30, | December 31, | ||||
2022 | 2021 | |||||
Oil and natural gas properties | ||||||
Proved properties | $ | | $ | | ||
Unevaluated properties | | | ||||
Less: accumulated depreciation, depletion and impairment | ( | ( | ||||
Total oil and natural gas properties | $ | | $ | | ||
The Partnership assesses all unevaluated properties on a 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. 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. 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.
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After evaluating certain external factors in 2020, the Partnership determined that it did not have reasonable certainty as to the timing of the development of the proved undeveloped (“PUD”) reserves and, therefore did not book PUD reserves in its total estimated proved reserves as of September 30, 2022 or December 31, 2021 and it does not intend to book PUD reserves going forward.
The Partnership did
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 unaudited interim consolidated balance sheets. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of September 30, 2022 is
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 leases was
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 unaudited interim consolidated statements of operations for the three and nine months ended September 30, 2022 and 2021. The total operating lease expense recorded for both the three months ended September 30, 2022 and 2021 was $
Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations.
Future minimum lease commitments as of September 30, 2022 were as follows:
Total | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | |||||||||||||||
Operating leases | $ | | $ | | $ | | $ | | $ | | $ | | $ | | |||||||
Less: Imputed Interest |
| ( |
| ||||||||||||||||||
Total | $ | |
| ||||||||||||||||||
NOTE 8—LONG-TERM DEBT
On June 7, 2022, the Partnership entered into Amendment No. 3 (the “Third Credit Agreement Amendment”) to the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (as amended by that certain Amendment No. 1 to Credit Agreement, dated as of July 12, 2018, and that certain Amendment No. 2 to Credit Agreement, dated as of December 8, 2020, and as otherwise amended or modified prior to such date, the “Credit Agreement” and the Credit Agreement, as amended by the Third Credit Agreement Amendment, the “Amended Credit Agreement”), with certain subsidiaries of the Partnership, as guarantors, the lenders party thereto and Citibank as administrative agent.
The Third Credit Agreement Amendment amended the Credit Agreement to, among other things, (i) increase (1) the aggregate elected commitments under the Amended Credit Agreement’s senior secured revolving credit facility (the “Credit Facility”) and (2) the borrowing base under the Credit Facility, in each case, from $
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interest periods, plus a fixed credit spread adjustment of
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 representing limited partner interests in the Partnership (“common units”) and common units of the Operating Company (“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 of not more than to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 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.
During the nine months ended September 30, 2022, the Partnership borrowed an additional $
As of September 30, 2022, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of
The 1-week and 2-month U.S. dollar LIBOR settings ceased to be published after December 31, 2021, and the U.K. Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S. dollar settings after June 30, 2023. In response, the Partnership’s secured revolving credit facility has transitioned to the use of the SOFR published by the Federal Reserve Bank of New York in replacement of LIBOR.
NOTE 9—PREFERRED UNITS
In July 2018, the Partnership completed the private placement of
On February 12, 2020, the Partnership completed the redemption of
On July 7, 2021, the Partnership completed the redemption of
On December 7, 2021, the Partnership completed the redemption of the remaining
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units was greater than the carrying value of the Series A preferred units as of the redemption date and the remaining intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $
As of September 30, 2022 and December 31, 2021,
NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS
The Partnership has issued units representing limited partner interests. As of September 30, 2022, the Partnership had a total of
In November 2021, the Partnership completed an underwritten public offering of
The following table summarizes the changes in the number of the Partnership’s common units:
Common Units | ||
Balance at December 31, 2021 | | |
Conversion of Class B units | | |
Common units issued under the A&R LTIP (1) | | |
Restricted units repurchased for tax withholding | ( | |
Forfeiture of restricted units | ( | |
Balance at September 30, 2022 | |
| (1) | Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan on February 24, 2022. |
The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the periods presented:
Amount per | Date | Unitholder | Payment | ||||||
Common Unit | Declared | Record Date | Date | ||||||
Q1 2022 | $ | | April 22, 2022 | May 2, 2022 | May 9, 2022 | ||||
Q2 2022 | $ | | August 3, 2022 | August 15, 2022 | August 22, 2022 | ||||
Q3 2022 | $ | | November 3, 2022 | November 14, 2022 | November 21, 2022 | ||||
Q1 2021 | $ | | April 23, 2021 | May 3, 2021 | May 10, 2021 | ||||
Q2 2021 | $ | | July 23, 2021 | August 2, 2021 | August 9, 2021 | ||||
Q3 2021 | $ | | October 22, 2021 | November 1, 2021 | November 8, 2021 | ||||
The following table summarizes the changes in the number of the Partnership’s Class B units:
Class B Units | ||
Balance at December 31, 2021 | | |
Conversion of Class B units | ( | |
Balance at September 30, 2022 | |
For each Class B unit issued,
The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.
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NOTE 11—EARNINGS (LOSS) PER COMMON UNIT
Basic earnings (loss) per common unit is calculated by dividing net income (loss) attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 12) for its employees, directors and consultants and potential conversion of Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Class B units (and corresponding units of Kimbell Royalty Partners, LP), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding restricted units granted under the Partnership’s LTIP. The Partnership does not use the two-class method because the Class B units and the unvested restricted units granted under the Partnership’s LTIP are nonparticipating securities.
The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted earnings (loss) per common unit:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||
Net income attributable to common units of Kimbell Royalty Partners, LP | $ | | $ | | $ | | $ | | ||||
Accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation | — | — | ( | — | ||||||||
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation | | | | | ||||||||
Diluted net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation | | | | | ||||||||
Weighted average number of common units outstanding: | ||||||||||||
Basic | | | | | ||||||||
Effect of dilutive securities: | ||||||||||||
Class B units | | | | | ||||||||
Restricted units | | | | | ||||||||
Diluted | | | | | ||||||||
Net income per unit attributable to common units of Kimbell Royalty Partners, LP | ||||||||||||
Basic | $ | | $ | | $ | | $ | | ||||
Diluted | $ | | $ | | $ | | $ | | ||||
The calculation of diluted net income per share for the three and nine months ended September 30, 2022 and 2021 includes the conversion of all Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method.
NOTE 12—UNIT-BASED COMPENSATION
On May 18, 2022, the Partnership held a special meeting of unitholders of the Partnership (the “Special Meeting”), at which the Partnership’s unitholders voted to approve the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (the “A&R LTIP”), which increased the number of common units eligible for issuance under the A&R LTIP by
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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.
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 under the A&R 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, 2021 | | $ | |
| |||
Awarded | | | — | ||||
Vested | ( | | — | ||||
Forfeited | ( | | — | ||||
Unvested at September 30, 2022 | | $ | |
| |||
NOTE 13—INCOME TAXES
The Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. The Partnership recorded an income tax benefit of $
NOTE 14—RELATED PARTY TRANSACTIONS
The Partnership currently has a management services agreement with Kimbell Operating, which has separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”) and K3 Royalties, LLC (“K3 Royalties”), 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 may 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 amount of cash available for distribution on common units to the Partnership’s unitholders.
Kimbell Operating previously had services agreements with Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”). Effective as of February 18, 2022, Kimbell Operating and each of Nail Bay Royalties and Duncan Management entered into an agreement to terminate the services agreements of such service providers.
During the three and nine months ended September 30, 2022 and 2021,
Commencing on the date of the TGR IPO, TGR agreed to pay the Partnership a total of $
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NOTE 15—COMMITMENTS AND CONTINGENCIES
During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. 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 September 30, 2022.
NOTE 16—SUBSEQUENT EVENTS
The Partnership has evaluated events that occurred subsequent to September 30, 2022 in the preparation of its unaudited interim consolidated financial statements.
Distributions
On November 3, 2022, the Board of Directors declared a quarterly cash distribution of $
As to the Partnership, $
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited interim consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2021 (the “2021 Form 10-K”).
Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” the “Partnership,” “we” or “us” refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. 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.
Cautionary Statement Regarding Forward-Looking Statements
Certain statements and information in this Quarterly 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 Quarterly 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 natural gas liquids (“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; |
| ● | our ability to forecast identified drilling locations, gross horizontal wells, drilling inventory and estimates of reserves on our properties and on properties we seek to acquire; |
| ● | regional supply and demand factors, delays or interruptions of production; |
| ● | industry, economic, business or political conditions, including the energy and environmental proposals being considered and evaluated by the federal government and other regulating bodies, 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; |
| ● | the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine; |
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| ● | revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties; |
| ● | impact 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; |
| ● | 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; |
| ● | 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; |
| ● | the ability of Kimbell Tiger Acquisition Corporation (“TGR”) to select an appropriate target business or businesses, enter into a binding agreement with a target and complete its initial business combination, as well as its ability to obtain necessary financing to complete its initial business combination; and |
| ● | the overall performance and success of any target business or businesses selected by TGR for its initial business combination. |
These factors are discussed in further detail in the 2021 Form 10-K under “Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II and elsewhere in this Quarterly 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.
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
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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 September 30, 2022, we owned mineral and royalty interests in approximately 11.4 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 62% 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 September 30, 2022, over 99% 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 122,000 gross wells, including over 46,000 wells in the Permian Basin.
The following table summarizes our ownership in United States basins and producing regions and information about the wells in which we have a mineral or royalty interest as of September 30, 2022:
Average Daily | ||||||||
Production | ||||||||
Basin or Producing Region | Gross Acreage | Net Acreage | (Boe/d)(6:1)(1) | Well Count | ||||
Permian Basin | 2,935,371 | 23,560 | 2,431 | 46,933 | ||||
Mid‑Continent |
| 5,369,358 | 44,310 | 1,801 | 19,118 | |||
Haynesville |
| 1,428,907 | 7,919 | 4,189 | 16,065 | |||
Appalachia | 741,354 | 23,203 | 1,850 | 3,818 | ||||
Bakken |
| 1,640,077 | 6,138 | 846 | 5,180 | |||
Eagle Ford |
| 624,148 | 6,730 | 1,762 | 3,930 | |||
Rockies |
| 74,152 | 1,036 | 847 | 12,502 | |||
Other |
| 3,232,561 | 36,693 | 1,259 | 15,353 | |||
Total |
| 16,045,928 | 149,589 | 14,985 | 122,899 |
| (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 “Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves” in our 2021 Form 10-K. |
The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of September 30, 2022:
Basin or Producing Region(1) | Gross DUCs | Gross Permits | Net DUCs | Net Permits | ||||
Permian Basin | 299 | 265 | 1.04 | 0.87 | ||||
Mid‑Continent |
| 118 | 40 | 0.24 | 0.07 | |||
Haynesville |
| 93 | 36 | 0.64 | 0.25 | |||
Appalachia | 4 | 12 | 0.02 | 0.02 | ||||
Bakken |
| 90 | 125 | 0.10 | 0.78 | |||
Eagle Ford |
| 62 | 77 | 0.40 | 0.80 | |||
Rockies |
| 16 | 20 | 0.03 | 0.18 | |||
Total |
| 682 | 575 | 2.47 | 2.97 |
| (1) | The above table represents DUCs and permitted locations only, and there is no guarantee that the DUCs or permitted locations will be developed into producing wells in the future. |
Recent Developments
Initial Public Offering of Kimbell Tiger Acquisition Corporation
On July 29, 2021, TGR, our newly formed special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the SEC. On February 8, 2022, TGR consummated its initial public offering (the “TGR IPO”) of 23,000,000 units (each a “unit” and, collectively, the “units”), including 3,000,000 additional units issued pursuant to the underwriter’s exercise in full of its over-allotment option, at $10.00 per unit, generating proceeds of
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approximately $230.0 million and incurring offering costs of approximately $12.7 million, inclusive of $8.1 million in deferred underwriting commissions. Each unit consists of one share of Class A common stock and one-half of one redeemable warrant. Each whole warrant may be exercised for one share of Class A common stock at a price of $11.50 per share. Certain members of our management and members of the Board of Directors are members of the sponsor of TGR. TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses (the “Business Combination”). Under the terms of TGR’s governing documents, TGR has 15 months (or up to 21 months under certain circumstances) from the closing of the TGR IPO to complete the Business Combination.
In connection with the closing of the TGR IPO, TGR completed the sale of 14.1 million private placement warrants (the “private placement warrants”) to TGR Sponsor for a purchase price of $1.00 per private placement warrant, generating gross proceeds of $14.1 million. Each private placement warrant is exercisable to purchase for $11.50 one share of TGR Class A common stock.
In May 2021, prior to the TGR IPO, TGR Sponsor paid $25,000 in exchange for the issuance of (i) 5,750,100 shares of TGR’s Class B common stock, par value $0.0001 per share (the “TGR Class B common stock”), and (ii) 2,500 shares of TGR’s Class A common stock, par value $0.0001 (the “TGR Class A common stock”). Additionally, in May 2021, TGR paid $25,000 to Kimbell Tiger Operating Company (“TGR Opco”) in exchange for the issuance of 2,500 Class A units of TGR Opco. Also in May 2021, TGR Sponsor received 100 Class A units of TGR Opco in exchange for $1,000 and 5,750,000 Class B units of TGR Opco. The shares of TGR Class B common stock and corresponding number of Class B units of TGR Opco (or the Class A units of TGR Opco into which such Class B units will convert) are collectively referred to as the “Founders Shares.” The Founders Shares will be exchangeable for shares of TGR Class A common stock upon completion of the Business Combination on a one-for-one basis, subject to certain adjustments. Class A units and Class B units of TGR Opco are substantially similar, other than certain distribution rights, and are entitled to vote together as a single class on all matters submitted for stockholder vote.
In determining the accounting treatment of our equity interest in TGR, management concluded that TGR is a variable interest entity (“VIE”) as defined by Accounting Standards Codification Topic 810, “Consolidation.” A VIE is an entity in which equity investors at risk lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, the party who has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, as well as the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the entity. TGR Sponsor is the primary beneficiary of TGR as it has, through its equity interest, the right to receive benefits or the obligation to absorb losses from TGR, as well as the power to direct a majority of the activities that significantly impact TGR’s economic performance, including identification of a target for its Business Combination. As such, TGR is fully consolidated into our financial statements.
As of September 30, 2022, we owned approximately 20% of the common stock of TGR and the net loss and net assets of TGR were consolidated with our financial statements. The remaining approximate 80% of the consolidated net loss and net assets of TGR, representing the percentage of economic interest in TGR held by public shareholders of TGR through their ownership of TGR common stock, were allocated to redeemable non-controlling interest. All transactions between TGR and TGR Sponsor, as well as related financial statement impact, eliminate in consolidation.
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Quarterly Distributions
On November 3, 2022, the Board of Directors declared a quarterly cash distribution of $0.49 per common unit representing limited partner interests in the Partnership (“common units”) and $0.509479 per common unit of the Operating Company (“OpCo common units”) for the quarter ended September 30, 2022. We intend to pay the distributions on November 21, 2022 to common unitholders and OpCo common unitholders of record as of the close of business on November 14, 2022.
As to us, $0.019479 of the OpCo common unit distribution corresponds to a tax payment made by us in the third quarter of 2022. Under the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us.
Business Environment
COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas
COVID-19 remains a global health crisis and there continues to be considerable uncertainty regarding the ultimate impact of COVID-19 and its variants. Despite improvements in global economic activity levels and higher energy demand compared to 2021, the impact of COVID-19 continue to be unpredictable, including the impact of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. The Partnership is unable to reasonably estimate the period of time that related conditions could exist or the extent to which they could impact the Partnership’s business, results of operations, financial condition or cash flows. Commodity prices have risen from 2021; however, further negative impact from COVID-19 may require the Partnership to adjust its business plan.
The ultimate impact 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 remain dependent on a number of factors, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, the ability of OPEC, Russia and other crude oil producing nations to manage the global crude oil supply, additional actions by businesses and governments in response to the pandemic, the economic downturn and the decrease in crude oil demand, the speed and effectiveness of responses to combat the virus and the time necessary to balance crude oil supply and demand to restore crude oil pricing. Although prices have recovered, the ongoing impact of COVID-19 on our business, employees and operations, including supply chain concerns, among others still continues to affect our industry. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in Part I, Item 1A. Risk Factors in our 2021 Form 10-K.
Russia / Ukraine Conflict
In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.
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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, the winter storms experienced in parts of the United States in February 2021 and the current conflict between Russia and Ukraine have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (the “EIA”).
Nine Months Ended September 30, 2022 | Nine Months Ended September 30, 2021 | |||||||||||
High |
| Low | High |
| Low | |||||||
Oil ($/Bbl) | $ | 123.64 | $ | 75.99 | $ | 75.54 | $ | 47.47 | ||||
Natural gas ($/MMBtu) | $ | 9.85 | $ | 3.73 | $ | 23.86 | $ | 2.43 | ||||
On October 28, 2022, the West Texas Intermediate posted price for crude oil was $87.85 per Bbl and the Henry Hub spot market price of natural gas was $5.02 per MMBtu.
The following table, as reported by the EIA, sets forth the average daily prices for oil and natural gas.
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
2022 |
| 2021 | 2022 |
| 2021 | ||||||||
Oil ($/Bbl) | $ | 93.06 | $ | 70.58 | $ | 98.96 | $ | 65.05 | |||||
Natural gas ($/MMBtu) | $ | 8.03 | $ | 4.35 | $ | 6.74 | $ | 3.61 | |||||
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 increased significantly to 745 active land rigs at September 30, 2022 compared to 513 active land rigs at September 30, 2021. The 745 active land rigs at September 30, 2022 increased by 2.1% from 730 active land rigs at June 30, 2022. The overall increase in rig count is primarily attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas prices and overall supply shortages.
The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated:
September 30, | ||||
Basin or Producing Region | 2022 | 2021 | ||
Permian Basin | 39 | 24 | ||
Mid‑Continent | 9 | 10 | ||
Haynesville | 18 | 16 | ||
Appalachia | 1 | — | ||
Bakken | 4 | 5 | ||
Eagle Ford | 6 | 5 | ||
Rockies | 1 | — | ||
Other | 1 | — | ||
Total | 79 | 60 | ||
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.
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The following table presents the breakdown of our revenue for the following periods:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2022 |
| 2021 | 2022 |
| 2021 | |||||||
Royalty income | ||||||||||||
Oil sales | 43 | % | 47 | % | 46 | % | 49 | % | ||||
Natural gas sales | 48 | % | 39 | % | 43 | % | 37 | % | ||||
NGL sales | 9 | % | 11 | % | 10 | % | 11 | % | ||||
Lease bonus and other income | — | % | 3 | % | 1 | % | 3 | % | ||||
100 | % | 100 | % | 100 | % | 100 | % | |||||
We have entered into oil and natural gas commodity derivative agreements, which extend through September 2024, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests.
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 depreciation and depletion expense, interest expense, income taxes, non cash unit based compensation, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of VIEs, which include general and administrative expense and interest income. 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.
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The tables below present a reconciliation of Adjusted EBITDA and cash available for distribution on common units to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated (unaudited).
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: | ||||||||||||
Net income | $ | 43,845,114 | $ | 7,466,496 | $ | 95,546,524 | $ | 11,714,289 | ||||
Depreciation and depletion expense | 11,326,791 |
| 8,828,517 | 33,359,915 | 25,076,429 | |||||||
Interest expense | 3,667,534 |
| 2,495,465 | 9,868,679 | 6,692,263 | |||||||
Cash distribution from affiliate | — | 174,636 | 385,326 | 664,916 | ||||||||
Income tax (benefit) expense | (224,883) | — | 1,850,357 | — | ||||||||
EBITDA | 58,614,556 |
| 18,965,114 | 141,010,801 | 44,147,897 | |||||||
Unit-based compensation | 2,981,903 |
| 2,760,528 | 8,125,736 | 8,196,939 | |||||||
(Gain) loss on derivative instruments, net of settlements | (13,388,100) | 11,251,770 | (1,271,103) | 34,969,324 | ||||||||
Cash distribution from affiliate | — | 314,786 | 473,812 | 500,389 | ||||||||
Equity income in affiliate | (23,727) | (261,336) | (3,658,460) | (719,958) | ||||||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in trust account | (1,188,256) | — | (1,512,777) | — | ||||||||
General and administrative expenses | 527,634 | — | 1,857,593 | — | ||||||||
Consolidated Adjusted EBITDA | 47,524,010 | 33,030,862 | 145,025,602 | 87,094,591 | ||||||||
Adjusted EBITDA attributable to noncontrolling interest | (5,954,026) | (9,610,844) | (18,187,707) | (26,699,083) | ||||||||
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | 41,569,984 | 23,420,018 | 126,837,895 | 60,395,508 | ||||||||
Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ||||||||||||
Cash interest expense | 2,624,190 | 1,426,409 | 7,024,551 | 3,774,193 | ||||||||
Cash distributions on Series A preferred units | — | 310,205 | — | 1,624,835 | ||||||||
Restricted units repurchased for tax withholding | — | — | — | 763,093 | ||||||||
Cash income tax expense | 1,024,000 | — | 3,067,374 | — | ||||||||
Distributions on Class B units | 8,211 | 17,610 | 34,032 | 59,170 | ||||||||
Cash available for distribution on common units | $ | 37,913,583 | $ | 21,665,794 | $ | 116,711,938 | $ | 54,174,217 | ||||
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Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2022 | 2021 | 2022 | 2021 | |||||||||
Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units: | ||||||||||||
Net cash provided by operating activities | $ | 51,550,250 | $ | 25,122,540 | $ | 128,005,890 | $ | 69,082,654 | ||||
Interest expense |
| 3,667,534 |
| 2,495,465 |
| 9,868,679 |
| 6,692,263 | ||||
Income tax (benefit) expense | (224,883) | — | 1,850,357 | — | ||||||||
Amortization of right-of-use assets | (80,541) | (75,593) | (237,839) |
| (221,294) | |||||||
Amortization of loan origination costs |
| (480,057) |
| (394,582) |
| (1,381,717) |
| (1,148,066) | ||||
Equity income in affiliate, net |
| 23,727 |
| 261,336 |
| 273,135 |
| 719,958 | ||||
Forfeiture of restricted units | — | — | 19,813 | — | ||||||||
Unit-based compensation |
| (2,981,903) |
| (2,760,528) |
| (8,125,736) |
| (8,196,939) | ||||
Gain (loss) on derivative instruments, net of settlements | 13,388,100 |
| (11,251,770) |
| 1,271,103 |
| (34,969,324) | |||||
Changes in operating assets and liabilities: | ||||||||||||
Oil, natural gas and NGL receivables |
| (7,208,042) |
| 6,964,956 |
| 11,240,327 |
| 13,130,343 | ||||
Accounts receivable and other current assets |
| 450,477 |
| (55,098) |
| (455,642) |
| 521,569 | ||||
Accounts payable |
| 678,811 |
| (133) |
| (63,161) |
| (139,753) | ||||
Other current liabilities |
| (1,240,468) |
| (1,417,494) |
| (3,099,504) |
| (1,552,405) | ||||
Operating lease liabilities | 81,597 | 76,015 | 241,314 |
| 228,891 | |||||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in trust account | 1,188,256 | — | 1,512,777 |
| — | |||||||
Other assets and liabilities | (198,302) | — | 91,005 |
| — | |||||||
EBITDA | 58,614,556 | 18,965,114 | 141,010,801 | 44,147,897 | ||||||||
Add: | ||||||||||||
Unit-based compensation |
| 2,981,903 |
| 2,760,528 |
| 8,125,736 |
| 8,196,939 | ||||
(Gain) loss on derivative instruments, net of settlements |
| (13,388,100) |
| 11,251,770 |
| (1,271,103) |
| 34,969,324 | ||||
Cash distribution from affiliate | — | 314,786 | 473,812 | 500,389 | ||||||||
Equity income in affiliate | (23,727) | (261,336) | (3,658,460) | (719,958) | ||||||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in Trust Account | (1,188,256) | — | (1,512,777) | — | ||||||||
General and administrative expenses | 527,634 | — | 1,857,593 | — | ||||||||
Consolidated Adjusted EBITDA | 47,524,010 | 33,030,862 | 145,025,602 | 87,094,591 | ||||||||
Adjusted EBITDA attributable to noncontrolling interest | (5,954,026) | (9,610,844) | (18,187,707) | (26,699,083) | ||||||||
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP | 41,569,984 | 23,420,018 | 126,837,895 | 60,395,508 | ||||||||
Adjustments to reconcile Adjusted EBITDA to cash available for distribution | ||||||||||||
Cash interest expense | 2,624,190 | 1,426,409 | 7,024,551 | 3,774,193 | ||||||||
Cash distributions on Series A preferred units | — | 310,205 | — | 1,624,835 | ||||||||
Restricted units repurchased for tax withholding | — | — | — | 763,093 | ||||||||
Cash income tax expense | 1,024,000 | — | 3,067,374 | — | ||||||||
Distributions on Class B units | 8,211 | 17,610 | 34,032 | 59,170 | ||||||||
Cash available for distribution on common units | $ | 37,913,583 | $ | 21,665,794 | $ | 116,711,938 | $ | 54,174,217 | ||||
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Factors Affecting the Comparability of Our Results to Our Historical 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 Activities
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 three and nine months ended September 30, 2022 and 2021 include the acquisition of all of the equity interests in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”).
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 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 significant 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. We did not record an impairment on our oil and natural gas properties for the three and nine months ended September 30, 2022 and 2021.
After evaluating certain external factors in 2020, we determined that we did not have reasonable certainty as to the timing of the development of the proved undeveloped (“PUD”) reserves and, therefore we did not book PUD reserves
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in our total estimated proved reserves as of September 30, 2022 or December 31, 2021 and we do not intend to book PUD reserves going forward. 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.
Results of Operations
The table below summarizes our revenue and expenses and production data for the periods indicated (unaudited).
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||
Operating Results: | ||||||||||||
Revenue | ||||||||||||
Oil, natural gas and NGL revenues | $ | 73,867,992 | $ | 47,638,423 | $ | 217,543,364 | $ | 122,844,684 | ||||
Lease bonus and other income | 171,702 | 1,722,508 | 2,039,154 | 3,013,041 | ||||||||
Loss on commodity derivative instruments, net | (1,116,722) | (17,566,617) | (40,194,369) | (45,919,531) | ||||||||
Total revenues | 72,922,972 | 31,794,314 | 179,388,149 | 79,938,194 | ||||||||
Costs and expenses | ||||||||||||
Production and ad valorem taxes |
| 4,518,580 |
| 3,104,502 |
| 13,542,285 |
| 8,100,733 | ||||
Depreciation and depletion expense |
| 11,326,791 |
| 8,828,517 |
| 33,359,915 |
| 25,076,429 | ||||
Marketing and other deductions |
| 3,068,244 |
| 2,996,434 |
| 10,639,314 |
| 8,842,942 | ||||
General and administrative expenses |
| 7,482,814 |
| 6,766,628 |
| 21,938,249 |
| 20,247,843 | ||||
Consolidated variable interest entities related: | ||||||||||||
General and administrative expense | 527,634 | — | 1,857,593 |
| — | |||||||
Total costs and expenses |
| 26,924,063 |
| 21,696,081 |
| 81,337,356 |
| 62,267,947 | ||||
Operating income |
| 45,998,909 |
| 10,098,233 |
| 98,050,793 |
| 17,670,247 | ||||
Other income (expense) | ||||||||||||
Equity income in affiliate | 23,727 | 261,336 | 3,658,460 | 719,958 | ||||||||
Interest expense |
| (3,667,534) |
| (2,495,465) |
| (9,868,679) |
| (6,692,263) | ||||
Other income (expense) | 76,873 |
| (397,608) |
| 4,043,530 |
| 16,347 | |||||
Consolidated variable interest entities related: | ||||||||||||
Interest earned on marketable securities in trust account | 1,188,256 | — | 1,512,777 |
| — | |||||||
Net income before income taxes | 43,620,231 | 7,466,496 | 97,396,881 | 11,714,289 | ||||||||
Income tax (benefit) expense | (224,883) | — | 1,850,357 | — | ||||||||
Net income | 43,845,114 | 7,466,496 | 95,546,524 | 11,714,289 | ||||||||
Distribution and accretion on Series A preferred units | — | (4,849,996) | — | (8,005,932) | ||||||||
Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interests in OpCo | (5,493,117) | (761,311) | (11,975,886) | (1,024,655) | ||||||||
Distribution on Class B units | (8,211) | (17,610) | (34,032) | (59,170) | ||||||||
Net income attributable to common units of Kimbell Royalty Partners, LP | $ | 38,343,786 | $ | 1,837,579 | $ | 83,536,606 | $ | 2,624,532 | ||||
Production Data: | ||||||||||||
Oil (Bbls) |
| 345,867 |
| 345,273 |
| 1,058,423 |
| 1,003,795 | ||||
Natural gas (Mcf) |
| 5,130,753 |
| 4,995,962 |
| 15,146,635 |
| 14,267,115 | ||||
Natural gas liquids (Bbls) |
| 177,651 |
| 184,591 |
| 558,806 |
| 525,486 | ||||
Combined volumes (Boe) (6:1) |
| 1,378,644 |
| 1,362,524 |
| 4,141,668 |
| 3,907,134 | ||||
Comparison of the Three Months Ended September 30, 2022 to the Three Months Ended September 30, 2021
Oil, Natural Gas and NGL Revenues
For the three months ended September 30, 2022, our oil, natural gas and NGL revenues were $73.9 million, an increase of $26.3 million from $47.6 million for the three months ended September 30, 2021. The increase in oil, natural gas and NGL revenues was primarily related to the increase in the average prices we received for oil, natural gas and NGL
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production, and to a lesser extent, an increase in production volumes for the three months ended September 30, 2022 as discussed below.
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 1,378,644 Boe or 14,985 Boe/d, for the three months ended September 30, 2022, an increase of 16,120 Boe or 175 Boe/d, from 1,362,524 Boe or 14,810 Boe/d, for the three months ended September 30, 2021. Our total production mix for the three months ended September 30, 2022 composed of approximately 62% from natural gas, 25% from oil and 13% from NGLs. The increase in production for the three months ended September 30, 2022 from September 30, 2021 was primarily attributable to production associated with the assets located in the Mid-Continent and Haynesville basins primarily as a result of the Cornerstone Acquisition, partially offset by a reduction in production in the remaining basins.
Our operators received an average of $92.65 per Bbl of oil, $6.92 per Mcf of natural gas and $35.50 per Bbl of NGL for the volumes sold during the three months ended September 30, 2022 compared to $67.47 per Bbl of oil, $3.82 per Mcf of natural gas and $28.42 per Bbl of NGL for the volumes sold during the three months ended September 30, 2021. These average prices received during the three months ended September 30, 2022 increased 37.3% or $25.18 per Bbl of oil and 81.2% or $3.10 per Mcf of natural gas as compared to the three months ended September 30, 2021. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 31.9% or $22.48 per Bbl of oil and 84.6% or $3.68 per Mcf of natural gas for the comparable periods.
Lease Bonus and Other Income
Lease bonus and other income was $0.2 million for the three months ended September 30, 2022 compared to $1.7 million for the three months ended September 30, 2021. Lease bonus and other income for the three months ended September 30, 2021 included a $1.5 million lease bonus received related to properties in the Permian Basin.
Loss on Commodity Derivative Instruments
Loss on commodity derivative instruments for the three months ended September 30, 2022 included $16.7 million of mark-to-market gains and $17.8 million of losses on the settlement of commodity derivative instruments compared to $11.2 million of mark-to-market losses and $6.4 million of losses on the settlement of commodity derivative instruments for the three months ended September 30, 2021. We recorded a mark-to-market gain for the three months ended September 30, 2022 as a result of the maturity of derivative contracts with lower strike pricing. This gain was offset by the losses on the settlement of commodity derivative instruments. We recorded a mark-to-market loss for the three months ended September 30, 2021 as a result of the increase in strip pricing from the three months ended June 30, 2021 to the three months ended September 30, 2021.
Production and Ad Valorem Taxes
Production and ad valorem taxes for the three months ended September 30, 2022 were $4.5 million, an increase of $1.4 million from $3.1 million for the three months ended September 30, 2021. The increase in production and ad valorem taxes was primarily related to the significant increase in the average prices we received for oil, natural gas and NGL production for the three months ended September 30, 2022, and to a lesser extent, the Cornerstone Acquisition.
Depreciation and Depletion Expense
Depreciation and depletion expense for the three months ended September 30, 2022 was $11.3 million, an increase of $2.5 million from $8.8 million for the three months ended September 30, 2021. The increase in depreciation and depletion expense was due to Cornerstone Acquisition, which significantly increased our net capitalized oil and natural gas properties.
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 units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $8.06 for the three months ended September 30, 2022, an increase of $1.85 per barrel from the $6.21 average depletion rate per barrel for the three months ended September 30, 2021. The increase in the depletion rate was due to the Cornerstone
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Acquisition that was closed in December 2021 which significantly increased our net capitalized 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 three months ended September 30, 2022 remained flat at $3.1 million, compared to $3.0 million for the three months ended September 30, 2021.
General and Administrative Expenses
General and administrative expenses for the three months ended September 30, 2022 were $7.5 million, an increase of $0.7 million from $6.8 million for the three months ended September 30, 2021. 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 attributable to a $0.2 million increase in unit-based compensation expense and cash general and administrative expenses resulting from an increase in our costs associated with company growth.
Interest Expense
Interest expense for the three months ended September 30, 2022 was $3.7 million compared to $2.5 million for the three months ended September 30, 2021. The increase in interest expense was primarily due to debt incurred in 2021 to fund the redemption of the Series A preferred units and the Cornerstone Acquisition. Also contributing to the increase in interest expense was a 1.55% increase in the weighted average interest rate on the Partnership’s outstanding borrowings for the three months ended September 30, 2022.
Income Tax (Benefit) Expense
We recorded a benefit from income taxes of $0.2 million for the three months ended September 30, 2022. The benefit from income taxes recorded during the three months ended September 30, 2022 was due to a change in the estimated income tax expense for the year ended December 31, 2022.
Comparison of the Nine months ended September 30, 2022 to the Nine months ended September 30, 2021
Oil, Natural Gas and NGL Revenues
For the nine months ended September 30, 2022, our oil, natural gas and NGL revenues were $217.5 million, an increase of $94.7 million from $122.8 million for the nine months ended September 30, 2021. The increase in oil, natural gas and NGL revenues was primarily related to the increase in the average prices we received for oil, natural gas and NGL production, and to a lesser extent, an increase in production volumes for the nine months ended September 30, 2022 as discussed below.
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 4,141,668 Boe or 14,869 Boe/d, for the nine months ended September 30, 2022, an increase of 234,534 Boe or 557 Boe/d, from 3,907,134 Boe or 14,312 Boe/d, for the nine months ended September 30, 2021. Our total production mix for the nine months ended September 30, 2022 composed of approximately 61% from natural gas, 26% from oil and 13% from NGLs. The increase in production for the nine months ended September 30, 2022 from September 30, 2021 was primarily as a result of the Cornerstone Acquisition.
Our operators received an average of $94.84 per Bbl of oil, $6.23 per Mcf of natural gas and $40.71 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2022 compared to $61.99 per Bbl of oil, $3.28 per Mcf of natural gas and $26.27 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2021. These average prices received during the nine months ended September 30, 2022 increased 53.0% or $32.85 per Bbl of oil and 89.9% or $2.95 per Mcf of natural gas as compared to the nine months ended September 30, 2021. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 52.1% or $33.91 per Bbl of oil and 86.7% or $3.13 per Mcf of natural gas for the comparable periods.
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Lease Bonus and Other Income
Lease bonus and other income was $2.0 million for the nine months ended September 30, 2022 compared to $3.0 million for the nine months ended September 30, 2021. Lease bonus and other income for the nine months ended September 30, 2021 included a $1.5 million lease bonus received related to properties in the Permian Basin.
Loss on Commodity Derivative Instruments
Loss on commodity derivative instruments for the nine months ended September 30, 2022 included $3.0 million of mark-to-market losses and $43.2 million of losses on the settlement of commodity derivative instruments compared to $35.4 million of mark-to-market losses and $10.5 million of losses on the settlement of commodity derivative instruments for the nine months ended September 30, 2021. We recorded a mark-to-market loss for the nine months ended September 30, 2022 as a result of the increase in the strip pricing of oil and natural gas from December 31, 2021. We recorded a mark-to-market loss for the nine months ended September 30, 2021 as a result of the increase in strip pricing from December 31, 2020.
Production and Ad Valorem Taxes
Production and ad valorem taxes for the nine months ended September 30, 2022 were $13.5 million, an increase of $5.4 million from $8.1 million for the nine months ended September 30, 2021. The increase in production and ad valorem taxes was primarily related to the significant increase in the average prices we received for oil, natural gas and NGL production for the nine months ended September 30, 2022, and to a lesser extent, the Cornerstone Acquisition.
Depreciation and Depletion Expense
Depreciation and depletion expense for the nine months ended September 30, 2022 was $33.4 million, an increase of $8.3 million from $25.1 million for the nine months ended September 30, 2021. The increase in depreciation and depletion expense was due to Cornerstone Acquisition, which significantly increased our net capitalized oil and natural gas properties.
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 units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $7.84 for the nine months ended September 30, 2022, an increase of $1.66 per barrel from the $6.18 average depletion rate per barrel for the nine months ended September 30, 2021. The increase in the depletion rate was due to the Cornerstone Acquisition that was closed in December 2021 which significantly increased our net capitalized 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 nine months ended September 30, 2022 were $10.6 million, an increase of $1.8 million from $8.8 million for the nine months ended September 30, 2021. The increase in marketing and other deductions was primarily related to the significant increase in the average prices we received for oil, natural gas and NGL production for the nine months ended September 30, 2022, and to a lesser extent, the Cornerstone Acquisition.
General and Administrative Expenses
General and administrative expenses for the nine months ended September 30, 2022 were $21.9 million, an increase of $1.7 million from $20.2 million for the nine months ended September 30, 2021. The increase in general and administrative expenses was primarily attributable to legal and professional fees incurred related to the special meeting of unitholders of the Partnership in May 2022, at which our unitholders approved the adoption of our Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan and our Amended and Restated Agreement of Limited Partnership.
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Interest Expense
Interest expense for the nine months ended September 30, 2022 was $9.9 million compared to $6.7 million for the nine months ended September 30, 2021. The increase in interest expense was primarily due to debt incurred in 2021 to fund the redemption of the Series A preferred units and the Cornerstone Acquisition. Also contributing to the increase in interest expense was a 0.95% increase in the weighted average interest rate on the Partnership’s outstanding borrowings for the nine months ended September 30, 2022.
Income Tax (Benefit) Expense
We recorded an income tax expense of $1.9 million for the nine months ended September 30, 2022. The income tax expense recorded during the nine months ended September 30, 2022 was due to the significant increase in commodity prices which generated forecasted taxable net income for the year ended December 31, 2022.
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 for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. See “Indebtedness” below for further discussion of 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 the limited liability company agreement of the Operating Company and our partnership agreement. 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.
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the third quarter of 2022 for the repayment of $10.9 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the third quarter of 2022. 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.
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. 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
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(iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Quarterly Distributions” above for discussion of our third quarter 2022 distributions.
Cash Flows
The table below presents our cash flows for the periods indicated.
Nine Months Ended September 30, | ||||||
2022 |
| 2021 | ||||
Cash Flow Data: | ||||||
Net cash provided by operating activities | $ | 128,005,890 | $ | 69,082,654 | ||
Net cash used in investing activities |
| (233,997,215) |
| (755,777) | ||
Net cash provided by (used in) financing activities |
| 116,045,612 |
| (65,433,098) | ||
Net increase in cash and cash equivalents | $ | 10,054,287 | $ | 2,893,779 | ||
Operating Activities
Our operating cash flow is impacted by many variables, the most significant of which are 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 nine months ended September 30, 2022 were $128.0 million, an increase of $58.9 million compared to $69.1 million for the nine months ended September 30, 2021. The increase in cash flows provided by operating activities was primarily attributable to the increase in the average prices we received for oil, natural gas and NGL production for the nine months ended September 30, 2022.
Investing Activities
Cash flows used in investing activities for the nine months ended September 30, 2022 were $234.0 million compared to $0.8 million for the nine months ended September 30, 2021. For the nine months ended September 30, 2022, cash flows used in investing activities include $236.9 million of investments held in marketable securities related to TGR, $0.4 million used to fund costs associated with the Cornerstone Acquisition and $0.1 million used to fund the purchase of equipment, partially offset by $3.5 million in cash distributions received in connection to the joint venture with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP (the “Joint Venture”). For the nine months ended September 30, 2021, we used $0.7 million primarily to fund the renovation of office space and $0.5 million primarily to fund the acquisition of assets from Nail Bay Royalties, LLC and Oil Nut Bay Royalties, LP, partially offset by a $0.5 million cash distribution received in connection the Joint Venture during the period.
Financing Activities
Cash flows provided by financing activities were $116.0 million for the nine months ended September 30, 2022 compared to $65.4 million of cash flows used in financing activities for the nine months ended September 30, 2021. Cash flows provided by financing activities for the nine months ended September 30, 2022 consists of $227.6 million in proceeds from the initial public offering of TGR and $43.2 million of additional borrowings under our secured revolving credit facility, partially offset by $91.1 million of distributions paid to holders common units, OpCo common units and Class B units, $56.4 million used to repay borrowings under out secured revolving credit facility, $3.3 million of restricted units repurchased for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units, $0.3 paid in connection with fees related to our 2021 equity offering and $0.4 million payment of loan origination costs.
Cash flows used in financing activities for the nine months ended September 30, 2021 consists of $48.9 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $36.1 million to fund the redemption of Series A preferred units, $19.4 million used to repay borrowings under out secured revolving credit facility, $1.1 million of restricted units repurchased for tax withholding, $0.3 million payment of loan origination costs and $0.2 million paid in connection with the redemption of Class B units, partially offset by $40.6 million of additional borrowings under our secured revolving credit facility.
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Indebtedness
On June 7, 2022, the Partnership entered into Amendment No. 3 (the “Third Credit Agreement Amendment”) to the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (as amended by that certain Amendment No. 1 to Credit Agreement, dated as of July 12, 2018, and that certain Amendment No. 2 to Credit Agreement, dated as of December 8, 2020, and as otherwise amended or modified prior to such date, the “Credit Agreement” and the Credit Agreement, as amended by the Third Credit Agreement Amendment, the “Amended Credit Agreement”), with certain subsidiaries of the Partnership, as guarantors, the lenders party thereto and Citibank as administrative agent.
The Third Credit Agreement Amendment amended the Credit Agreement to, among other things, (i) increase (1) the aggregate elected commitments under the Amended Credit Agreement’s senior secured revolving credit facility (the “Credit Facility”) and (2) the borrowing base under the Credit Facility, in each case, from $275.0 million to $300.0 million and (ii) effect a transition of the benchmark interest rate from the London interbank offered rate (“LIBOR”) to the secured overnight financing rate (“SOFR”), by replacing the term “LIBOR” with the term “SOFR” for one, three or six month interest periods, plus a fixed credit spread adjustment of 10, 15 and 25 basis points for 1-month, 3-month and 6-month Term SOFR loans (as defined in the Amended Credit Agreement), respectively.
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 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 September 30, 2022, we had outstanding borrowings of $203.9 million under the secured revolving credit facility and $96.1 million of available capacity.
The 1-week and 2-month U.S. dollar LIBOR settings ceased to be published after December 31, 2021 and the U.K. Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S. dollar settings after September 30, 2023. In response, our secured revolving credit facility has transitioned to the use of the SOFR published by the Federal Reserve Bank of New York in replacement of LIBOR.
For additional information on our secured revolving credit facility, please read Note 8―Long-Term Debt to the unaudited interim consolidated financial statements included in this Quarterly Report.
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 estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units. We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2022. Our estimates regarding treatment of our distributions are based on currently available information only and are subject to change, including with respect to prior quarters.
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. Our estimates 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
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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.
New and Revised Financial Accounting Standards
The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies to our unaudited interim consolidated financial statements included elsewhere in this Quarterly Report.
Critical Accounting Policies and Related Estimates
Other than those noted below related to TGR, there have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our 2021 Form 10-K.
Consolidation
We analyze whether we have a variable interest in an entity and whether that entity is a VIE to determine whether we are required to consolidate those entities. We perform the variable interest analysis for all entities in which we have a potential variable interest, which primarily consist of all entities in which we serve as the sponsor, general partner or managing member, and general partner entities not wholly owned by us. If we have a variable interest in the entity and the entity is a VIE, we will also analyze whether we are the primary beneficiary of this entity and whether consolidation is required.
In evaluating whether we have a variable interest in the entity, we review the equity ownership and the extent to which we absorb the risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by us are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) our other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.
For entities determined to be VIEs, we must then evaluate whether we are the primary beneficiary of such VIEs. To make this determination, we evaluate our economic interests in the entity, specifically determining if we have both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, we consider the total economics of the entity, and analyze whether our share of the economics is significant. We utilize qualitative factors, and, where applicable, quantitative factors, while performing the analysis.
VIEs of which we are the primary beneficiary have been included in our consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.
Investments Held in Trust by Consolidated Variable Interest Entities
Investments held in trust represent an actively-traded money market fund of TGR, a consolidated special purpose acquisition company, which investments are invested in U.S. Treasury securities purchased with funds raised through the TGR IPO. Investments held in trust are classified as trading securities and are presented on the balance sheet at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in other income (expense)—interest earned on marketable securities in trust account on the accompanying unaudited
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interim consolidated statements of operations. The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy, as described in Note 5—Fair Value Measurements.
Redeemable Non-Controlling Interest
Redeemable non-controlling interests represent the shares of TGR Class A common stock sold in the TGR IPO that are redeemable for cash by the public shareholders concurrently with TGR’s initial business combination or in the event of TGR’s failure to complete the Business Combination or a tender offer. The redeemable non-controlling interests are initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. The carrying amount remains accreted to its full redemption value at September 30, 2022.
Management does not believe that any other recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our financial statements.
Contractual Obligations and Off-Balance Sheet Arrangements
There have been no significant changes to our contractual obligations previously disclosed in our 2021 Form 10-K. As of September 30, 2022, we did not have any off-balance sheet arrangements. See Note 7—Leases to the unaudited interim consolidated financial statements for additional information regarding our operating leases.
Item 3. 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 counterparties to the contracts are unrelated third parties.
Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pay 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 unaudited interim consolidated financial statements in Item 1 of this Quarterly 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 September 30, 2022, we had three counterparties to our derivative contracts, which are also lenders under our secured revolving credit facility.
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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. 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 September 30, 2022, we had total borrowings outstanding under our secured revolving credit facility of $203.9 million. The impact of a 1% increase in the interest rate on this amount of debt could result in an increase in interest expense of approximately $2.0 million annually, assuming that our indebtedness remained constant throughout the year.
On January 27, 2021, we entered into an interest rate swap with Citibank, which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility. On May 17, 2022 we entered into a partial termination agreement with Citibank to unwind 50% of the interest rate swap. On August 8, 2022, we entered into a termination agreement with Citibank to unwind the remaining 50% of the interest rate swap. The terminations resulted in a $3.4 million gain and $6.4 million gain for the three and nine months ended September 30, 2022, respectively, which is included in other income (expense) in the accompanying unaudited interim consolidated statements of operations. We used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted a portion of our secured revolving credit facility from a floating to a fixed rate.
Inflation
Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2021 through September 30, 2022. However, inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of the 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 such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act 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 and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that as of September 30, 2022, our disclosure controls and procedures were effective in ensuring that all information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to our General Partner’s management, including its principal executive officer and principal financial officer, in a manner that allows timely decisions regarding required disclosure.
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 September 30, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II – OTHER INFORMATION
Item 1. Legal Proceedings
For a description of the Partnership’s legal proceedings, see Note 15—Commitments and Contingencies to the unaudited interim consolidated financial statements included in Part I of this Quarterly Report and incorporated by reference herein.
Item 1A. Risk Factors
In addition to the risks and uncertainties discussed in this Quarterly Report, included in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks set out under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our 2021 Form 10-K. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of the current pandemic and the volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks. Further, these risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.
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Item 6. Exhibits
Exhibit |
| Description |
3.1 | — | |
3.2 | — | |
3.3 | — | |
3.4 | — | |
3.5 | — | |
31.1* | — | |
31.2* | — | |
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 |
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 |
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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: November 3, 2022 | By: | /s/ Robert D. Ravnaas | ||
Name: | Robert D. Ravnaas | |||
Title: | Chief Executive Officer and Chairman | |||
Principal Executive Officer | ||||
Date: November 3, 2022 |
| By: | /s/ R. Davis Ravnaas | |
Name: | R. Davis Ravnaas | |||
Title: | President and Chief Financial Officer | |||
Principal Financial Officer | ||||
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