Chesapeake Granite Wash Trust 10-K, filed Apr 1, 2024
Chesapeake Granite Wash Trust (CHKR)
10-K
2024-04-01
For: 2023-12-31
View Original
Added on
April 06, 2026
About this 10-K
Chesapeake Granite Wash Trust filed this 10-K on April 1, 2024, covering the fiscal year ended December 31, 2023.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2023
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to .
Commission File No. 001-35343
Chesapeake Granite Wash Trust
(Exact name of registrant as specified in its charter)
| Delaware | 45-6355635 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
| The Bank of New York Mellon Trust Company, N.A., Trustee Global Corporate Trust | ||||||||
| 601 Travis Street, Floor 16 | ||||||||
| Houston, Texas | 77002 | |||||||
| (Address of principal executive offices) | (Zip Code) | |||||||
| (Registrant’s telephone number, including area code) | ||
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Trading Symbol | Name on each exchange on which registered | ||||||||||||
| None | Not applicable | Not applicable | ||||||||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [ ] No [X]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [X] No [ ]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ ] No [X]
The registrant is a voluntary filer of reports required to be filed by certain companies under Section 13 or 15(d) of the Securities Exchange Act of 1934 and has filed all reports that would have been required to have been filed by the registrant during the preceding 12 months had it been subject to such filing requirements during the entirety of such period.
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). Yes [ ] No [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer [ ] | Accelerated filer [ ] | Non-accelerated filer [X] | Smaller reporting company [ ] | Emerging growth company [ ] | ||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements
of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X]
The aggregate market value of the 23,000,000 Common Units representing beneficial interests in Chesapeake Granite Wash Trust held by non-affiliates of the registrant, computed using the closing sale price of $1.18 on June 30, 2023, was approximately $27.14 million.
As of March 28, 2024, 46,750,000 Common Units representing beneficial interests in Chesapeake Granite Wash Trust were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Listed below is the only document parts of which are incorporated herein by reference and the parts of this Annual Report into which the document is incorporated:
None
CHESAPEAKE GRANITE WASH TRUST
2023 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
| PART I | Page | |||||||
| Item 1. | ||||||||
| Item 1A. | ||||||||
| Item 1B. | ||||||||
Item 1C. | ||||||||
| Item 2. | ||||||||
| Item 3. | ||||||||
| Item 4. | ||||||||
| PART II | ||||||||
| Item 5. | ||||||||
| Item 6. | ||||||||
| Item 7. | ||||||||
| Item 7A. | ||||||||
| Item 8. | ||||||||
| Item 9. | ||||||||
| Item 9A. | ||||||||
| Item 9B. | ||||||||
| Item 9C. | ||||||||
| PART III | ||||||||
| Item 10. | ||||||||
| Item 11. | ||||||||
| Item 12. | ||||||||
| Item 13. | ||||||||
| Item 14. | ||||||||
| PART IV | ||||||||
| Item 15. | ||||||||
| Item 16. | ||||||||
All references to “we,” “us,” “our,” or the “Trust” refer to Chesapeake Granite Wash Trust. The royalty interests conveyed on November 16, 2011 by Chesapeake Energy Corporation from its interests in certain properties in the Colony Granite Wash formation in Oklahoma and held by the Trust are referred to as the “Royalty Interests.” References to "Chesapeake" refer to Chesapeake Energy Corporation and, where the context requires, its subsidiaries. References to "Tapstone" refer to Tapstone Energy Holdings, LLC or its wholly owned subsidiary Tapstone Energy LLC, as applicable. References to "Diversified" refer to Diversified Energy Company PLC and, where the context requires, its subsidiaries. References to "Operator" refer to (i) Diversified Energy Company PLC and, where the context requires, its subsidiaries at all times after consummation of the Merger (as defined below), (ii) Tapstone Energy, LLC at all times from December 11, 2020 and prior to the consummation of the Merger, and (iii) Chesapeake at all times prior to December 11, 2020. Commencing as of December 7, 2021, Diversified, through Tapstone, its wholly owned subsidiary, owns and operates all Underlying Properties (as defined below) held by the
Trust. Additional information about Diversified, including its presentation of the Merger is available on Diversified's website at www.div.energy.
RISK FACTOR SUMMARY
Our business involves certain risks and uncertainties. The following is a description of significant risks that might cause our future financial condition or results of operations to differ materially from those expected. In addition to the risks and uncertainties described below, we may face other risks and uncertainties, some of which may be unknown to us and some of which we may deem immaterial. A summary of our risk factors is as follows (capitalized terms being defined in the Glossary below):
•Producing oil, natural gas, and NGL on the Underlying Properties is a high-risk activity with many uncertainties.
•Oil, natural gas, and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on proceeds to the Trust and cash distributions to unitholders.
•Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
•The sale of the Underlying Properties of the Trust may result in the ownership and management of the Trust by a party that is unfamiliar with the operation of the Trust or the Underlying Properties.
•Due to the Trust's lack of industry and geographic diversification, adverse developments in the Trust's existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.
•The generation of proceeds for distribution by the Trust depends in part on access to and the operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil, natural gas and NGL production from the Underlying Properties.
•The Trust units may lose value and cash available for distribution may be reduced as a result of title deficiencies with respect to the Underlying Properties.
•The oil, natural gas and NGL reserves estimated to be attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time.
•An increase in the differential between the prices realized by the Operator for oil, natural gas and NGL produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of Trust units.
•Oil and natural gas producing operations can be hazardous and may expose the Operator to liabilities.
•Climate change and the effects of energy transition could result in significant operational changes and expenditures, reduce demand for our services and adversely affect business.
•Negative public perception regarding the Operator or the oil and gas industry could have an adverse effect on the Operator's operations.
•Increases in interest rates may cause the value of the Trust units to decline.
•The amount of cash available for distribution by the Trust will be reduced by post-production expenses and applicable taxes associated with the Royalty Interests and Trust expenses.
•The Trust is passive in nature and will have no voting rights in the Operator managerial, contractual or other ability to influence the Operator, or control over the field operations of, sales of oil, natural gas and NGL from, or development of, the Underlying Properties.
•Financial information of the Trust is not prepared in accordance with U.S. GAAP.
•The Trust is precluded from acquiring other oil and natural gas properties or royalty interests to replace the depleting assets and production.
•The Trustee may, under certain circumstances, sell the Royalty Interests and dissolve the Trust.
•The Trust is administered by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
•Trust unitholders have limited ability to enforce provisions of the Royalty Interest conveyances, and the Operator's liability to the Trust is limited.
•Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
•Diversified may sell Trust units in the public or private markets and such sales could have an adverse impact on the trading price of the common units.
•Conflicts of interest could arise between the Operator and the Trust.
•The Operator may sell all or a portion of its retained interest in the Underlying Properties, subject to and burdened by the Royalty Interests.
•The Trust units are listed quoted for trading on the OTC Pink marketplace.
•The Operator is subject to extensive governmental regulation, including environmental, which can change and could adversely impact the Operator's business.
•The Trust could be negatively affected by cybersecurity threats.
•The Trust's tax treatment depends on its status as a partnership for U.S. federal income tax purposes.
•The U.S. federal income tax treatment of the Development Royalty Interest is not entirely free from doubt.
•The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.
•If the IRS contests the tax positions the Trust takes, the value of the Trust units may be adversely affected, the cost of any IRS contest will reduce the Trust's cash available for distribution to Trust unitholders.
•Trust unitholders will be required to pay taxes on their share of the Trust's income even if they do not receive any cash distributions from the Trust.
•Tax gain or loss on the disposition of the Trust units could be more or less than expected.
•Tax-exempt entities and non-U.S. persons face unique tax issues from owning the Trust units that may result in adverse tax consequences to them.
•The Trust will treat each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased.
•The Trust prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly record date in such quarter, instead of on the basis of the date a particular Trust unit is transferred.
•A Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of those Trust units.
•The Trust has adopted certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders.
•Trust unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in Trust units.
GLOSSARY OF CERTAIN TERMS
In this Annual Report, the following terms have the meanings specified below. Other terms are defined in the text of this Annual Report.
Administrative Servicer. The company providing the Trust with certain accounting, tax preparation, bookkeeping and information services related to the Royalty Interests and the Registration Rights Agreement in accordance with the Administrative Services Agreement (defined below). Pursuant to an agreement between Tapstone and Chesapeake following the divestiture of the Underlying Properties, (i) Chesapeake served as the Administrative Servicer through the filing of the 2020 Annual Report with the SEC and (ii) Tapstone is the Administrative Servicer for all periods subsequent to the filing of the 2020 Annual Report with the SEC. Following consummation of the Merger (as defined in Part I Item 1. Business), all duties previously performed by Tapstone and its subsidiaries with respect to the Trust are now performed by Diversified.
Administrative Services Agreement. An administrative services agreement the Trust entered into on November 16, 2011 with the Administrative Servicer, effective July 1, 2011, pursuant to which the Administrative Servicer provides the Trust with certain accounting, tax preparation, bookkeeping and information services related to the Royalty Interests and the Registration Rights Agreement.
AMI. The area of mutual interest, or AMI, lies within Washita County in western Oklahoma and is limited to the Colony Granite Wash formation in the area identified below, consisting of approximately 40,500 gross acres (26,400 net acres) held by Tapstone as of December 31, 2023.
Assignment Agreement. Assignment and Assumption Agreement, dated as of December 11, 2020, by and among Chesapeake, Chesapeake Exploration, L.L.C., Chesapeake E&P Holding, L.L.C., and Tapstone, pursuant to which Tapstone agreed to assume all duties and obligations of Chesapeake and its subsidiaries under each of the Trust Agreement, the Administrative Services Agreement, the royalty conveyances and the Registration Rights Agreement following the divestiture by Chesapeake of the Underlying Properties and 23,750,000 common units.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Boe. Barrel of oil equivalent. Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Despite holding this ratio constant at six mcf to one bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.
Btu. British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas or natural gas liquids, or in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at the original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development Costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to (a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (b) drill and equip Development Wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (c) acquire, construct and install production facilities such as leases, flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (d) provide improved recovery systems.
Development Well. As defined by the SEC, a development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. For the purposes of the Trust and as used herein, references to “Development Wells” refer to the 118 horizontal development wells that, since July 1, 2011, have been drilled on properties held by the Operator in the AMI and in which the Trust has received an interest.
Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Economically Producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue is determined at the terminal point of oil and gas producing activities as defined in Rule 4-10(a)(16) of Regulation S-X under the Securities Act.
Estimated Future Net Revenues. The result of applying current prices of oil, natural gas and NGL to estimated future production from oil, natural gas and NGL proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays or areas of interest.
GAAP. Generally Accepted Accounting Principles in the United States.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.
IRS. The Internal Revenue Service of the United States federal government.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mboe. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet.
Mmcf. One million cubic feet.
Net Acres or Net Wells. The sum of the fractional working interest owned in gross acres or gross wells, respectively.
Net Revenue Interest. A share of production after all burdens, such as royalty and overriding royalty interests, have been deducted from the working interest.
Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.
NYMEX. New York Mercantile Exchange.
Operator. The company that holds the AMI, owns the Underlying Properties and is bound by the terms of the Trust Agreement. Following the consummation of the Merger (as defined below), Diversified Energy Company PLC and, where the context requires, its subsidiaries, became the Operator.
Participation Agreement. Participation Agreement, dated October 2, 2020, by and between Operator and OCM Denali Holdings, LLC, which agreement was not in existence as of the date of the Conveyances and is a permitted encumbrance under the Conveyances. The agreement relates to the Underlying Properties.
Plugging and Abandoning. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Oklahoma regulations require plugging of abandoned wells.
Present Value of Estimated Future Net Revenues or PV-10 (non-GAAP). When used with respect to oil, natural gas and NGL reserves, present value of estimated future net revenues, or PV-10, means the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted net cash flows, or Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Because the Trust will not bear income tax expense, the PV-10 and Standardized Measure attributable to the Royalty Interests are the same.
Price Differential. The difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.
Producing Well. As defined by the SEC, a producing well is a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. For the purposes of the Trust and as used herein, references to “Producing Wells” refer to the 69 existing horizontal wells in which Chesapeake conveyed an interest to the Trust effective as of July 1, 2011.
Production Expenses. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil, natural gas and NGL produced. Examples of production expenses (sometimes called lifting expenses) are:
•costs of labor to operate the wells and related equipment and facilities;
•repairs and maintenance;
•materials, supplies and fuel consumed as well as supplies utilized in operating the wells and related equipment and facilities;
•property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and
•production taxes.
Some support equipment or facilities may serve two or more oil and natural gas producing activities and may also serve transportation, refining and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production expenses, as appropriate. Depreciation, depletion and amortization of capitalized acquisition, exploration, and development costs are not production expenses but also become part of the cost of oil and natural gas produced along with production (lifting) costs identified above.
Productive Well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
Prospectus. The Trust Prospectus dated November 10, 2011 and filed with the SEC on November 14, 2011, in connection with the initial public offering of the Trust's common units.
Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved Reserves. As used in this report, proved reserves has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved Undeveloped Reserves (PUDs). Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively high expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
Registration Rights Agreement. Registration Rights Agreement dated as of November 16, 2011, by and among Tapstone (as successor to Chesapeake and Chesapeake Exploration, L.L.C.) and the Trust.
Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
SEC. The United States Securities and Exchange Commission.
Standardized Measure. The discounted future net cash flows relating to proved reserves based on the means of the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period). The standardized measure differs from the PV-10 measure only because the former includes the effects of estimated future income tax expenses.
Underlying Properties. Interests in specified oil and natural gas properties located in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma.
Undeveloped Acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (“Annual Report” or "Form 10-K") includes “forward-looking statements” about the Trust and the Operator and other matters discussed herein that are subject to risks and uncertainties that are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical fact included in this document are forward-looking statements, including, without limitation, statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of Part II and “Risk Factors” in Item 1A of Part I and elsewhere herein regarding market factors, market prices, the proved oil, natural gas and NGL reserves associated with the properties underlying the Royalty Interests, the Trust’s or the Operator's future financial position, business strategy, budgets, projected costs and plans and objectives for future operations, information regarding target distributions, statements pertaining to future development activities and costs and information regarding production and reserve growth, statements regarding the continued trading of the Trust's common units on the Pink Open Market operated by OTC Markets Group, Inc. (the "OTC Pink"), statements regarding the expected impact of geopolitical events, including the ongoing conflicts in Ukraine and Israel, and actions by, or disputes among or between, members of the Organization of the Petroleum Exporting Countries and its allies, in each case on our and the Operator's business, financial condition, results of operations and cash flows. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “seek,” “plan,” “goal,” “assume,” “target,” “should,” “intend," "ability," "will," "would," "forecast" or other words that convey the uncertainty of future events or outcomes. Actual outcomes and results may differ materially from those projected. These forward-looking statements are based on certain assumptions made by the Trust, and by the Operator in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with such expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part I of this Annual Report, which could affect the future results of the energy industry in general, and the Trust and the Operator in particular, and could cause those results to differ materially from those expressed in such forward-looking statements. These factors should not be construed as exhaustive, and there may also be other risks that we are unable to predict at this time. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on the Operator's business and the Trust. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The Trustee relies on the Operator for information regarding the Royalty Interests, the Underlying Properties and the Operator itself. The Trust undertakes no obligation to publicly update or revise any forward-looking statements and expressly disclaims any obligation to do so, except as required by applicable law.
PART I
ITEM 1.Business
Introduction
The Trust is a statutory trust formed in June 2011 under the Delaware Statutory Trust Act pursuant to an initial trust agreement by and among the Operator, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust maintains its offices at the office of the Trustee, which is located at 601 Travis Street, Floor 16, Houston, Texas 77002, and the telephone number of the Trustee is (512) 235-6555.
The Trustee maintains a website for filings by the Trust with the SEC. Electronic filings by the Trust with the SEC are available free of charge through the Trust's website at www.chkgranitewashtrust.com and through the SEC's website at www.sec.gov. The Trust will also provide electronic and paper copies of its recent filings free of charge upon request to the Trustee. Documents and information on the Trust's website are not incorporated by reference herein.
General
The Trust was created to own the Royalty Interests for the benefit of Trust unitholders pursuant to a trust agreement dated as of June 29, 2011 and subsequently amended and restated as of November 16, 2011 by and among Tapstone (as successor to Chesapeake and Chesapeake Exploration, L.L.C., a wholly owned subsidiary of Chesapeake), the Trustee and the Delaware Trustee (the “Trust Agreement”). The Royalty Interests are derived from the Underlying Properties. Chesapeake conveyed the Royalty Interests to the Trust from Chesapeake's interests in the Producing Wells and the Development Wells.
The business and affairs of the Trust are managed by the Trustee. The Trust Agreement limits the Trust's business activities generally to owning the Royalty Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances applicable to the Royalty Interests. The royalty interests in the Producing Wells (the “PDP Royalty Interest”) entitle the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to the Operator's net revenue interest in the Producing Wells. The royalty interests in the Development Wells (the “Development Royalty Interest”) entitle the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to the Operator's net revenue interest in the Development Wells.
Through an initial public offering in November 2011, the Trust sold to the public 23,000,000 common units, representing beneficial interests in the Trust, for cash proceeds of approximately $409.7 million, net of offering costs. The Trust delivered the net proceeds of the initial public offering, along with 12,062,500 common units and 11,687,500 subordinated units, to certain wholly owned subsidiaries of Chesapeake in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions, there were 46,750,000 Trust units issued and outstanding, consisting of 35,062,500 common units and 11,687,500 subordinated units, which were converted into common units on a one-for-one basis as of June 30, 2017. On December 11, 2020, Chesapeake sold its 23,750,000 common units to Tapstone in a sale that included the Underlying Properties of the Trust.
On October 6, 2021, Tapstone Energy Holdings, LLC, a Delaware limited liability company and the parent of Tapstone, ("Tapstone Holdings"), entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Diversified, the parent of Diversified Production LLC (“Diversified Production”), and certain of its affiliates, including Diversified Production. Upon the terms and subject to the conditions set forth in the Merger Agreement, a wholly owned subsidiary of Diversified merged with and into Tapstone Holdings with Tapstone Holdings as the surviving entity, resulting in Tapstone Holdings and Tapstone becoming wholly owned subsidiaries of Diversified. The transactions provided for under the Merger Agreement were consummated on December 7, 2021, and Tapstone Holdings became a wholly owned subsidiary of Diversified on such date (the “Merger”). Following the Merger, the 23,750,000 common units previously held by Tapstone Energy LLC were transferred to Diversified Production, another indirect, wholly-owned subsidiary of Diversified. Subsequently, on September 22, 2023, the 23,750,000
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common units were transferred to DP Bluegrass LLC ("DP Bluegrass"), an indirect, wholly-owned subsidiary of Diversified Production.
Following consummation of the Merger, duties previously performed by Tapstone and its subsidiaries with respect to the Trust are now performed by Diversified.
Tapstone’s right, title and interest in and to, and all of their duties and obligations under all documents related to the Trust (including the Amended and Restated Trust Agreement (dated as of November 16, 2011), the Administrative Services Agreement (dated as of November 16, 2011) and the related royalty interest conveyances) remain unchanged as a result of the Merger, although there have been certain changes in the management of the Underlying Properties. However, as a result of the Merger, Diversified may be deemed the beneficial owner of the 23,750,000 common units of the Trust, now held by DP Bluegrass, representing the entire 50.8% beneficial ownership interest in the Trust held by Tapstone immediately prior to the effective time of the Merger.
Neither the Trust nor the Trustee is responsible for, or has any control over, any operating or capital costs of the Underlying Properties. The Trust's cash receipts with respect to the Royalty Interests in the Underlying Properties are determined after deducting certain post-production expenses and any applicable taxes associated with the Royalty Interests. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil, natural gas and NGL produced. However, the Trust is not responsible for costs of marketing services provided by affiliates of the Operator. Cash distributions to unitholders will continue to be reduced by the Trust's general and administrative expenses.
The Trust will dissolve and begin to liquidate on June 30, 2031 (the “Termination Date”), or earlier upon certain events, and will soon thereafter wind up its affairs and terminate. At the Termination Date, (a) 50% of the total Royalty Interests conveyed by the Operator (the “Term Royalties”) will revert automatically to the Operator and (b) 50% of the total Royalty Interests conveyed by the Operator (the “Perpetual Royalties”) will be retained by the Trust and thereafter sold. The net proceeds of the sale of the Perpetual Royalties, as well as any remaining Trust cash reserves, will be distributed to the unitholders on a pro rata basis. The Operator will have a right of first refusal to purchase the Perpetual Royalties retained by the Trust at the Termination Date.
The Trust is required to make quarterly cash distributions of substantially all of its quarterly cash receipts, after deducting the Trust's administrative expenses and any cash reserves, on or about 60 days following the completion of each quarter through (and including) the quarter ending June 30, 2031. Quarterly distributions to Trust unitholders will generally include royalty income attributable to sales of oil, natural gas and NGL for three months, including the first two months of the quarter just ended and the last month of the quarter prior to that one. The first quarterly distribution was made on December 28, 2011 to record unitholders as of December 15, 2011.
Actual cash distributions to the Trust unitholders will fluctuate quarterly based on the quantity of oil, natural gas, and NGL sold from the Underlying Properties, the prices received for such sales, the timing of the Operator's receipt of payment for such sales, the Trust's expenses and other factors. Target distributions will decline over time as a result of the depletion of the reserves in the Underlying Properties.
For the year ended December 31, 2023, the Trust declared and paid the following cash distributions:
| Production Period | Distribution Date | Cash Distribution per Common Unit | ||||||||||||||||||||||||
| June 2023 – August 2023 | November 30, 2023 | $ | 0.0336 | |||||||||||||||||||||||
| March 2023 - May 2023 | August 31, 2023 | $ | 0.0178 | |||||||||||||||||||||||
| December 2022 - February 2023 | June 1, 2023 | $ | 0.0487 | |||||||||||||||||||||||
| September 2022 - November 2022 | March 1, 2023 | $ | 0.0757 | |||||||||||||||||||||||
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Subsequent Distribution. The Trust's quarterly income available for distribution was $0.0214 per common unit for the production period from September 1, 2023 to November 30, 2023. On February 5, 2024, the Trust declared a cash distribution of $0.0214 per common unit attributable to such production period. The distribution was paid on February 29, 2024 to record unitholders as of February 19, 2024. All Trust unitholders share on a pro rata basis in the Trust's distributable income.
As of March 28, 2024, DP Bluegrass held 23,750,000 common units, which represent 50.8% of the outstanding Trust units. Diversified is the ultimate parent company of DP Bluegrass, and therefore is deemed to beneficially own the common units held by DP Bluegrass.
Administrative Services Agreement
In return for the services provided by the Administrative Servicer under the Administrative Services Agreement, the Trust pays the Administrative Servicer an annual fee of $200,000, which is paid in equal quarterly installments and remains fixed for the life of the Trust. The Administrative Servicer is also entitled to receive reimbursement for its actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement.
The Administrative Services Agreement will terminate upon the earliest to occur of (a) the date the Trust shall have been wound up in accordance with the Trust Agreement, (b) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (c) with respect to services to be provided with respect to any Underlying Properties being transferred by the Operator, the date that either the Administrative Servicer or the Trustee may designate by delivering 90-days prior written notice, provided that the transferee of such Underlying Properties assumes responsibility to perform the services in place of the Administrative Servicer or (d) a date mutually agreed by the Administrative Servicer and the Trustee.
Description of the Trust
Common Units. Each Trust unit is a unit of the beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. The Trust has 46,750,000 Trust units issued and outstanding, all of which are common units.
Distributions and Income Computations. The Trust is required to make quarterly cash distributions to unitholders from its available funds for such calendar quarter. Royalty Interest payments due to the Trust with respect to any calendar quarter are based on actual sales volumes attributable to the Trust's interests in the Underlying Properties (as measured at the Operator's metering systems) for the first two months of the quarter just ended as well as the last month of the immediately preceding quarter and actual revenues, net of post-production expenses received for such volumes. The Operator makes the Royalty Interest payments to the Trust within 35 days of the end of each calendar quarter. Taking into account the receipt and disbursement of all such amounts, the Trustee determines for such calendar quarter the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust over the Trust's expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities.
The Trustee distributes cash approximately 60 days (or the next succeeding business day following such day if such day is not a business day) following each calendar quarter to each person who is a Trust unitholder of record on the quarterly record date together with interest expected to be earned on the amount of such quarterly distribution from the date of receipt thereof by the Trustee to the payment date.
Unless otherwise advised by counsel or the IRS, the Trustee treats the income and expenses of the Trust for each quarter as belonging to the Trust unitholders of record on the quarterly record date that occurs in such quarter. Trust unitholders recognize income and expenses for tax purposes in the quarter the Trust receives or pays those amounts, rather than in the quarter the Trust distributes them. Minor variances may occur. For example, the Trustee could establish a reserve in one quarter that would not result in a tax deduction until a later quarter. The Trustee could also make a payment in one quarter that would be amortized for tax purposes over several months.
Transfer of Trust Units. Trust unitholders may transfer their Trust units in accordance with the Trust Agreement. The Trustee does not require either the transferor or transferee to pay a service charge for any transfer of a Trust unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any Trust unit as shown by its records as the owner of the Trust unit. The Trustee will not be
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considered to know about any claim or demand on a Trust unit by any party except the record owner. A person who acquires a Trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of Trust units.
Periodic Reports. The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust unitholders a Schedule K-1 and also causes to be prepared and filed reports required to be filed under the Exchange Act, and by the rules any securities exchange or quotation system on which the Trust units are listed or admitted to trading.
Each Trust unitholder and his representatives have the right, at his own expense and during reasonable business hours upon reasonable prior notice, to examine and inspect the records of the Trust and the Trustee in reference thereto for any purpose reasonably related to the Trust unitholder's interest as a Trust unitholder.
Liability of Trust Unitholders. Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
Voting Rights of Trust Unitholders. The Trustee or Trust unitholders owning at least 10% of the outstanding Trust units may call meetings of Trust unitholders. The Trust does not intend to hold annual meetings of the Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders unless such meeting is called by the Trust unitholders, in which case the Trust unitholders are responsible for all costs associated with calling such meeting of Trust unitholders. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.
Unless otherwise required by the Trust Agreement, a matter may be approved or disapproved by the vote of a majority of the Trust units held by the Trust unitholders voting in person or by proxy at a meeting where there is a quorum. Accordingly, a matter may be approved even if a majority of the total outstanding Trust units does not approve it.
Until such time as Diversified and its affiliates own less than 10% of the outstanding Trust units, the affirmative vote of the holders of a majority of common units (excluding common units owned by Diversified and its affiliates) and a majority of Trust units voting in person or by proxy at a meeting of such holders at which a quorum is present is required to:
•dissolve the Trust (except in accordance with its terms);
•remove the Trustee or the Delaware Trustee;
•amend the Trust Agreement, the royalty conveyances, the Administrative Services Agreement and the development agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any material respect);
•merge, consolidate or convert the Trust with or into another entity; or
•approve the sale of all or any material part of the assets of the Trust.
At any time when Diversified and its affiliates own less than 10% of the outstanding Trust units, the vote of the holders of a majority of Trust units, including units owned by Diversified, voting in person or by proxy at a meeting of such holders at which a quorum is present will be required to take the actions described above. Notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units.
Certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders. The Trustee must consent before all or any part of the Trust assets can be sold except in connection with the dissolution of the Trust or limited sales directed by Diversified in conjunction with its sale of Underlying Properties.
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Description of the Trust Agreement. The Trust was created under Delaware law as a separate legal entity to acquire and hold the Royalty Interests for the benefit of the Trust unitholders pursuant to the Trust Agreement among the Operator, the Trustee and the Delaware Trustee. The Royalty Interests are passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. Neither the Operator nor other operators of the Underlying Properties have any contractual commitments to the Trust to provide additional funding for, to conduct further drilling on or to maintain their ownership interest in any of these properties.
The Trust Agreement provides that the Trust's business activities are generally limited to owning the Royalty Interests and any activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not generally permitted to acquire other oil, natural gas and NGL properties or royalty interests. The Trust is not able to issue any additional Trust units.
Contractual Rights and Assets of the Trust. Contractual rights of the Trust include those contained in the development agreement and the Administrative Services Agreement. The assets of the Trust consist of the Royalty Interests and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the Trust unitholders.
Duties and Powers of the Trustee. The duties and powers of the Trustee are specified in the Trust Agreement and by the laws of the State of Delaware, except as modified by the Trust Agreement. The Trust Agreement provides that the Trustee shall not have any duties or liabilities, including fiduciary duties, except as expressly set forth in the Trust Agreement and the duties and liabilities of the Trustee as set forth in the Trust Agreement replace any other duties and liabilities, including fiduciary duties, to which the Trustee might otherwise be subject.
The Trustee's principal duties consist of:
•collecting cash proceeds attributable to the Royalty Interests;
•paying expenses, charges and obligations of the Trust from the Trust's assets;
•making cash distributions to the unitholders and the Operator (with respect to incentive distributions) in accordance with the Trust Agreement;
•causing to be prepared and distributed a Schedule K-1 for each Trust unitholder and preparing and filing tax returns on behalf of the Trust; and
•causing to be prepared and filed reports required to be filed under the Exchange Act, and by the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading.
The Administrative Servicer will provide administrative and other services to the Trust in fulfillment of certain of the foregoing duties pursuant to the Administrative Services Agreement.
The Trustee may create a cash reserve to pay for future expenses of the Trust. If the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust's expenses, the Trustee may cause the Trust to borrow funds required to pay the expenses. The Trust may borrow the funds from any person, including the Trustee or its affiliates or, as described below, the Operator. The terms of such indebtedness, if funds were loaned by the entity serving as Trustee or Delaware Trustee, must be similar to the terms which such entity would grant to a similarly situated, unaffiliated commercial customer, and such entity shall be entitled to enforce its rights with respect to any such indebtedness as if it were not then serving as Trustee or Delaware Trustee. If the Trust borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid (except in certain circumstances where the Trust borrows funds from the Operator).
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Each quarter, the Trustee will pay Trust obligations and expenses and distribute to the Trust unitholders the remaining proceeds received from the Royalty Interests. The cash held by the Trustee as a reserve against future liabilities must be invested in:
•interest-bearing obligations of the U.S. government;
•money market funds that invest only in U.S. government securities;
•repurchase agreements secured by interest-bearing obligations of the U.S. government; or
•bank certificates of deposit.
Alternatively, cash held for distribution at the next distribution date may be held in a non-interest bearing account.
The Trustee withheld approximately $1.0 million from the first distribution to establish an initial cash reserve available for Trust expenses. If the Trustee uses its cash reserve (or any portion thereof) to pay or reimburse Trust liabilities or expenses, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until the cash reserve is replenished. Additional cash reserves may also be established from time to time as determined by the Trustee to pay for future expenses of the Trust. This cash reserve will be part of the Trust estate and will bear interest at the same rate as other cash on hand in the Trust estate. Upon the dissolution of the Trust, after payment of Trust liabilities, the balance of the cash reserve (including accrued interest thereon) will be distributed to Trust unitholders on a pro rata basis.
The Trust may not acquire any asset except the Royalty Interests, the other assets described above under Contractual Rights and Assets of the Trust and cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.
The Trust Agreement provides that the Trustee will not make business decisions affecting the assets of the Trust. However, the Trustee may:
•prosecute or defend, and settle, claims of or against the Trust or its agents;
•retain professionals and other third parties to provide services to the Trust;
•charge for its services as Trustee;
•retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the Trustee to the extent permitted by law);
•lend funds at commercial rates to the Trust to pay the Trust's expenses; and
•seek reimbursement from the Trust for its out-of-pocket expenses.
In discharging its duty to Trust unitholders, the Trustee may act in its discretion and will be liable to the Trust unitholders only for willful misconduct, bad faith or gross negligence, and certain taxes, fees and other charges based on fees, commissions or compensation received by the Trustee in connection with the transactions contemplated by the Trust Agreement. The Trustee is not liable for any act or omission of its agents or employees unless the Trustee acts with willful misconduct, bad faith or gross negligence in its selection and retention. The Trustee will be indemnified individually or as the Trustee for any liability or cost that it incurs in the administration of the Trust, except in cases of willful misconduct, bad faith or gross negligence. The Trustee has a lien on the assets of the Trust as security for this indemnification and its compensation earned as Trustee. Trust unitholders are not liable to the Trustee for any indemnification. The Trustee is obligated to ensure that all contractual liabilities of the Trust are limited to the assets of the Trust.
The Trust may merge or consolidate with or into, or convert into, one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the Trustee and approved by the vote of the holders of a majority of the Trust units and a majority of the common units (excluding common units owned by Diversified and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law. At any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, however, the standard for approval will be the vote of a majority of the Trust units, including units owned by Diversified voting in person or by proxy at a meeting of such holders at which a quorum is present. Notwithstanding the foregoing, there are conflicting interpretations that
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the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units.
Trustee's Power to Sell Trust Assets. The Trustee may sell Trust assets, including the Royalty Interests, under any of the following circumstances:
•the sale is requested by Diversified, in accordance with the provisions of the Trust Agreement; or
•the sale is approved by the vote of holders representing a majority of the Trust units and a majority of the common units (excluding common units owned by Diversified and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be the vote of a majority of the Trust units, including units owned by Diversified voting in person or by proxy at a meeting of such holders at which a quorum is present. Notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units.
Upon dissolution of the Trust, the Trustee must sell the remaining Royalty Interests. No Trust unitholder approval is required in this event.
The Trustee will distribute the net proceeds from any sale of the Royalty Interests and other assets to the Trust unitholders after payment or reasonable provision for payment of the liabilities of the Trust.
Dispute Resolution. To the fullest extent permitted by law, any dispute, controversy or claim that may arise between the Operator and the Trustee relating to the Trust will be submitted to binding arbitration before a panel of three arbitrators.
Trust Fees and Expenses. It is expected that the Trust will only incur liabilities for routine administrative expenses, such as legal, accounting, audit, tax advisory, engineering, printing and other administrative and out-of-pocket fees and expenses incurred by or at the direction of the Trustee or the Delaware Trustee, including tax return and Schedule K-1 preparation and mailing costs; independent auditor fees; and registrar and transfer agent fees. The Trust is also responsible for paying costs associated with annual and quarterly reports to unitholders. Moreover, the Trustee's and the Delaware Trustee's compensation, and the fee payable to the Administrative Servicer pursuant to the Administrative Services Agreement, are paid out of the Trust's assets.
The Operator's Obligation to Fund Trust Expenses in Certain Circumstances. The Operator has agreed that, if at any time the Trust's cash on hand (including available cash reserves) is not sufficient to pay the Trust's ordinary course expenses as they become due, the Operator will lend funds to the Trust necessary to pay such expenses. Any funds loaned by the Operator pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other accrued current liabilities arising in the ordinary course of the Trust's business, and may not be used to satisfy Trust indebtedness for borrowed money. If the Operator lends funds pursuant to this commitment, unless the Operator agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. Any such loan will be on an unsecured basis. There were no loans outstanding as of December 31, 2023 or December 31, 2022.
Duration of the Trust; Sale of Royalty Interests. The Trust will dissolve and begin to liquidate on the Termination Date, or earlier upon the occurrence of certain events, and will soon thereafter wind up its affairs and terminate. At the Termination Date, the Term Royalties will revert automatically to the Operator. Following the Termination Date, the Perpetual Royalties will be sold by the Trust and the net proceeds of the sale, as well as any remaining Trust cash reserves, will be distributed to the unitholders pro rata. The Operator will have a right of first refusal to purchase the Perpetual Royalties from the Trust following the Termination Date.
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The Trust will not dissolve until the Termination Date, unless:
•the Trust sells all of the Royalty Interests;
•the aggregate quarterly cash distribution amounts for any four consecutive quarters is less than $1.0 million;
•the holders of a majority of the Trust units and a majority of the common units (excluding common units owned by Diversified and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present vote in favor of dissolution; except that at any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be a majority of the Trust units, including units owned by Diversified, voting in person or by proxy at a meeting of such holders at which a quorum is present; notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units; or
•the Trust is judicially dissolved.
In the case of any of the foregoing, the Trustee would sell all of the Trust's assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders after payment, or reasonable provision for payment, of all Trust liabilities.
Federal Income Tax Considerations
The Trust's federal income tax reporting position is that it is classified as a partnership for federal and applicable state income tax purposes. This position relies on the opinion of Bracewell LLP, former counsel to the Operator and the Trust, rendered in connection with the initial public offering of the Trust units in 2011, in which counsel opined that at least 90% of the Trust's gross income is qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended. The Trust's federal income tax reporting positions are consistent with the Federal Income Tax Considerations section in the Prospectus filed by the Trust with the SEC on November 14, 2011, in connection with the initial public offering of its common units (the “Federal Income Tax Considerations Section in the Prospectus”). However, as discussed in detail below under Item 1A. Risk Factors – Tax Risks Related to the Units, the Trust has not requested a ruling from the IRS regarding its U.S. federal income tax reporting positions and its positions may not be sustained by a court or if contested by the IRS.
Additional information regarding the opinion and material tax matters is discussed in the Federal Income Tax Considerations Section in the Prospectus.
Competition and Markets
The oil and natural gas industry is highly competitive. The Operator competes with both major integrated and other independent oil and natural gas companies in all aspects of its business to explore, develop and operate its properties and market its production. Some of the Operator's competitors may have larger financial and other resources than the Operator. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of the Operator's competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities, and overall economic conditions. The Operator also faces indirect competition from alternative energy sources, including wind, solar and electric power. The Operator believes that its technological expertise, combined with its exploration, land, drilling and production capabilities and the experience of its management team enable it to compete effectively.
Recent volatility in oil, natural gas and NGL prices has impacted, and will continue to directly impact, Trust distributions, estimates of reserves attributable to the Trust's interest, and estimated and actual future net revenues to the Trust. In view of the many uncertainties that affect the supply and demand for oil, natural gas and NGL, neither the Trust nor the Operator can make reliable predictions of future supply and demand for oil, natural gas and NGL, future oil, natural gas and NGL prices or the effect of future oil, natural gas and NGL prices on the Trust.
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Public Policy and Government Regulation
All of the Operator's operations are conducted onshore in the United States. The U.S. oil and natural gas industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations that are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. The Operator has advised the Trustee that the Operator actively monitors regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following are significant areas of government control and regulation affecting the Operator's operations.
Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations
The Operator's operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
•reporting of workplace injuries and illnesses;
•industrial hygiene monitoring;
•worker protection and workplace safety;
•approval or permits to drill and to conduct operations;
•provision of financial assurances (such as bonds) covering drilling and well operations;
•calculation and disbursement of royalty payments and production taxes;
•seismic operations and data;
•hydraulic fracturing;
•location, drilling, cementing and casing of wells;
•well design and construction of pad and equipment;
•construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
•method of completing wells and hydraulic fracturing;
•water withdrawal;
•well production and operations, including processing and gathering systems;
•emergency response, contingency plans and spill prevention plans;
•emissions and discharges permitting;
•climate change;
•use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
•surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
•plugging and abandoning of wells; and
•transportation of production.
Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines or penalties or injunctions limiting the Operator's operations in affected areas. Moreover, multiple environmental laws provide for citizen suits that allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. The Operator considers the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of its business. The Operator has been able to plan for and comply with environmental, safety and health initiatives without materially altering its operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, the Operator's capital expenditures and operating expenses related to the protection of the
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environment and safety and health compliance have increased over the years and may continue to increase. The Operator cannot predict with any reasonable degree of certainty its future exposure concerning such matters.
The Operator's operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas the Operator can produce from its wells and the number of wells or the locations at which it can drill. For further discussion, see Item 1A. Risk Factors - The Operator is subject to extensive governmental regulation, which can change and could adversely impact the Operator's business.
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could make it prohibitive to conduct operations, and also reduce the amount of oil, natural gas and NGL that the Operator is ultimately able to produce in commercial quantities from its properties.
Certain of the Operator's U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject to frequent delays.
Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit the Operator's ability to execute its drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of the Operator's permits, inability to obtain new permits and the imposition of fines and penalties. For further discussion, see Item 1A. Risk Factors - Oil and natural gas drilling and producing operations can be hazardous and may expose the Operator to liabilities.
Human Capital
The Trust does not have any employees, directors, or executive officers.
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, the Operator could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. The Operator's horizontal operations involve greater risk of mechanical problems than vertical wells.
As a passive entity, the Trust does not maintain insurance policies for the Underlying Properties. The Operator maintains a control of well insurance policy with a $3 million limit on producing wells with a true vertical depth of less than or equal to 5,000 feet, a $20 million limit on producing wells with a true vertical depth of more than 5,000 feet, and a $20 million to $30 million limit on drilling, workover, and re-entry activities depending on the level of the authorization for expenditure that insure against certain sudden and accidental risks associated with drilling, completing, and operating its wells. There is no assurance that this insurance will be adequate to cover all losses or exposure to liability. The Operator also carries in excess of $20 million in commercial general liability and/or umbrella insurance that is inclusive of sudden and accidental pollution liability. The Operator provides workers’ compensation insurance coverage to employees in all states in which it operates. While the Operator has informed
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us that it believes these policies are customary in the industry, they do not provide complete coverage against all operating risks and policy limits scale to the Operator's working interest percentage in certain situations. In addition, the Operator's insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect to the Operator's financial position, results of operations and cash flows. The Operator’s insurance coverage may not be sufficient to cover every claim made against the Operator or may not be commercially available for purchase in the future.
The Underlying Properties and the Royalty Interests
Overview. The Underlying Properties consist of working interests owned by the Operator located in the Colony Granite Wash play in Washita County in western Oklahoma arising from leases and farmout agreements related to properties from which the Royalty Interests were conveyed. The AMI consists of approximately 40,500 gross acres (26,400 net acres). As of December 31, 2023 and 2022, the total reserves estimated to be attributable to the Trust were 3,593 mboe (60% natural gas by volume) and 3,846 mboe (57% natural gas by volume), respectively. These amounts include 3,593 mboe of proved developed reserves and no proved undeveloped reserves as of December 31, 2023 and 3,846 mboe of proved developed reserves and no proved undeveloped reserves as of December 31, 2022. The decrease in estimated total reserves attributable to the Trust of 253 mboe is primarily due to 2023 production and decreases in commodity pricing. See Item 1A. Risk Factors – Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units and Risks and Uncertainties in Note 2 to the financial statements contained in Part II, Item 8 of this Annual Report for further discussion of the decrease in reserves. For clarity, the Trust does not own or have rights to undeveloped lands, undeveloped formations, or undeveloped reserves, nor the right or ability to drill future wells.
The Colony Granite Wash is a subset of the greater granite wash plays of the Anadarko Basin. The Colony Granite Wash is located at the eastern end of a series of Des Moines-age granite wash fields that extend along the southern flank of the Anadarko Basin, approximately 60 miles into the Texas Panhandle. These granite wash fields were generally deposited as deep-water turbidites that result in relatively low risk, laterally extensive reservoirs. The productive members of the Colony Granite Wash are encountered between approximately 11,500 and 13,000 feet and lie stratigraphically between the top of the Des Moines formation (or top of Colony Granite Wash 'A') and the top of the Prue formation (or base of Colony Granite Wash 'C'). The individual productive members within the Colony Granite Wash may reach 200 feet or more in gross interval thickness and the targeted porosity zones within these individual members are generally 20 to 75 feet thick. The Colony Granite Wash is primarily a natural gas and natural gas condensate reservoir based on reserve volumes. No development costs were incurred in the years ended December 31, 2023 and 2022 due to no new wells being drilled by the Operator in the Colony Granite Wash after fulfillment of its drilling obligation to the Trust.
Royalty Interests. The Royalty Interests were conveyed from Chesapeake's interest in the Underlying Properties effective as of July 1, 2011. As of December 31, 2023, the Trust on average owns a 47.8% net revenue interest in the Producing Wells and a 28.6% net revenue interest in the completed Development Wells. The Operator retains 10% of the proceeds from the sales of oil, natural gas and NGL production attributable to its net revenue interest in the Producing Wells, and 50% of the proceeds from the sales of production attributable to its net revenue interest in the Development Wells.
The Royalty Interests were conveyed to the Trust by Chesapeake by means of conveyance instruments that were recorded in the appropriate real property records in Washita County, Oklahoma. The conveyance instruments obligate the Operator to act diligently and as a reasonably prudent oil and gas operator would act under the same or similar circumstances as if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens affecting such properties. We refer to this standard as the "Reasonably Prudent Operator Standard." The Trustee has no ability to manage or influence the operation of the Underlying Properties.
Oil, Natural Gas and NGL Reserves. Proved reserve quantities attributable to the Royalty Interests are calculated by multiplying the gross reserves for each property attributable to the Operator's interest by the net revenue interest assigned to the Trust in each property. The reserves related to the Underlying Properties include all proved reserves expected to be economically produced during the life of the properties. The reserves attributable to the Trust's interests include only the reserves attributable to the Underlying Properties that are expected to be produced within the 20-year period prior to the Termination Date as well as the residual 50% interest in the Royalty Interests that the Trust will own on the Termination Date and subsequently sell.
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All of the Trust's estimated oil, natural gas and NGL reserves are located within the U.S. The table below sets forth information as of December 31, 2023 with respect to the estimated proved reserves of the Underlying Properties and Royalty Interests and the associated PV-10. Because the Trust will not bear income tax expense, PV-10 and the standardized measure of estimated future net revenue of the Royalty Interests are the same. PV-10 is not intended to represent the current market value of the estimated oil, natural gas and NGL reserves attributable to the Royalty Interests. The reserve estimates were prepared by third party engineering firm, Netherland, Sewell & Associates, Inc., in accordance with the criteria established by the SEC. Management uses PV-10, a non-GAAP measure, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.
Proved Reserves | ||||||||||||||||||||||||||||||||
| Oil (mbbl) | Natural Gas (mmcf) | NGL (mbbl) | Total (mboe) | PV-10 ($ in thousands) | ||||||||||||||||||||||||||||
| Underlying Properties: | ||||||||||||||||||||||||||||||||
| Developed | 418 | 12,882 | 989 | 3,553 | $ | 17,345 | ||||||||||||||||||||||||||
| Undeveloped | — | — | — | — | — | |||||||||||||||||||||||||||
Total | 418 | 12,882 | 989 | 3,553 | $ | 17,345 | ||||||||||||||||||||||||||
| Royalty Interests: | ||||||||||||||||||||||||||||||||
Developed(1) | 419 | 13,035 | 1,001 | 3,593 | $ | 35,081 | ||||||||||||||||||||||||||
Undeveloped(1) | — | — | — | — | — | |||||||||||||||||||||||||||
Total | 419 | 13,035 | 1,001 | 3,593 | $ | 35,081 | ||||||||||||||||||||||||||
_________________________________________________
(1)PV-10 for the Royalty Interests was calculated exclusive of any production or development costs.
| Proved Developed | Proved Undeveloped | Total Proved | ||||||||||||||||||
| ($ in thousands) | ||||||||||||||||||||
| Royalty Interests: | ||||||||||||||||||||
Estimated future net revenue (1) | $ | 71,120 | $ | — | $ | 71,120 | ||||||||||||||
Present value of estimated future net revenue (PV-10)(1) | $ | 35,081 | $ | — | $ | 35,081 | ||||||||||||||
Standardized measure(1) | $ | 35,081 | ||||||||||||||||||
_________________________________________________
(1)Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and costs, using prices and costs under existing economic conditions as of December 31, 2023. PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted at 10% per annum to reflect timing of future cash flows and calculated without deducting future income taxes. PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted net cash flows, or the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, as the Trust is not subject to income tax expense, the two measures are the same as of December 31, 2023.
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A comparison of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of the proved oil and gas reserves.
The proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil, natural gas and NGL for the period from January 1, 2023 through December 31, 2023, and were held constant for the life of the properties. The prices used in the reserve reports, as well as the Operator's internal reports, yield weighted average prices at the wellhead, which are based on first-day-of-the-month reference prices and before basis differential adjustments. For the Royalty Interests, costs of marketing services provided by the Operator's affiliates will not be charged to the Trust. The reference prices and the equivalent weighted average wellhead prices are presented in the table below.
| Oil | Natural Gas | ||||||||||||||||||||||
| (per bbl) | (per mcf) | ||||||||||||||||||||||
| Trailing 12-month average (SEC) pricing | $ | 78.21 | $ | 2.64 | |||||||||||||||||||
| Weighted average wellhead prices (Underlying Properties) | $ | 74.57 | $ | 1.68 | |||||||||||||||||||
| Weighted average wellhead prices (Royalty Interests) | $ | 74.57 | $ | 1.68 | |||||||||||||||||||
As of December 31, 2023, no Royalty Interests or proved reserves attributable to the Underlying Properties were classified as PUDs.
As of December 31, 2023, of the total proved reserves, 3,553 mboe and 3,593 mboe attributable to the Underlying Properties and the Royalty Interests, respectively, were classified as proved developed reserves.
The Operator's ownership interest used for calculating proved reserves and the associated estimated future net revenue assumed maximum participation by other parties to the Operator's farmout and participation agreements. SEC pricing used for calculating the estimated future net revenues attributable to proved reserves does not reflect actual market prices for oil, natural gas and NGL production sold subsequent to December 31, 2023.
The Trust's estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2023, 2022 and 2021, respectively, along with the changes in quantities and standardized measure of such reserves for the three years ended December 31, 2023, 2022 and 2021, respectively, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this Annual Report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Operator's control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions to such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures about Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this Annual Report for further discussion of our reserve quantities.
Development Wells. Pursuant to the development agreement with the Trust, the Operator was obligated to drill, cause to be drilled or participate as a non-operator in the drilling of 118 Development Wells by June 30, 2016. The Operator had fulfilled its drilling obligation under the development agreement as of June 30, 2016. The Operator retained an interest in each of the Producing Wells and Development Wells and Diversified currently operates approximately 96% of the Producing Wells and the completed Development Wells. Prior to fulfilling its commitment to drill the Development Wells, the Operator was not allowed to drill or complete, or permit any other person within
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its control to drill or complete any well in the Colony Granite Wash formation or lease acreage included within the AMI for its own account. For the life of the Trust, the Operator will not be permitted to drill or complete any well that will have a perforated segment within 600 feet of any perforated interval of any Development Well or Producing Well. The Operator's average net revenue interest in the oil and gas properties underlying the Development Royalty Interest is approximately 60%. The Development Royalty Interest entitles the Trust to receive 50% of the proceeds attributable to the Operator's net revenue interest in future production of oil, natural gas and NGL from the Development Wells.
The Trust was not responsible for any costs related to the drilling of the Development Wells and is not responsible for any other operating or capital costs of the Underlying Properties.
Due to the Operator's completion of its drilling obligation under the development agreement, it may now sell all or any part of its retained interest in the Underlying Properties, without the consent or approval of the Trust unitholders. In any such sale by the Operator, the Underlying Properties must be sold subject to and burdened by the Royalty Interests, except that the Operator may require the Trust to release the Royalty Interests on such Underlying Properties with an aggregate value of up to $5.0 million during any 12-month period. In such event, the Trust must receive an amount equal to the fair value to the Trust of any Royalty Interests it sells.
Drilling Activity. Due to the Operator's completion of its drilling obligation under the development agreement as of June 30, 2016, the Operator did not drill any wells in 2023, 2022 or 2021 and has no obligation to do so in the future.
Developed and Undeveloped Acreage. The following table sets forth information regarding developed and undeveloped acreage held by the Operator within the AMI as of December 31, 2023. All of the leases associated with the Underlying Properties are held by production and not subject to expiration so long as production continues in paying quantities.
Developed Acreage(1) | Undeveloped Acreage | ||||||||||||||||||||||
| Gross | Net | Gross | Net | ||||||||||||||||||||
| Acreage Held by the Operator within the AMI | 40,236 | 26,195 | — | — | |||||||||||||||||||
_________________________________________________
(1)Gross and net developed acres are acres spaced or assignable to productive wells. The drilling unit for each Colony Granite Wash horizontal well comprises 640 acres. As such, developed acreage may include up to 640 acres assigned to each Colony Granite Wash horizontal well.
Marketing and Post-Production Services. Pursuant to the terms of the conveyances creating the Royalty Interests, the Operator has the responsibility to market, or cause to be marketed, the oil, natural gas and NGL production related to the Underlying Properties. Marketing costs are deducted from the proceeds upon which the royalty payments are calculated.
Post-production expenses are also deducted from proceeds paid to the Trust. Williams Partners, L.P. ("WMB"), provides gathering, treating, compression and other post-production services, and an affiliate of Energy Transfer LP ("Energy Transfer") provides gathering, processing, transportation and other post-production services. The proceeds paid to the Trust are reduced by deductions for these post-production expenses.
Post-production expenses may be deducted by the ultimate purchaser of the oil, natural gas and NGL prior to payment being made to the Operator for such production. At other times, the Operator makes payments directly to the applicable provider of such post-production services. In either instance, the Trust's cash available for distribution is reduced by the expenses incurred for such post-production services. If the post-production expenses are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is less the applicable percentage charged, and as a result the reserves associated with that well that are attributable to the Royalty Interest are reduced accordingly.
The post-production expenses are negotiated based on market conditions at the time or pursuant to a state or federal regulatory proceeding. The Operator is permitted to deduct from the proceeds available to the Trust other post-production expenses necessary to enhance the value of the oil, natural gas and NGL from the Underlying Properties and to transport such production to market.
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Natural gas and NGL produced from the Underlying Properties are gathered by gathering pipelines owned by WMB under a contract that expires in approximately 5 years. NGL and natural gas are gathered and processed at facilities owned by Energy Transfer under a contract that is month-to-month and then sold to a number of primary purchasers in the area. The contract with Energy Transfer requires a 30 day written notice for termination and can be assigned to any third party by mutual agreement. Oil produced from the Underlying Properties is gathered by gathering pipelines and equipment owned by WMB or transported by trucks owned by third parties and sold to various counterparties. In the event of a loss of its contracts with WMB or Energy Transfer, the Operator believes that the availability of other customers and service providers in the area is sufficient to accommodate such loss.
Any new oil, natural gas and NGL supply arrangements or those entered into for providing post-production services will be utilized in determining the proceeds for the Underlying Properties.
Discussion and Analysis of Results from the Underlying Properties
Historical Results. The Underlying Properties consist of the working interests owned by the Operator in the Colony Granite Wash play in Washita County in western Oklahoma arising under leases and farmout agreements related to properties from which the PDP Royalty Interest and the Development Royalty Interest were conveyed.
The following table provides revenues and direct operating expenses for the years ended December 31, 2023, 2022 and 2021 as derived from the Underlying Properties' statements of revenues and direct operating expenses.
| Years Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| ($ in thousands) | ||||||||||||||||||||
Oil, natural gas and NGL revenues(1) | $ | 11,240 | $ | 18,349 | $ | 20,718 | ||||||||||||||
| Direct operating expenses: | ||||||||||||||||||||
| Production expenses excluding taxes | 3,419 | 2,732 | 4,459 | |||||||||||||||||
| Production taxes | 780 | 1,395 | 1,525 | |||||||||||||||||
| Total direct operating expenses | 4,199 | 4,127 | 5,984 | |||||||||||||||||
Revenues in excess of direct operating expenses | $ | 7,041 | $ | 14,222 | $ | 14,734 | ||||||||||||||
_________________________________________________
(1)Oil, natural gas and NGL revenues are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.
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The following table sets forth the production, average sales prices, and average cost per boe for production expenses and production taxes for the Underlying Properties for the years ended December 31, 2023, 2022 and 2021.
| Years Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Production: | ||||||||||||||||||||
| Oil (mbbls) | 68 | 69 | 99 | |||||||||||||||||
| Natural gas (mmcf) | 1,830 | 1,588 | 2,271 | |||||||||||||||||
| NGL (mbbls) | 151 | 148 | 286 | |||||||||||||||||
Total production (mboe) | 525 | 482 | 764 | |||||||||||||||||
Average sales prices:(1) | ||||||||||||||||||||
| Oil (per bbl) | $ | 74.52 | $ | 96.68 | $ | 64.71 | ||||||||||||||
Natural gas (per mcf) | $ | 2.62 | $ | 6.62 | $ | 3.12 | ||||||||||||||
| NGL (per bbl) | $ | 28.44 | $ | 43.16 | $ | 25.29 | ||||||||||||||
| Average (per boe) | $ | 21.43 | $ | 38.07 | $ | 27.12 | ||||||||||||||
| Direct operating expenses: | ||||||||||||||||||||
Production expenses (per boe) | $ | 6.52 | $ | 5.67 | $ | 5.84 | ||||||||||||||
Production taxes (per boe)(2) | $ | 1.49 | $ | 2.90 | $ | 2.00 | ||||||||||||||
___________________________________________________
(1)Average sales prices are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.
(2)Production taxes are generally based upon volume produced and prices received for production and include ad valorem taxes.
Oil, Natural Gas and NGL Revenues. For the year ended December 31, 2023, oil, natural gas and NGL revenues were $11.2 million compared to $18.3 million and $20.7 million for the years ended 2022 and 2021, respectively. The $7.1 million decrease in revenues from 2022 to 2023 was due to a decrease in average sales prices received offset by an increase in production from Diversified's acquisition of additional working interests in certain of the Underlying Properties in October 2022, which did not affect the corresponding revenue attributable to the Trust. The overall decrease in the price received per boe in 2023 compared to 2022 resulted in a $8.7 million decrease in oil, natural gas and NGL revenues. Increased sales volumes resulted in a $1.6 million increase in oil, natural gas and NGL revenues. The Participation Agreement was effective throughout 2023, and did not affect the corresponding revenue attributable to the Trust.
The $2.4 million decrease in revenues from 2021 to 2022 was due to a decrease in production offset by an increase in average sales prices received. The overall increase in the price received per boe in 2022 compared to 2021 resulted in a $5.3 million increase in oil, natural gas and NGL revenues. Decreased sales volumes in 2022 resulted in a $7.7 million decrease in oil, natural gas and NGL revenues. This decrease was a result of the Participation Agreement, which did not affect the corresponding revenue attributable to the Trust.
Production Expenses. For the year ended December 31, 2023, production expenses were $3.4 million compared to $2.7 million and $4.5 million for the years ended 2022 and 2021, respectively. On a unit-of-production basis, production expenses were $6.52 per boe in 2023 compared to $5.67 per boe in 2022 and $5.84 per boe in 2021.
Production Taxes. For the year ended December 31, 2023, production taxes were $0.8 million, compared to $1.4 million and $1.5 million for the years ended 2022 and 2021, respectively. On a unit-of-production basis, production taxes were $1.49 per boe in 2023 compared to $2.90 per boe in 2022 and $2.00 per boe in 2021. The decrease in per unit-of-production taxes from 2022 to 2023 was primarily due to the decrease in commodity prices. The increase in per unit-of-production taxes from 2021 to 2022 was primarily due to the increase in commodity prices.
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The Reserve Report for the Underlying Properties and the Royalty Interests
The oil, natural gas and NGL reserves in this Annual Report were estimated by Netherland, Sewell & Associates, Inc. ("NSAI"). The process to review and estimate the reserves begins with Diversified's Corporate Reserves Department collecting and verifying all pertinent data, including but not limited to well test data, production data, historical pricing, cost information, property ownership interests, reservoir data, and geosciences data. This data is reviewed by various levels of Diversified management for accuracy before consultation with NSAI. NSAI was consulted with regularity during the reserve estimation process to review properties, assumptions, and any new data available. Internal reserve estimates and methodologies are compared to NSAI's estimates and methodologies to test the reserve estimates and conclusions before the reserve estimates are included in this Annual Report. Additionally, Diversified's senior management reviews and approves the reserve report contained herein.
Internal Controls. Diversified's Vice President of Engineering is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. His qualifications include the following:
•over 25 years of practical experience in the oil and gas industry, with over 20 years in reservoir engineering;
•Bachelor of Science degree in Petroleum Engineering; and
•member in good standing of the Society of Petroleum Engineers.
Diversified ensures that the key members of Diversified's Reservoir Engineering Department have appropriate technical qualifications to oversee the preparation of reserves estimates. Each of Diversified's Corporate Reserves Engineers has significant experience in reserve estimation.
Diversified maintains internal controls such as the following to ensure the reliability of reserves estimations:
•Diversified follows comprehensive SEC-compliant internal policies to estimate and report proved reserves for the Trust. Reserves estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Diversified's Vice President of Engineering.
•Diversified's Reservoir Engineering Department reviews all of Diversified's reserves bi-annually and the Trust's proved reserves at the close of each quarter.
Technologies. The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells, as defined by the SEC. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset undeveloped wells in the field. The continuity of the play across the AMI area was established by reviewing electronic well logs from wells, geologically mapping the analogous reservoir and reviewing extensive production data from horizontal wells within the larger Colony Granite Wash area.
Netherland, Sewell & Associates, Inc. Diversified engaged Netherland, Sewell & Associates, Inc., a third-party engineering firm, to prepare all of the Trust's estimated proved reserves as of December 31, 2023. A copy of the report issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical person at the firm primarily responsible for overseeing the preparation of our reserve estimates are set forth below.
•over 30 years of practical experience in the estimation and evaluation of reserves;
•licensed professional engineer in the State of Texas; and
•Bachelor of Science in Mechanical Engineering, Bachelor of Science in Geology and Master of Science in Geology.
Miscellaneous
The Trustee may consult with counsel (which may include counsel to the Operator), accountants, tax advisors, geologists and engineers and other parties the Trustee believes to be qualified as experts on the matters for which advice is sought. The Trustee is protected for any action it takes in good faith reliance upon the opinion of the expert.
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The Delaware Trustee and the Trustee may resign at any time or be removed with or without cause at any time by the vote of a majority of the outstanding Trust units (excluding common units owned by Diversified and its affiliates) voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be the vote of a majority of the Trust units, including units owned by Diversified, voting in person or by proxy at a meeting of such holders at which a quorum is present. Notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units. Abstentions and broker non-votes shall not be deemed to be votes cast. Any successor must be a bank or trust company meeting certain requirements, including having combined capital, surplus and undivided profits of at least $20 million, in the case of the Delaware Trustee, and $100 million, in the case of the Trustee.
ITEM 1A. Risk Factors
Geopolitical Events May Adversely Impact the Trust's Business, Cash Flows, Liquidity, or Financial Condition
We are actively monitoring the military conflicts in Ukraine and in Israel and surrounding countries, and assessing their impact on the Trust’s business. To date, we have not experienced any material interruptions to our business given that the Underlying Properties are exclusively located within the United States. The extent and duration of the military action, sanctions and resulting market disruptions could be significant, including significant volatility in commodity prices, supply of energy resources, instability in financial markets, including inflation, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increases in cyberattacks and espionage, each of which could have a substantial impact on the global economy and consequently our business for an unknown period of time. We currently do not expect any material impact on the Trust’s business, cash flows, liquidity or financial condition; however, we have no way to predict the progress or outcome of the military conflict in Ukraine and Israel as the conflict, and any resulting government reactions, are rapidly developing and beyond our control.
Risks Related to Operation of the Underlying Properties
Producing oil, natural gas and NGL on the Underlying Properties is a high-risk activity with many uncertainties. Any delays or reductions in production could decrease cash available for distribution to unitholders.
Producing oil, natural gas and NGL can be unprofitable if productive wells do not produce sufficient revenues to return a profit. The Operator's and third-party operators' decisions to develop or otherwise exploit certain areas within the AMI depended in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Production operations on the Underlying Properties may be curtailed, delayed or canceled as a result of various factors, including the following:
•unusual or unexpected geological formations and miscalculations or irregularities in formations;
•equipment malfunctions, failures or accidents;
•lack of available gathering facilities or delays in construction of gathering facilities;
•lack of available capacity on interconnecting transmission pipelines;
•pipe or cement failures and casing collapses;
•pressures, fires, blowouts and explosions;
•lost or damaged service tools;
•uncontrollable flows of oil, natural gas and NGL water or drilling fluids;
•natural disasters;
•environmental hazards, such as oil, natural gas and NGL leaks, pipeline ruptures and discharges of toxic gases or fluids;
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•adverse weather conditions, such as extreme cold, fires caused by extreme heat or lack of rain and severe storms or tornadoes;
•reductions in oil, natural gas and NGL prices; and
•title problems affecting the Underlying Properties.
If the Producing Wells or Development Wells have lower than anticipated production due to one of the factors above or for any other reason, cash distributions to unitholders may be reduced.
Oil, natural gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on proceeds to the Trust and cash distributions to unitholders.
The Trust's reserves and quarterly cash distributions depend primarily upon the prices realized from the sales of oil, natural gas and NGL. The Operator requires substantial expenditures to replace reserves, sustain production and fund its business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures and debt repayment and the ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on the Operator's financial condition, results of operations, cash flows and reserves and the Trust’s reserves and quarterly cash distributions. Historically, the markets for oil, natural gas and NGL have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGL, market uncertainty and other factors that are beyond the control of the Trust and the Operator, including:
•domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;
•weather conditions;
•changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus;
•the price and availability of alternative fuels;
•technological advances affecting energy consumption;
•the effectiveness of worldwide conservation and environmental measures;
•the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
•the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
•U.S. exports of oil, natural gas and/or liquefied natural gas;
•the price and level of foreign imports;
•the nature and extent of domestic and foreign governmental regulations and taxes;
•the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil price and production controls;
•increased use of competing energy products, including alternative energy sources;
•political instability or armed conflict in oil and natural gas producing regions, including the conflicts in Ukraine and Israel;
•acts of terrorism; and
•domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements.
Lower oil, natural gas and NGL prices have reduced, and could continue to reduce, proceeds to which the Trust is entitled and may ultimately reduce the amount of oil, natural gas and NGL that is economic to produce from the Underlying Properties. As a result, the Operator or any third-party operator of any of the Underlying Properties could determine during periods of low oil, natural gas and NGL prices to shut-in or curtail production from wells on
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the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low oil, natural gas and NGL prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, the Operator or any third-party operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil, natural gas and NGL in commercially economic quantities. This could result in termination of the portion of the Royalty Interests relating to the abandoned well or property.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the future production estimated to be attributable to the Royalty Interests. The future production estimates are based on estimates of reserve quantities for the Underlying Properties. Estimates of proved reserves and estimated future net revenues from proved reserves are based upon various assumptions, including assumptions required by the SEC relating to oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil, natural gas and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to further revisions.
Actual future production attributable to the Royalty Interests, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond the Operator's control. The Trust's revenue and distributable income available to unitholders have been adversely affected throughout 2022 and 2023 by a decline in production. Due to natural declines, the Trust expects production to decline further and expects distributable income to continue to be adversely affected.
As of December 31, 2023, none of the Trust’s estimated proved reserves were undeveloped.
The present values included in this report do not represent the current market value of the Trust's estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. Prices on the date of estimate are calculated as the average oil and natural gas price, as applicable, during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2023 present value is based on a $78.21 per bbl of oil price and a $2.64 per mcf of natural gas price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for oil and natural gas, governmental regulations, or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in estimates of proved reserves, future production rates and the timing of development expenditures. Most of the Producing Wells have been operational for a relatively short period of time and estimated total reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion technique. There can be no assurance that the data used in preparing these estimates can accurately predict future production. The lack of operational history for horizontal wells in the Colony Granite Wash may also contribute to the inaccuracy of estimates of proved reserves. During 2023, the Trust recorded downward reserve revisions primarily attributable to lower production and commodity prices in forecasts. During 2022, the Trust recorded upward reserve revisions
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primarily attributable to higher production and commodity prices in forecasts. Future well performance or different expected ultimate recovery could lead to further adjustments to our reserve estimates. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on the financial condition, results of operations and cash flows of the Trust and would reduce cash distributions to Trust unitholders.
The Operator may not serve as the operator of as many of the Development Wells as it expects and the Operator will rely upon unaffiliated third parties, who may be less qualified, to operate the Development Wells.
Pursuant to the development agreement between Tapstone (as successor to Chesapeake) and the Trust, Tapstone was obligated to, and did, drill and complete the equivalent of 118 Development Wells in the AMI as of June 30, 2016. Certain Development Wells drilled by Tapstone are currently operated by third-party operators. The failure of an operator to adequately perform operations could reduce production from the Underlying Properties and the cash available for distribution to Trust unitholders.
Because the Operator does not have a majority working interest in most of the non-operated properties comprising the Underlying Properties, the Operator may not be able, either unilaterally or in concert with other working interest owners, to remove the operator in the event of poor or untimely performance. The failure of an operator to adequately perform operations could reduce the revenues distributable to the Trust and the amount of cash distributable to the Trust unitholders.
Due to the Trust's lack of industry and geographic diversification, adverse developments in the Trust's existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.
The Underlying Properties are operated for oil, natural gas and NGL production and are focused exclusively in the Colony Granite Wash in Washita County in the Anadarko Basin of western Oklahoma. This concentration could disproportionately expose the Trust's interests to operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the Trust's interests, adverse developments in the oil, natural gas and NGL markets or the area of the Underlying Properties, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance, could have a significantly greater impact on the Trust's financial condition, results of operations and cash flows than if the Royalty Interests were more diversified.
The generation of proceeds for distribution by the Trust depends in part on access to and the operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil, natural gas and NGL production from the Underlying Properties.
The amount of oil, natural gas and NGL that may be produced and sold from any well to which the Underlying Properties relate is subject to the availability of gathering, transportation and processing facilities. Even where such facilities are available, services from such facilities are subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil, natural gas and NGL to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery or physical damage to the gathering system or transportation system. The curtailments may vary from a few days to several months. In many cases, the Operator or a third-party operator is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If the Operator or a third-party operator is forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of proceeds from the sale of production. Moreover, the Operator currently ships all of its natural gas production from the Underlying Properties to market through one pipeline provider and sells all of its oil production from the Underlying Properties to one purchaser. Although the Operator currently does not have any material production shut-in and does not shut in production on a routine basis as a result of lack of accessibility to transportation or lack of processing facilities, there can be no assurance this will be the case in the future.
The Trust units may lose value and cash available for distribution may be reduced as a result of title deficiencies with respect to the Underlying Properties.
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The existence of a title deficiency with respect to any of the Underlying Properties could reduce the value or render a property worthless, thus adversely affecting the distributions to unitholders. The Operator does not obtain title insurance covering oil, natural gas and mineral leaseholds. The Operator's inability or failure to cure title defects could cause the Operator to lose its rights to some or all production from some of the Underlying Properties, which could result in a reduction in proceeds available for distribution to unitholders and the value of the Trust units may be reduced.
The oil, natural gas and NGL reserves estimated to be attributable to the Underlying Properties are depleting assets and production from those reserves will continue to diminish over time.
The proceeds payable to the Trust from the Royalty Interests are derived from the sale of the production of oil, natural gas and NGL from the Underlying Properties. The oil, natural gas and NGL reserves attributable to the Underlying Properties are depleting assets, which means that the reserves of oil, natural gas and NGL attributable to the Underlying Properties decline over time. As a result, the quantity of oil, natural gas and NGL produced from the Underlying Properties will continue to decline over time.
Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural gas and NGL. The Operator has no contractual obligation to the Trust to make capital expenditures on the Underlying Properties in the future. Furthermore, for properties on which the Operator is not designated as the operator, the Operator has no control over the timing or amount of those capital expenditures. The Operator also has the right not to participate in the capital expenditures on properties for which it is not the operator, in which case the Operator and the Trust will not receive the production resulting from such capital expenditures. If the Operator or other operators of the wells to which the Underlying Properties relate do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Operator or estimated in the reserve reports.
An increase in the differential between the prices realized by the Operator for oil, natural gas and NGL produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of Trust units.
The prices received for the Operator's oil, natural gas and NGL production in Oklahoma usually fall below benchmark prices, such as NYMEX. The difference between the price received and the benchmark price is called a differential. The amount of the differential will depend on a variety of factors, including discounts based on the quality and location of hydrocarbons produced, btu content, post-production expenses and production taxes. These factors can cause differentials to be volatile from period to period. The Operator has little or no control over the factors that determine the amount of the differential and cannot accurately predict natural gas or crude oil differentials. Increases in the differential between the realized price of oil, natural gas and NGL and the benchmark price for oil, natural gas and NGL could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of the Trust units.
Oil and natural gas producing operations can be hazardous and may expose the Operator to liabilities.
Oil and natural gas producing operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, oil spills, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. Some of these risks or hazards could materially and adversely affect the Operator's revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of its prospects. For non-operated properties, the Operator is dependent on the operator for operational and regulatory compliance. A temporary or permanent halt of the production and sales of oil, natural gas and NGL at any of the Underlying Properties could also reduce Trust distributions by reducing the amount of proceeds available for distribution.
If any of these risks occurs, the Operator could sustain substantial losses as a result of:
•injury or loss of life;
•severe damage to or destruction of property, natural resources or equipment;
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•pollution or other environmental damage;
•clean-up responsibilities;
•private lawsuits;
•regulatory investigations and administrative, civil and criminal penalties; and
•injunctions resulting in limitation or suspension of operations.
A material event such as those described above could expose the Operator to liabilities, monetary penalties or interruptions in its business operations. While the Operator may maintain insurance against some, but not all, of the risks described above, its insurance may not be adequate to cover casualty losses or liabilities. In addition, the Operator's insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination and/or do not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, the Operator has limited or no insurance coverage. Also, in the future the Operator may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which the Operator is not fully insured may expose it to liabilities.
Climate change and the effects of energy transition could result in significant operational changes and expenditures, reduce demand for our services and adversely affect business.
Many scientists have shown that increasing concentrations of carbon dioxide, methane and other greenhouse gases in the Earth’s atmosphere are changing global climate patterns. Impacts associated with global climate change include evolving and increasing regulations, increasing global concern and stakeholder scrutiny about climate change and increasing frequency and/or severity of adverse weather conditions. An increase in the frequency and severity of extreme weather, such as hurricanes, floods and winter storms, would adversely impact operations in various ways, such as through damage to facilities or from increased costs for insurance. Further, extreme weather conditions can interfere with customers’ and suppliers’ operations and increase costs. To the extent the frequency of extreme weather events increases, this could increase the cost of providing service.
Changing meteorological conditions, particularly an increased volatility in seasonal temperatures, could impact operations and result in changes to the amount, timing or location of demand for energy or the products produced by the Underlying Properties. Drilling and other crude oil and natural gas activities can be adversely affected during the winter months. Severe winter weather conditions limit and may reduce or temporarily halt operations during such conditions, leading to the decrease in drilling activity. This could result in a decrease in the volumes of crude oil, natural gas and NGLs produced from the Operator’s assets. Further, energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate changes. For example, the market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that the Operator produces. As a result, if there is an overall trend of warmer temperatures, it would be expected to affect the Operator’s financial condition through decreased revenues.
If any of these results occur, it could have an adverse effect on our assets and operations and cause increased costs in preparing for and responding to weather events. To the extent any such effects were to occur, the resulting impacts could have a material adverse effect on the Operator’s business, results of operations and financial condition.
Another consequence of climate change is the increased efforts by governments, international bodies, businesses and consumers to reduce greenhouse gases and otherwise mitigate the effects of climate change. The nature of these efforts and their effects on the Operator’s business are inherently unpredictable and subject to change. Certain regulatory responses to climate change issues are discussed below under the heading “The Operator is subject to extensive governmental regulation, which can change and could adversely impact the Operator's business.” Regulation of methane and other greenhouse gases emissions associated with oil and natural gas production could impose significant requirements and costs on the Operator’s operations.
The increased regulation of environmental emissions is expected to create greater incentives for the use of alternative energy sources. Increased demand for low-carbon or renewable energy sources (such as wind, solar geothermal, tidal and biofuels) could reduce the demand for, and the price of, or eventually phase out the use of,
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hydrocarbons and therefore for the Operator’s products and services, which would lead to a reduction in revenues. Technological changes, such as developments in renewable energy and low-carbon transportation, could contribute to the energy transition and adversely affect demand for the Operator’s products.
The transition of the global energy sector from primarily a fossil fuel-based system to renewable energy sources in response to climate change could affect customers’ levels of expenditures. Political, litigation and financial risks may result in the Operator’s oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which could reduce demand for our services and products.
Actions taken by private parties in anticipation of, or to facilitate, a transition to a lower-carbon economy would further impact the Operator’s business and financial condition. For example, activists concerned about the potential effects of climate change have recently begun to pressure sources of funding for fossil-fuel energy companies to restrict or eliminate their investment in energy-related activities. Lenders or other market participants may decline to invest in fossil fuel-related companies for reputational or regulatory reasons. Further, shareholders who are currently invested in fossil fuel companies but are concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into other sectors resulting in an increase in our cost of capital. Some stakeholders, including but not limited to sovereign wealth, pension, and endowment funds, have begun divesting and promoting divestment of or screening out of fossil fuel equities and urging lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. An economy-wide transition to lower greenhouse gases energy sources resulting from new government regulation and changing customer preferences would have a material adverse effect on the Operator’s business, financial condition and results of operations. Failure to effectively and timely address the energy transition would adversely affect the Operator’s business, reputation, results of operations and financial positions.
There are also increasing risks of litigation related to climate change effects. Governments and third-parties have brought suits against fossil fuel companies alleging, among other things, that such companies created public nuisances by marketing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Such litigation is becoming more common and has the potential to adversely affect the production of fossil fuels, which in turn could result in reduced demand for the Operator’s services. Climate change and the effects of energy transition could result in significant operational changes and expenditures, reduce demand for our services and adversely affect business.
Negative public perception regarding the Operator or the oil and gas industry could have an adverse effect on the Operator's operations.
Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Negative public perception regarding the Operator or the oil and gas industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose the Operator's operations through organized protests, attempts to block or sabotage the Operator's operations or those of the Operator's midstream transportation providers, intervene in regulatory or administrative proceedings involving the Operator's assets or those of the Operator's midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of the Operator's assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits the Operator requires to conduct its operations to be withheld, delayed or burdened by requirements that restrict the Operator's ability to profitably conduct its business. A change in presidential administration and/or change in control of Congress may also result in increased restrictions on oil and gas production activities, which could materially adversely affect the oil and gas industry and the Operator's financial condition and results of operations.
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Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our common units. Any efforts to improve the Operator's sustainability practices in response to these pressures may increase its costs, and it may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.
Increasing attention to environmental, social, and governance (“ESG”) matters, including those related to climate change and sustainability, may impact the Operator's business, reputation and ability to raise capital. Organizations now provide ESG ratings for companies based on their approach to ESG matters, including climate change and its associated risks. Investors are increasingly relying on company ESG ratings to inform their investment and voting decisions. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Unfavorable ESG ratings and investment community divestment initiatives, among other actions, may lead to negative investor sentiment toward the Operator and to the diversion of investment to other industries, which could have a negative impact on the Operator’s stock price and access to and costs of capital.
Any efforts by the Operator to improve sustainability practices in response to these evolving expectations on various ESG matters, including biodiversity, waste and water, may increase the Operator’s costs and reduce profits, and the Operator may be forced to implement technologies that are not economically viable in order to improve its sustainability performance and to meet the specific requirements to perform services for certain customers. However, where the Operator is not able to meet the current and future expectations of investors, customers or other stakeholders, the Operator’s business, reputation and ability to raise capital may be adversely affected.
Further, voluntary disclosures of ESG data, and the resulting public attention to a company’s ESG performance, may result in governmental investigations and public and private litigation, or threats thereof. For example, though federal securities laws generally do not require the disclosure of ESG data except in limited instances, potential liability may arise from ESG risk disclosures made in financial filings that are materially misleading or false. Though often unsuccessful, ESG litigation can cause serious reputational damage and result in significant litigation and public relations costs.
Emerging ESG regulations could impose enforceable disclosure requirements and present the Operator with substantial risk of litigation or government investigation. In 2021, the European Union implemented ESG reporting requirements for financial market participants. In the U.S., disclosure regulations have been issued related to pension investments in California and for the responsible investment of public funds in Illinois. Additional regulation is pending in other states. On March 6, 2024, the SEC adopted final rules to require registrants such as the Trust to disclose certain climate-related information in registration statements and annual reports filed with the SEC. The final rules require a registrant to disclose, among other things: material climate-related risks; activities to mitigate or adapt to such risks; information about the registrant's board of directors' oversight of climate-related risks and management’s role in managing material climate-related risks; and information on any climate-related targets or goals that are material to the registrant's business, results of operations, or financial condition. Further, the final rules require disclosure of Scope 1 and/or Scope 2 greenhouse gas (“GHG”) emissions on a phased-in basis by certain larger registrants when those emissions are material; the filing of an attestation report covering the required disclosure of such registrants’ Scope 1 and/or Scope 2 emissions, also on a phased-in basis; and disclosure of the financial statement effects of severe weather events and other natural conditions including, for example, costs and losses. The GHG emission disclosure requirements do not apply to non-accelerated filers such as the Trust. However, the Trust will be required to comply with the other disclosure requirements of the rules commencing with the Trust’s 2027 fiscal year. The SEC’s final rules have been challenged in a number of U.S. federal circuit courts, and on March 15, 2024 the Fifth Circuit Court of Appeals published an order granting an administrative stay of the rules. The Trust has not yet determined the impact that the final rules will have on the Trust or its operations. The increasing societal, investor and regulatory pressure on companies to address ESG matters may result in reputational damage, negative impacts on stock price and access to capital markets, reduced profits and investigations and litigation risks.
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Increases in interest rates may cause the value of the Trust units to decline.
Recent increases in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as the Trust units. Any such increase in interest rates or reduction in demand for the units resulting from other relatively more attractive investment opportunities may cause the value of the units to decline. A global economic slowdown or recession and macroeconomic trends (such as higher inflation, volatility in the financial markets and increasing interest rates) may also result in unfavorable impact to the value of the Trust units.
Cybersecurity Risks
Diversified, as the Operator of the Underlying Properties, could be negatively affected by various security threats, including cybersecurity threats, and other disruptions, which could have a negative impact on the business of the Trust.
Diversified, as the Operator of the Underlying Properties, faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of the facilities and infrastructure of Diversified and of third parties on which Diversified relies such as processing plants and pipelines. These threats pose a risk to the security of Diversified’s systems and networks, the confidentiality, availability and integrity of its data and the physical security of its employees and assets. Diversified relies on information technology (“IT”) systems and networks in connection with its business activities, including certain of its exploration, development and production activities. Diversified relies on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil, natural gas and NGL reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased in the oil and gas industry, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. Diversified has experienced cyber-attacks in the past, and may not be successful in preventing future security breaches or cyber-attacks or mitigating their effect. Any security breach or cyber-attack could have a material adverse effect on Diversified’s reputation and competitive position and could lead to losses of sensitive information, critical infrastructure or capabilities essential to Diversified’s operation of the Underlying Properties. Cyber-attacks or security breaches also could result in litigation or regulatory action.
In addition to the risks presented to Diversified’s systems and networks, cyber-attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery to markets. A cyber-attack of this nature would be outside Diversified’s ability to control, but could have a material adverse effect on Diversified’s business, financial condition and results of operations, and could have a material adverse effect on the Trust.
Cyber-attacks or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of the Trustee's operations.
The Trustee depends heavily upon IT systems and networks in connection with its business activities. Despite a variety of security measures implemented by the Trustee, events such as the loss or theft of back-up tapes or other data storage media could occur, and the Trustee's computer systems could be subject to physical and electronic break-ins, cyber-attacks and similar disruptions from unauthorized tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally from within.
If a cyber-attack were to occur, it could potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the Trustee's computer systems and networks, or otherwise cause interruptions or malfunctions in the operations of the Trust, which could result in litigation, increased costs and regulatory penalties. It is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.
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Risks Related to Our Structure
The amount of cash available for distribution by the Trust will be reduced by post-production expenses and applicable taxes associated with the Royalty Interests and Trust expenses.
The Royalty Interests and the Trust will bear certain costs and expenses that will reduce the amount of cash received by or available for distribution by the Trust to the holders of the Trust units. These costs and expenses include the following:
•the Trust's share of the expenses incurred by the Operator to gather, store, compress, transport, process, treat, dehydrate and market the oil, natural gas and NGL (excluding costs of marketing services provided by the Operator);
•the Trust's share of applicable taxes on the oil, natural gas and NGL; and
•Trust administrative expenses, including fees paid to the Trustee and the Delaware Trustee, the annual administrative services fee payable to the Operator, tax return and Schedule K-1 preparation and mailing costs, independent auditor fees and registrar and transfer agent fees, costs associated with annual and quarterly reports to unitholders and certain internal expenses of the Trust incurred pursuant to the Registration Rights Agreement.
In addition, the amount of funds available for distribution to unitholders will be reduced by the amount of any cash reserves maintained by the Trustee in respect of anticipated future Trust expenses, including any expenses incurred by the Trustee as a result of the dissolution of the Trust. The Trustee may increase or decrease the targeted amount of the cash reserve at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the unitholders. Without limiting the foregoing, the Trustee reviewed the adequacy and sufficiency of the existing cash reserve in 2021 and determined to withhold funds otherwise available for distribution to the unitholders each quarter to increase existing cash reserves by a total of approximately $3,200,000 over a period of several quarters, commencing with the distribution to unitholders for the fourth quarter 2021 (payable in 2022). As of December 31, 2023, $1,660,828 has been so withheld to increase cash reserves. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to unitholders, together with interest earned on the funds.
The amount of costs and expenses borne by the Trust may vary materially from quarter to quarter. The extent by which the costs and expenses of the Trust are higher or lower in any quarter will directly decrease or increase the amount received by the Trust and available for distribution to the unitholders. Historical post-production expenses and taxes, however, may not be indicative of future post-production expenses and taxes.
The Trust is passive in nature and has no voting rights in the Operator and no managerial, contractual or other ability to influence the Operator, or control over the field operations of, sales of oil, natural gas and NGL from, or development of, the Underlying Properties.
Trust unitholders have no voting rights with respect to the Operator and has no managerial, contractual or other ability to influence the Operator's activities or operations of the Underlying Properties. In addition, some of the Development Wells are currently operated by third parties unrelated to the Operator. Such third-party operators may not have the operational expertise of the Operator within the AMI. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the aggregate working interest in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders have any contractual ability to influence or control the field operations of, sales of oil, natural gas and NGL from, or future development of, the Underlying Properties.
Financial information of the Trust is not prepared in accordance with U.S. GAAP.
The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles, or U.S. GAAP.
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Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from U.S. GAAP financial statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in U.S. GAAP financial statements. See Item 8 – Financial Statements and Supplementary Data – Notes to Financial Statements – Note 2 Accounting Policies for additional information.
The Trust is precluded from acquiring other oil and natural gas properties or royalty interests to replace the depleting assets and production.
The Trust Agreement provides that the Trust's business activities are generally limited to owning the Royalty Interests and activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not permitted to acquire other oil and natural gas properties or royalty interests to replace the depleting assets and production attributable to the Trust.
The Trustee may, under certain circumstances, sell the Royalty Interests and dissolve the Trust; otherwise, the Trust will begin to liquidate following the end of the 20-year period in which the Trust owns the Term Royalties.
The Royalty Interests will be sold and the Trust will be dissolved upon the occurrence of certain events. For example, the Trustee must sell the Royalty Interests if unitholders approve the sale or vote to dissolve the Trust. The Trustee must also sell the Royalty Interests if cash available for distribution is less than $1.0 million, in the aggregate, for any four consecutive quarters. The sale of all of the Royalty Interests will result in the dissolution of the Trust. Upon the dissolution of the Trust, the net proceeds of any such sale, after the payment of Trust liabilities, will be distributed to the Trust unitholders pro rata and unitholders will not be entitled to receive any proceeds from the sale of production from the Underlying Properties following such date. If none of these events occur, the Trust will dissolve on the Termination Date.
In connection with the dissolution of the Trust on the Termination Date, the Term Royalties will automatically revert to the Operator, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders (including Diversified to the extent of any Trust units it owns) at the date the Trust dissolves or soon thereafter. The price received by the Trust from any purchaser of the Perpetual Royalties will depend, among other things, on the prices of oil, natural gas and NGL at that time. There can be no assurance that the prices of oil, natural gas and NGL will be at levels such that Trust unitholders will receive any particular amount of cash in return for the Trust's sale of the Perpetual Royalties.
The Operator will have a right of first refusal to purchase the Perpetual Royalties upon the dissolution of the Trust, which may reduce the inclination of third parties to place a bid, and thereby reduce the value received by the Trust in a sale. If the Trustee receives a bid from a proposed purchaser other than the Operator and wants to sell all or part of the Perpetual Royalties to such third party, the Trustee will be required to give notice to the Operator and identify the proposed purchaser and proposed sale price, and other terms of the bid.
The Trust is administered by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs of the Trust are administered by the Trustee. Voting rights as a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders, and the Trust does not currently anticipate holding annual meetings. Likewise, there is no requirement for an annual or other periodic re-election of the Trustee. The Trust Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding Trust units, excluding Trust units held by the Operator, voting in person or by proxy at a special meeting of Trust unitholders at which a quorum is present called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it may be difficult for public unitholders to remove or replace the Trustee without the cooperation of holders of a substantial percentage of the outstanding Trust units.
Trust unitholders have limited ability to enforce provisions of the Royalty Interest conveyances, and the Operator's liability to the Trust is limited.
The Trust Agreement permits the Trustee and the Trust to sue the Operator or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the Royalty Interests. If the Trustee does
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not take appropriate action to enforce provisions of these conveyances, a Trust unitholder's recourse would be limited to bringing a lawsuit against the Trust or the Trustee to compel the Trust or the Trustee to take specified actions. The Trust Agreement expressly limits a Trust unitholder's ability to directly sue the Operator or any other party other than the Trustee. As a result, Trust unitholders will not be able to sue the Operator or any future owner of the Underlying Properties to enforce the Trust's rights under the conveyances. Furthermore, the Royalty Interest conveyances prohibit recovery of certain types of damages, such as consequential and punitive damages, and provide that, except as set forth in the conveyances, the Operator will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith and in accordance with the Reasonably Prudent Operator Standard under the development agreement and, to the fullest extent permitted by law, will owe no fiduciary duties to the Trust or the unitholders.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
Diversified may sell Trust units in the public or private markets and such sales could have an adverse impact on the trading price of the common units.
Diversified owns 23,750,000 common units. Subject to its compliance with applicable securities laws, Diversified may sell Trust units in the public or private markets, and any such sales could have an adverse impact on the price of the common units or on any trading market that may develop. The Trust has granted registration rights to DP Bluegrass, a subsidiary of Diversified, which, if exercised, would facilitate sales of Trust units by Diversified to the public.
Conflicts of interest could arise between the Operator and the Trust.
The Operator could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:
•The Operator's interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. For example, the Operator may abandon a well that is no longer producing in paying quantities even though such well is still generating revenue for the Trust unitholders. The Operator may make decisions with respect to expenditures and decisions to allocate resources to projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause oil, natural gas and NGL production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.
•The Operator may, without the consent or approval of the Trust unitholders, sell all or any part of its retained interest in the Underlying Properties, subject to and burdened by the Royalty Interests. Although the Operator must require any purchaser of its retained interest in the Underlying Properties to assume the Operator's obligations with respect to those properties, such sale may not be in the best interests of the Trust and the Trust unitholders. Any purchaser may lack the Operator's experience in the Colony Granite Wash or its creditworthiness.
•The Operator may, without the consent or approval of the Trust unitholders, require the Trust to release Royalty Interests with an aggregate value of up to $5.0 million during any 12-month period in connection with a sale by the Operator of a portion of its retained interest in the Underlying Properties. Although these releases are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such Royalty Interests, the fair value received by the Trust for such Royalty Interests may not fully compensate the Trust for the value of future production attributable to the Royalty Interests disposed of.
•The Operator can sell its Trust units regardless of the effects such sale may have on common unit prices or on the Trust itself. Additionally, once the Operator is allowed to vote its Trust units, the Operator can vote its Trust units in its sole discretion.
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In addition, the Operator has agreed that, if at any time the Trust's cash on hand (including available cash reserves) is not sufficient to pay the Trust's ordinary course expenses as they become due, it will lend funds to the Trust necessary to pay such expenses. Any such loan will be on an unsecured basis. If the Operator provides such funds to the Trust, it would become a creditor of the Trust and its interests as a creditor could conflict with the interests of unitholders. There were no loans to the Trust outstanding as of December 31, 2023 or December 31, 2022.
The Operator may sell all or a portion of its retained interest in the Underlying Properties, subject to and burdened by the Royalty Interests; any such purchaser could have a weaker financial position and/or be less experienced in oil, natural gas and NGL development and production than the Operator.
Trust unitholders will not be entitled to vote on any sale by the Operator of its retained interest in the Underlying Properties and the Trust will not receive any proceeds from any such sale. The purchaser would be responsible for all of the Operator's obligations relating to the Royalty Interests on the portion of the Underlying Properties sold, including the Operator's obligation to operate the Underlying Properties sold in accordance with the Reasonably Prudent Operator Standard under the development agreement and the Operator's true-up obligations with respect to the Underlying Properties sold, and the Operator would have no continuing obligation to the Trust for those properties. Additionally, the Operator may enter into farmout or participation arrangements with respect to the wells burdened by the Royalty Interests. Any purchaser, farmout counterparty or participating partner could have a weaker financial position and/or be less experienced in oil, natural gas and NGL development and production in the Colony Granite Wash than the Operator, which could result in a decrease in production from the Underlying Properties sold and a corresponding decrease in cash available for distribution to the Trust's unitholders. Additionally, in the event that the Operator enters into such a farmout or participation agreement, such as the participation agreement with Oaktree, the Royalty Interests will not burden any interests that the counterparty earns under such an agreement.
The Trust units are quoted for trading on the OTC Pink marketplace.
The Trust units are quoted on the Pink Open Market operated by OTC Markets Group, Inc. (the "OTC Pink") under the symbol “CHKR.” The lack of market and float of the Trust units can have an adverse effect on the market liquidity of the units and, as a result, the market price for the units could become more volatile. The Trust units were delisted from the New York Stock Exchange in March 2020. There is no intent to re-list the Units on a national securities exchange. If the Trust does not re-list the units on a national securities exchange and seek to increase its trading liquidity, it may be difficult to attract the interest of analysts, institutional investors, investment funds and brokers.
There are conflicting interpretations that the Trust Agreement requires the exclusion of common units owned by Diversified and its affiliates in a vote of the holders of a majority of common units.
Courts may not interpret that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake, even if Diversified and its affiliates own over 10% of the outstanding Trust units. Under this interpretation, Trust unitholders may be adversely effected if Diversified is able to vote its common units to take certain actions described below.
•dissolve the Trust (except in accordance with its terms);
•remove the Trustee or the Delaware Trustee;
•amend the Trust Agreement, the royalty conveyances, the Administrative Services Agreement and the development agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any material respect);
•merge, consolidate or convert the Trust with or into another entity; or
•approve the sale of all or any material part of the assets of the Trust.
If the Trust were to hold a vote, such vote may be subject to litigation to invalidate the vote if Diversified's common units were wrongfully excluded or included pursuant to the terms of the Trust Agreement. Any such litigation may adversely affect the unitholders and delay any vote from going into effect.
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Legal and Regulatory Risks
The Operator is subject to extensive governmental regulation, which can change and could adversely impact the Operator's business.
The Operator's operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on drilling or completion activities, the Operator may not be able to conduct its operations as planned. If new or more stringent federal, state or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, it could have a material adverse impact on the Operator's operations. In addition, the Operator may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.
In addition, changes in public policy have affected, and in the future could further affect, the Operator's operations. Regulatory developments could, among other things, restrict production levels, impose price controls, change environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to the Operator's operations. The Operator does not expect that any of these laws and regulations will affect operations materially differently than they would affect other companies with similar operations, size and financial strength. Although the Operator is unable to predict changes to existing laws and regulations, such changes could significantly impact profitability, financial condition and liquidity. This is particularly true of changes related to pipeline safety, hydraulic fracturing and climate change, as discussed below.
Pipeline Safety. The pipelines are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as for certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas. In December 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 became law, reauthorizing PHMSA for funding through 2023 and requiring, among other things, rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. At this time, we cannot predict the cost of these requirements or other potential new or amended regulations, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.
Hydraulic Fracturing. Congress has in the past and may in the future consider legislation to regulate hydraulic fracturing by federal agencies or limit the ability of companies to engage in hydraulic fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, and Vermont have done. In addition, certain local governments have adopted, and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, the Operator's business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
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Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. The U.S. Environmental Protection Agency (the "EPA") and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry.
In September 2018, the BLM published a final rule to repeal certain requirements of these regulations. The September 2018 rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. In July 2020, the U.S. District Court for the Northern District of California vacated BLM’s 2018 revision rule. On November 30, 2022 BLM published a proposed methane gas waste rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production. In June 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. Further, in November 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments, with supplemental rules regarding the same proposed on December 6, 2022. In December 2023, the EPA released final, more stringent methane emissions rules for new, modified, and reconstructed facilities in the oil and gas sector, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc, which may increase the operating costs of the Operator. Further, the Inflation Reduction Act of 2022 (the "Inflation Reduction Act") establishes the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain petroleum and natural gas facilities. The EPA proposed rules implementing the Inflation Reduction Act's methane emissions charge, which proposal was published in the Federal Register on January 26, 2024, is subject to a public comment period which closed on March 26, 2024, and could be finalized later in 2024.
Several states where the Operator operates, have imposed limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of renewable energy standards and/or cap-and-trade and/or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. In general, the number of allowances available for purchase is reduced each year until the overall greenhouse gas emissions reduction goal is achieved. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. A federal cap-and-trade program or expanded use of cap-and-trade programs at the state level could impose direct costs on the Operator through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. A carbon tax could directly increase costs of operation and similarly incentivize consumers to shift away from fossil fuels.
Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions. The agreement entered into force in November 2016, after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. As part of rejoining the Paris Agreement, President Biden announced that the United States would commit to a 50 to 52 percent reduction from 2005 levels of greenhouse gas emissions by 2030, and set the goal of reaching net-zero greenhouse gas emissions by 2050. In addition, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change. New legislation to regulate greenhouse gas emissions has also been periodically introduced in the United States Congress, but none have passed. Reentry into the Paris Agreement, new legislation, or President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations, which could have a material adverse effect on our business and that of our customers.
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In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this would make it more difficult and expensive to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as the Operator’s for sustainability performance, including practices related to greenhouse gases and climate change when making investment decisions. There is also a risk that financial institutions may adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, such as the adoption of net zero financed emissions targets. Such policies may be hastened by actions under the Biden administration, including the implementation by the Federal Reserve of any recommendations made by the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Any efforts by the Operator to improve its sustainability practices in response to these pressures may increase its costs, and it may be forced to implement technologies that are not economically viable in order to improve its sustainability performance and to meet the specific requirements to perform services for certain customers.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect the Operator, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, equipment and operations, which could require the Operator to incur costs to reduce emissions of greenhouse gases associated with its operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of reserves and have a material adverse effect on the Operator's profitability, financial condition and liquidity.
Tax Risks Related to the Units
The Trust's tax treatment depends on its status as a partnership for U.S. federal income tax purposes. If the IRS were to treat the Trust as a corporation for U.S. federal income tax purposes or the Trust were subjected to state or local entity level tax, then its cash available for distribution to Trust unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the Trust units depends largely on the Trust being treated as a partnership for U.S. federal income tax purposes. The Trust has not requested, and does not plan to request, a ruling from the IRS on this or any other tax matter affecting it.
It is possible in certain circumstances for a publicly traded trust otherwise treated as a partnership, such as the Trust, to be treated as a corporation for U.S. federal income tax purposes. Although the Trust does not believe based upon its current activities that such treatment is applicable to it, a change in current law or the Trust's activities could cause the Trust to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to federal taxation as an entity.
If the Trust were treated as a corporation for U.S. federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently 21%, and would likely be required to pay state income tax on its taxable income at the corporate tax rate in Oklahoma. Distributions to Trust unitholders would generally be taxed again as corporate distributions (to the extent of the Trust's current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to Trust unitholders. Because a tax would be imposed upon the Trust as a corporation, its cash available for distribution to Trust unitholders would be substantially reduced. In addition, changes in current state law may subject the Trust to additional entity-level taxation by individual states. Because of state budget deficits and other reasons, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to Trust unitholders. Therefore, if the Trust were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to the Trust unitholders, likely causing a substantial reduction in the value of the Trust units.
The U.S. federal income tax treatment of the Development Royalty Interest is not entirely free from doubt. A successful challenge by the IRS to the tax position the Trust takes with respect to the Development Royalty Interest could affect the amount, timing and character of income, gain or loss relating to an investment in Trust units.
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The U.S. federal income tax laws and precedents applicable to the tax treatment of royalty interests in wells that will be drilled in the future are not well established. As a result, the tax treatment of the Development Royalty Interest is not entirely free from doubt. A successful challenge by the IRS to the tax position the Trust takes with respect to the Development Royalty Interest could negatively affect the amount, timing and character of income, gain or loss relating to a unitholder's investment in Trust units, which could increase or accelerate the amount of federal income tax payable on a unitholder's share of the Trust's income.
The tax treatment of an investment in Trust units could be affected by potential legislative changes, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including the Trust, or an investment in the Trust units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Such proposals, if adopted, could eliminate the qualifying income exception for publicly traded partnerships deriving qualifying income from activities relating to fossil fuels thus treating such partnerships as corporations. The Trust currently relies upon this qualifying income exemption for our treatment of the Trust as a partnership for U.S. federal income tax purposes. The Trust is unable to predict whether any of these changes or other proposals will ultimately be enacted or will materially change interpretations of the current law, but it is possible that a change in law could affect the Trust and may, if enacted, be applied retroactively. Any such changes could have a material adverse effect on the Trust’s financial condition, cash flows, ability to make cash distributions to Trust unitholders and the value of an investment in the Trust units.
If the IRS contests the tax positions the Trust takes, the value of the Trust units may be adversely affected, the cost of any IRS contest will reduce the Trust's cash available for distribution to Trust unitholders.
The Trust has not requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other matter affecting the Trust. The IRS may adopt positions that differ from the conclusions of the Trust's counsel expressed in the federal income tax considerations section in the prospectus or from the positions the Trust takes. It may be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of the Trust's counsel or the positions the Trust takes. A court may not agree with some or all of the conclusions of the Trust's counsel or the positions the Trust takes. Any contest with the IRS may materially and adversely impact the market for the Trust units and the price at which they trade. In addition, the Trust's costs of any contest with the IRS will be borne indirectly by the Trust unitholders because the costs will reduce the Trust's cash available for distribution.
If the IRS makes audit adjustments to the Trust’s income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from the Trust. To the extent possible under the new rules, the Trust may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although the Trust may elect to have Trust unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, current Trust unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Trust unitholders did not own units in the Trust during the tax year under audit. If, as a result of any such audit adjustment, the Trust is required to make payments of taxes, penalties and interest, cash available for distribution to Trust unitholders might be substantially reduced. Additionally, the Trust may be required to allocate an adjustment disproportionately among Trust unitholders, causing the publicly traded Trust units to have different capital accounts, unless the IRS issues further guidance.
Trust unitholders will be required to pay taxes on their share of the Trust's income even if they do not receive any cash distributions from the Trust.
Because the Trust unitholders will be treated as partners to whom the Trust will allocate taxable income that could be different in amount than the cash the Trust distributes, Trust unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of the Trust's taxable income even if they receive no cash distributions from the Trust. Trust unitholders may not receive cash distributions from the Trust
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equal to their share of the Trust's taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of the Trust units could be more or less than expected.
Trust unitholders that sell their Trust units will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those Trust units. Because distributions in excess of the Trust unitholders allocable share of the Trust's net taxable income decrease the tax basis in such Trust unitholders' Trust units, the amount, if any, of such prior excess distributions with respect to the Trust units sold will, in effect, become taxable income if Trust units are sold at a price greater than the tax basis in those Trust units, even if the price received is less than the original cost of the Trust units. Furthermore, a substantial portion of the amount realized, whether or not there is a net taxable gain on the sale, may be taxed as ordinary income due to potential recapture items, including depletion recapture.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning the Trust units that may result in adverse tax consequences to them.
Investment in Trust units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons could result in differing tax consequences. For example, some of the Trust income allocated to organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income which would be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal income tax returns and pay tax on their share of the Trust's taxable income or proceeds from the sale of Trust units.
The Trust will treat each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
Due to a number of factors, including the Trust's inability to match transferors and transferees of Trust units, the Trust has adopted positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely alter the tax effects of an investment in Trust units. It also could affect the timing of any tax benefits or the amount of gain from the sale of Trust units by Trust unitholders and could have a negative impact on the value of the Trust units or result in audit adjustments to Trust unitholders tax returns.
The Trust prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly record date in such quarter, instead of on the basis of the date a particular Trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record ownership of the Trust units on the quarterly record date in such quarter instead of on the basis of the date a particular Trust unit is transferred.
Final Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferors and transferees, although these regulations do not specifically authorize all aspects of the proration method the Trust has adopted. If the IRS were to challenge the Trust's proration method, the Trust may be required to change its allocation of items of income, gain, loss and deduction among the Trust unitholders and the costs to the Trust of implementing and reporting under any such changed method may be significant.
A Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of those Trust units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those Trust units during the period of the loan and may recognize gain or loss from the disposition.
Because a Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of the loaned Trust units, the unitholder may no longer be treated for tax
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purposes as a partner with respect to those Trust units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the Trust's income, gain, loss or deduction with respect to those Trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Trust units could be fully taxable as ordinary income.
The Trust has adopted certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders. The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
The U.S. federal income tax consequences of the ownership and disposition of Trust units will depend in part on the Trust's estimates of the relative fair market values, and the initial tax bases of the Trust's assets. Although the Trust may from time to time consult with professional appraisers regarding valuation matters, the Trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by Trust unitholders might change, and Trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
Trust unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in Trust units.
In addition to U.S. federal income taxes, Trust unitholders will likely be subject to other taxes, including Oklahoma state income taxes, even if they do not live in Oklahoma. Trust unitholders will likely be required to file Oklahoma state income tax returns and pay Oklahoma state income tax. Further, Trust unitholders may be subject to penalties for failure to comply with those requirements. It is each Trust unitholder's responsibility to file all U.S. federal, state, local and non-U.S. tax returns.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 1C. Cybersecurity
The Trust has no directors or executive officers. The Trust falls under the cybersecurity program of The Bank of New York Mellon Corporation (“BNY Mellon”). As further described in its 2023 Annual Report, BNY Mellon maintains a broad range of defenses aimed at remaining abreast of and responding to evolving cybersecurity threats impacting it, its operations, its clients, its third-party service providers and the broader financial services sector.
Risk Management Strategy and Procedures
BNY Mellon has implemented policies and procedures designed to detect, prevent and respond to malicious and accidental disruptions to the delivery of critical technology services. BNY Mellon’s cybersecurity strategy and procedures are embedded in its Three Lines of Defense model.
As part of its first line of defense, BNY Mellon maintains a dedicated Information Security Division (“ISD”), led by the Chief Information Security Officer (the “CISO”), that is responsible for the day-to-day management of risks from cybersecurity threats. ISD’s responsibilities include cyber threat intelligence, incident response and other cybersecurity operations aimed at enabling BNY Mellon to identify, assess and manage existing and emerging cybersecurity threats. ISD monitors for potential threats and communicates relevant risks to the CISO and other members of executive management. Additionally, ISD maintains a cybersecurity incident response and reporting process pursuant to which cybersecurity incidents are classified according to their severity based upon an assessment of multiple factors. Certain cybersecurity incidents may activate enterprise-wide resiliency processes, which include, among other things, escalation through the management and Board committee structures described below. BNY Mellon also has standing arrangements with third parties to assist BNY Mellon in identifying, assessing and managing cybersecurity threats, including in connection with risk assessments, penetration testing, legal advice and other aspects of BNY Mellon’s cybersecurity risk management and incident response processes.
BNY Mellon has a defined third-party governance framework to help manage the risk posed to it by the use of third‑party service providers. BNY Mellon evaluates the risk posed by third-party service engagements based on
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multiple factors. BNY Mellon has protocols that seek to mitigate cybersecurity risks associated with third-party service providers based on the risk level assigned to such third party, which may include mandatory contractual obligations or the implementation of additional controls by BNY Mellon and/or the applicable service provider.
ISD is subject to ongoing review and challenge from Technology Risk Management, which is a part of the independent second line of defense risk function. Technology Risk Management, together with the broader Risk & Compliance group, is responsible for and manages BNY Mellon’s risk management framework and establishes guidance for ISD and management designed to help identify, assess and manage cybersecurity risk.
BNY Mellon’s Internal Audit function serves as the third line of defense and provides an independent view on how effectively the organization as a whole manages cybersecurity risk.
Risk Management oversight and governance
BNY Mellon’s management is responsible for assessing and managing BNY Mellon’s material risks from cybersecurity threats with oversight provided by its Board of Directors (the “Board”) and the Board committees. The Risk Committee of the Board has primary responsibility for oversight of the overall operation of BNY Mellon’s risk management framework, including policies and practices addressing cybersecurity risk, and is responsible for the oversight of the second line of defense with respect to its cybersecurity risk management responsibilities. The Technology Committee of the Board and the full Board regularly receive reports and briefings from management concerning cybersecurity matters, including any significant changes to BNY Mellon’s cybersecurity program. BNY Mellon also has protocols for escalating cybersecurity threats and incidents to the Technology Committee of the Board and the full Board. In addition, the Audit Committee of the Board monitors and oversees the performance of Internal Audit, including with respect to its cybersecurity risk management responsibilities.
At the management level, BNY Mellon’s Technology Oversight Committee, which is the senior management committee responsible for the governance and oversight of BNY Mellon’s significant technology projects and initiatives, reviews reports from management concerning ISD and is responsible for, among other things, escalating issues, including significant cybersecurity threats and incidents, to the Technology Committee of the Board. The Technology Oversight Committee is chaired by the Chief Information Officer (the “CIO”) and its members include the CISO.
BNY Mellon’s Technology Risk Committee is responsible for, among other things, overseeing and reviewing significant cybersecurity incidents. The Technology Risk Committee receives reports from management and has protocols for escalating certain issues and risks to the Senior Risk and Control Committee and the Risk Committee of the Board. The Technology Risk Committee is co-chaired by the Head of Technology Risk and Control and the Chief Technology Risk Officer, and the CISO is a member.
BNY Mellon’s CIO, CISO and Chief Technology Risk Officer each have extensive experience in assessing and managing risks from cybersecurity threats. BNY Mellon’s CISO joined BNY Mellon in 2022 and previously served as head of information security at a Fortune 500 biopharmaceutical company and an information technology company, as well as the Global Chief Technology Officer at a large cybersecurity company. BNY Mellon’s CIO has served in that position since 2017 and previously held roles as Chief Information Officer, Chief Technology Officer, and numerous other technology management positions at other large financial institutions. BNY Mellon’s Chief Technology Risk Officer joined BNY Mellon in 2021 and previously served as Global Head of Technology Risk Management, Chief Information Security Officer, Global Head of Cyber Risk and Operational Resilience and Chief Risk Officer for Technology and Operations at other large financial institutions.
The Operator, Diversified, is responsible for the oversight and overall management of the Underlying Properties. The Trust also relies on Diversified's Enterprise Risk Management ("ERM") framework for cybersecurity risk management and strategy relating to the operation of the Underlying Properties. Key aspects of Diversified's cybersecurity risk management, strategy and governance are summarized below. As of December 31, 2023, cybersecurity risks have not materially affected the business of the Underlying Properties or the Trust's results of operations or financial condition.
Cybersecurity is a component of Diversified's ERM Program. The ERM program entails risk identification, assessment, prioritization, monitoring and mitigation processes, which are continually evaluated and enhanced. The risk assessment process takes into account broader risks such as strategic, operational and regulatory and financial implications. Additionally, the ERM program risk assessment is discussed with members of Diversified's Senior Leadership Team and its Audit & Risk Committee, which includes members of Diversified's Board of Directors.
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In addition to Diversified's ERM Program, Diversified's governing policies and procedures create a structured approach to managing cybersecurity risk. Diversified's network is designed using a Zero Trust Approach ("ZTA") and is segmented to include several layers of security, including least privilege access, conditional access policies, and multi-factor authentication ("MFA"). The ZTA encompasses identity, endpoints, infrastructure, data, and applications for enhanced visibility, intelligence and automation for Diversified's security team. Diversified network environment is completely cloud based and is therefore continuously tested from both trusted and untrusted sources - both external and internal to its networks, rather than relying on a one-time penetration testing approach. Additionally, Diversified's employees are subject to annual cybersecurity training and e-learning sessions as employees are viewed as the first line of defense against cybersecurity attacks.
Diversified engages with key technology partners and suppliers to ensure potentially vulnerable systems are identified and secured, including continuous incident monitoring, regular threat testing, and control and protection of confidential information. Third-party providers are subject to an assessment every 90 days, based on various criteria, such as whether the third-party provider has access to Diversified's network, data and information systems. Third-party providers that have access are required to use MFA and their system and organization controls reports are obtained and reviewed annually.
A dedicated Cybersecurity Council is responsible for Diversified's cybersecurity risk management and strategy. The Cybersecurity Council includes certain members of Diversified's Senior Leadership Team, including the Chief Operating Officer, Chief Financial Officer, Chief Information Officer and General Counsel. This Council meets at least once a quarter to discuss cybersecurity issues, risks and strategies. The Cybersecurity Council briefs Diversified's Board of Directors at least quarterly, on all security initiatives, including assessing risks, incidents and any remediation taken. Additionally, the Council is briefed on efforts to improve Diversified's network security systems and enhanced employee trainings. The membership of this council is adequately trained and educated to provide proper governance, risk management and control of the cybersecurity program utilizing the National Institute of Standards and Technology framework.
ITEM 2. Properties
Reference is made to "Item 1 – Business," which is incorporated herein by reference.
ITEM 3. Legal Proceedings
There are no legal proceedings to which the Trust is a named party. However, the Trustee has been advised by Diversified that the Trust may from time to time be subject to litigation in the ordinary course of business for certain matters that include the Royalty Interests. While Diversified has advised the Trustee that it does not presently believe any pending litigation will have a net material adverse effect to the Trust, in the event such matters are adjudicated or settled in a material amount and charges are made against royalty income, such charges could have a material impact on the Trust's future royalty income.
The Trust is not a party to any lawsuit and the Operator has advised the Trustee that it is not aware of any pending or threatened lawsuit or dispute that individually or in the aggregate with other pending or threatened lawsuits or disputes is likely to have a material adverse effect on the Trust's financial position or distributable income.
ITEM 4. Mine Safety Disclosures
Not applicable.
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PART II
ITEM 5. Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units
Common Units Representing Beneficial Interests
As of March 28, 2024, 46,750,000 common units representing beneficial interests in the Trust were outstanding and were held by 16 certified unitholders of record.
The Trust's common units began trading on March 2, 2020 under the symbol "CHKR" on the OTC Pink. Previously the Trust's common units were listed and traded on the New York Stock Exchange. Over-the-counter market quotations may reflect inter-dealer prices, without retail mark-up, mark-down or commissions and may not necessarily represent actual transactions.
The Trust is required to make quarterly cash distributions of substantially all of its quarterly cash receipts, after deducting the Trust's administrative expenses and any cash reserves, on or about 60 days following the completion of each quarter through (and including) the quarter ending June 30, 2031. Quarterly distributions to Trust unitholders will generally include royalty income attributable to sales of oil, natural gas and NGL for three months, including the first two months of the quarter just ended and the last month of the prior quarter. The first quarterly distribution was made on December 28, 2011 to record unitholders as of December 15, 2011. During the year ended December 31, 2023, four distributions were paid. See Liquidity and Capital Resources below and Note 5 to the financial statements contained in Part II, Item 8 of this Annual Report for more information regarding the distributions.
Pursuant to the Trust Agreement, if at any time the Trust's cash on hand (including cash reserves) is not sufficient to pay the Trust's ordinary course expenses as they become due, the Operator will loan funds to the Trust necessary to pay such expenses. Any funds loaned by the Operator pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other current liabilities arising in the ordinary course of the Trust's business, and may not be used to satisfy Trust indebtedness for borrowed money of the Trust. If the Operator loans funds pursuant to this commitment, unless the Operator agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. As of December 31, 2023 and December 31, 2022, there were no loans outstanding.
Equity Compensation Plans
The Trust does not maintain any equity compensation plans or any other compensation arrangements under which Trust units or other equity securities of the Trust may be issued.
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities
None.
ITEM 6. [RESERVED]
ITEM 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis is intended to help the reader understand the Trust's financial condition and results of operations. This discussion and analysis should be read in conjunction with the audited financial statements and the accompanying notes relating to the Trust and the Underlying Properties included in Part II, Item 8 of this Annual Report and The Underlying Properties and the Royalty Interests and Discussion and Analysis of Results from the Underlying Properties included in Part I, Item 1 of this Annual Report.
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Overview
The Trust is a statutory trust formed in June 2011 under the Delaware Statutory Trust Act. The business and affairs of the Trust are managed by the Trustee and, as necessary, the Delaware Trustee. The Trust does not conduct any operations or activities other than owning the Royalty Interests and activities related to such ownership. The Trust’s purpose is generally to own the Royalty Interests, to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalty Interests and to perform certain administrative functions in respect of the Royalty Interests and the Trust units. The Trust derives all or substantially all of its income and cash flow from the Royalty Interests. The Trust is treated as a partnership for U.S. federal income tax purposes.
Concurrent with the Trust's initial public offering in November 2011, Chesapeake conveyed the Royalty Interests to the Trust effective July 1, 2011, which included interests in (a) 69 Producing Wells in the Colony Granite Wash play and (b) 118 Development Wells that have since been drilled in the Colony Granite Wash play on properties within the AMI. Chesapeake was obligated to drill, cause to be drilled or participate as a non-operator in the drilling of the Development Wells from drill sites in the AMI on or prior to June 30, 2016. Additionally, based on Chesapeake’s assessment of the ability of a Development Well to produce in paying quantities, Chesapeake was obligated to either complete and tie into production or plug and abandon each Development Well. As of June 30, 2016, Chesapeake had fulfilled its drilling obligation under the development agreement. The Operator retained an interest in each of the Producing Wells and Development Wells, and Diversified currently operates approximately 96% of the Producing Wells and the completed Development Wells.
The Trust was not responsible for any costs related to the drilling of the Development Wells and is not responsible for any other operating or capital costs of the Underlying Properties, and Chesapeake was not permitted to drill and complete any well in the Colony Granite Wash formation on acreage included within the AMI for its own account until it satisfied its drilling obligation to the Trust.
The Royalty Interests entitle the Trust to receive 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) from the sales of production of oil, natural gas and NGL attributable to Diversified’s net revenue interest in the Producing Wells and 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and natural gas liquids ("NGL") production attributable to Diversified’s net revenue interest in the Development Wells. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil, natural gas and NGL produced. However, the Trust is not responsible for costs of marketing services provided by Diversified or Diversified affiliates.
The Trust is required to make quarterly cash distributions of substantially all of its cash receipts, after deducting the Trust’s administrative expenses, on or about 60 days following the completion of each calendar quarter through (and including) the quarter ending June 30, 2031. During the year ended December 31, 2023, four distributions were paid. See Liquidity and Capital Resources below and Note 5 to the financial statements contained in Part II, Item 8 of this Annual Report for more information regarding the distributions.
The amount of Trust revenues and cash distributions to Trust unitholders fluctuates from quarter to quarter depending on several factors, including:
•oil, natural gas and NGL prices received;
•volumes of oil, natural gas and NGL produced and sold;
•certain post-production expenses and any applicable taxes; and
•the Trust’s expenses.
Results of Trust Operations
Below is a discussion of changes in our results of operations for 2023 compared to 2022. A discussion of changes in our results of operations for 2022 compared to 2021 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2022 as filed with the SEC on March 24, 2023.
The quarterly payments to the Trust with respect to the Royalty Interests are based on the amount of proceeds actually received by the Operator during the preceding calendar quarter. Proceeds from production are typically
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received by the Operator approximately one month after the month of production. Due to the timing of the payment of production proceeds, quarterly distributions made by the Operator to the Trust generally include royalties attributable to sales of oil, natural gas and NGL for three months, comprised of the first two months of the quarter just ended and the last month of the quarter prior to that one. The Operator is required to make the Royalty Interest payments to the Trust within 35 days of the end of each calendar quarter. During the year ended December 31, 2023, the Trust received payments on the Royalty Interests representing royalties attributable to proceeds from sales of oil, natural gas and NGL for the period from September 1, 2022 through August 31, 2023. During the year ended December 31, 2022, the payments received by the Trust represented royalties attributable to proceeds from sales of oil, natural gas and NGL for the period from September 1, 2021 through August 31, 2022.
The Trust's revenues and distributable income available to unitholders have been adversely affected throughout 2023 by a decline in production and lower commodity prices. Due to natural declines, the Trust expects production to decline in the future and expects distributable income to be adversely affected.
During the years ended December 31, 2023 and 2022, the Trust recognized no impairments of the Royalty Interests.
Distributable Income. The Trust's distributable income was $8.0 million for the year ended December 31, 2023, compared to $13.0 million for the year ended December 31, 2022.
The $5.0 million decrease from 2022 to 2023 was primarily due to a decrease in the average realized prices received from sales of oil, natural gas and NGL with a slight revenue decrease attributable to a decrease in total production volumes in the production period from September 1, 2022 to August 31, 2023 (the "2023 production period") as compared to the production period from September 1, 2021 to August 31, 2022 (the "2022 production period"). See Royalty Income below for information regarding average prices received and sales volumes.
On a per unit basis, cash distributions during the year ended December 31, 2023 and attributable to the 2023 production period were $0.1721 per common unit as compared to $0.2778 per common unit for the year ended December 31, 2022 and attributable to the 2022 production period. Distributable income for the production periods described above was calculated as follows:
| Years Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | |||||||||||||||||||
| ($ in thousands, except per unit data) | ||||||||||||||||||||
| Revenues: | ||||||||||||||||||||
Royalty income(1) | $ | 10,693 | $ | 15,842 | ||||||||||||||||
| Total revenues | 10,693 | 15,842 | ||||||||||||||||||
| Expenses: | ||||||||||||||||||||
| Production taxes | (699) | (1,111) | ||||||||||||||||||
Trust administrative expenses(2) | (1,551) | (1,272) | ||||||||||||||||||
| Total expenses | (2,250) | (2,383) | ||||||||||||||||||
Cash withheld to increase cash reserves(3) | (395) | (471) | ||||||||||||||||||
| Distributable income available to unitholders | $ | 8,048 | $ | 12,988 | ||||||||||||||||
| Distributable income per common unit (46,750,000 units) | $ | 0.1721 | $ | 0.2778 | ||||||||||||||||
_____________________________________________________
(1)Net of certain post-production expenses.
(2)Includes the annual change in cash advance resulting in no change in administrative expenses in 2023 and an increase in administrative expenses totaling $50,000 in 2022.
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(3)The Trustee may increase or decrease the targeted amount of the cash reserve at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the unitholders. Without limiting the foregoing, the Trustee reviewed the adequacy and sufficiency of the existing cash reserve in 2021 and determined to withhold funds otherwise available for distribution to the unitholders each quarter to increase existing cash reserves by a total of approximately $3,200,000 over a period of several quarters, commencing with the distribution to unitholders for the fourth quarter 2021 (payable in 2022). As of December 31, 2023, $1,660,828 has been so withheld to increase cash reserves. Cash held in reserve will be invested as required by the trust agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to unitholders, together with interest earned on the funds.
Royalty Income. Royalty income to the Trust for the year ended December 31, 2023, and attributable to the 2023 production period, totaled $10.7 million based upon sales of production attributable to the Royalty Interests of 48 mbbls of oil, 1,400 mmcf of natural gas and 115 mbbls of NGL. Total production attributable to the Royalty Interests for the 2023 production period was 396 mboe. Average prices received for oil, natural gas and NGL production, including the impact of certain post-production expenses and excluding production taxes, during the 2023 production period were $74.63 per bbl of oil, $3.31 per mcf of natural gas and $21.70 per bbl of NGL, respectively.
Royalty income to the Trust for the year ended December 31, 2022, and attributable to the 2022 production period, totaled $15.8 million based upon sales of production attributable to the Royalty Interests of 60 mbbls of oil, 1,236 mmcf of natural gas and 153 mbbls of NGL. Total production attributable to the Royalty Interests for the 2022 production period was 419 mboe. Average prices received for oil, natural gas and NGL production, including the impact of certain post-production expenses and excluding production taxes, during the 2022 production period were $89.71 per bbl of oil, $4.24 per mcf of natural gas and $34.28 per bbl of NGL, respectively.
The decrease in the average price received per boe in the 2023 production period compared to the 2022 production period resulted in a $4.3 million decrease in royalty income. The decrease in sales volumes resulted in a $0.9 million decrease in royalty income, for a net decrease in royalty income of $5.2 million.
Production Taxes. Production taxes are calculated as a percentage of oil, natural gas and NGL revenues, net of any applicable tax credits. Production taxes for the year ended December 31, 2023, and attributable to the 2023 production period, totaled $0.7 million, or $1.77 per boe, or approximately 6.5% of royalty income, as compared to $1.1 million, or $2.65 per boe, or approximately 7.0% of royalty income for the year ended December 31, 2022, and attributable to the 2022 production period. The decrease in production taxes per boe from 2022 to 2023 was primarily due to decreased commodity prices.
Trust Administrative Expenses. Trust administrative expenses, including additional cash reserves, for the years ended December 31, 2023 and 2022 totaled $1.6 million and $1.3 million, respectively. Trust administrative expenses primarily consist of the administrative fees paid to the Trustee and the Administrative Servicer, and costs for accounting and legal services.
Liquidity and Capital Resources
The Trust’s principal sources of liquidity and capital are cash flows generated from the Royalty Interests. The Trust’s primary uses of cash are distributions to Trust unitholders, payments of production taxes, payments of Trust administrative expenses, including any reserves established by the Trustee for future liabilities, and repayment of loans and payments of expense reimbursements to the Operator for out-of-pocket expenses incurred on behalf of the Trust. Administrative expenses include payments to the Trustee and the Delaware Trustee as well as a quarterly fee of $50,000 to the Administrative Servicer pursuant to the Administrative Services Agreement. Each quarter, the Trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the Trust from the sales of oil, natural gas and NGL production attributable to the Royalty Interests during the quarter, over the Trust’s expenses for the quarter and any cash reserve for the payment of liabilities of the Trust.
The Trust is required to make quarterly cash distributions of substantially all of its cash receipts, after deducting the Trust’s administrative expenses, on or about 60 days following the completion of each calendar quarter through (and including) the quarter ending June 30, 2031. During the year ended December 31, 2023, four distributions
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were paid. The 2023 first quarter distribution of $0.0757 per common unit to common unitholders consisting of proceeds attributable to production from September 1, 2022 through November 30, 2022, was made on March 1, 2023 to record unitholders as of February 20, 2023. The 2023 second quarter distribution of $0.0487 per common unit, consisting of proceeds attributable to production from December 1, 2022 through February 28, 2023, was made on June 1, 2023 to record unitholders as of May 22, 2023. The 2023 third quarter distribution of $0.0178 per common unit, consisting of proceeds attributable to production from March 1, 2023 through May 31, 2023, was made on August 31, 2023 to record unitholders as of August 21, 2023. The 2023 fourth quarter distribution of $0.0336 per common unit, consisting of proceeds attributable to production from June 1, 2023 through August 31, 2023, was made on November 30, 2023 to record unitholders as of November 20, 2023.
The following is a summary of distributable income and distributable income per common unit by quarter for the years ended December 31, 2023 and 2022 (in thousands except per unit amounts):
| 2023 | Q1 | Q2 | Q3 | Q4 | Total | |||||||||||||||||||||||||||
| Distributable income | $ | 3,537 | $ | 2,274 | $ | 832 | $ | 1,405 | $ | 8,048 | ||||||||||||||||||||||
| Distributable income per common unit | $ | 0.0757 | $ | 0.0487 | $ | 0.0178 | $ | 0.0300 | $ | 0.1721 | ||||||||||||||||||||||
| 2022 | Q1 | Q2 | Q3 | Q4 | Total | |||||||||||||||||||||||||||
| Distributable income | $ | 3,120 | $ | 2,524 | $ | 3,968 | $ | 3,376 | $ | 12,988 | ||||||||||||||||||||||
| Distributable income per common unit | $ | 0.0667 | $ | 0.0540 | $ | 0.0849 | $ | 0.0722 | $ | 0.2778 | ||||||||||||||||||||||
On February 5, 2024, the Trust announced that a cash distribution of $0.0214 per common unit, consisting of proceeds attributable to production from September 1, 2023 to November 30, 2023, would be paid to common unitholders of record as of February 19, 2024 on February 29, 2024. Such payment was made in accordance with this announcement. See Note 6 to the financial statements contained in Part II, Item 8 of this Annual Report for additional information.
The Trustee may increase or decrease the targeted amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the unitholders. Without limiting the foregoing, the Trustee reviewed the adequacy and sufficiency of the existing cash reserve in 2021 and determined to withhold funds otherwise available for distribution to the unitholders each quarter to increase existing cash reserves by a total of approximately $3,200,000 over a period of several quarters, commencing with the distribution to unitholders for the fourth quarter 2021 (payable in 2022). As of December 31, 2023, $1,660,828 has been so withheld to increase cash reserves. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to unitholders, together with interest earned on the funds.
The Trustee can authorize the Trust to borrow money to pay Trust expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee as a lender provided the terms of the loan are fair to the Trust unitholders. The Trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the Trust at least equals amounts paid by the Trustee on similar deposits, and make other short-term investments with the funds distributed to the Trust. The Trustee may also hold funds awaiting distribution in a non-interest bearing account.
Pursuant to the Trust Agreement, if at any time the Trust’s cash on hand (including cash reserves) is not sufficient to pay the Trust’s ordinary course expenses as they become due, the Operator will loan funds to the Trust necessary to pay such expenses. Any funds loaned by the Operator pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other current liabilities arising in the ordinary course of the Trust’s business, and may not be used to satisfy Trust indebtedness for borrowed money of the Trust. If the Operator loans funds pursuant to this commitment, unless the Operator agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. As of December 31, 2023 and December 31, 2022, there were no loans outstanding.
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Off-Balance Sheet Arrangements
The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.
Critical Accounting Policies
Basis of Accounting. Financial statements of the Trust differ from financial statements prepared in accordance with GAAP as the Trust records revenues when received and expenses when paid and may also establish certain cash reserves for contingencies that would not be accrued in financial statements prepared in accordance with GAAP. This non-GAAP, other comprehensive basis of accounting corresponds to the accounting principles permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust's assets, trust corpus, earnings and distributions as follows:
Investment in Royalty Interests. The conveyance of the Royalty Interests to the Trust was accounted for as a transfer of properties between entities under common control and thus the Trust recorded the Royalty Interests at the historical cost of Chesapeake (“Investment in Royalty Interests”), which was based on an allocation of the historical net book value of Chesapeake's full cost pool according to the fair value of the Royalty Interests relative to the fair value of Chesapeake's proved reserves. The carrying value of the Trust's Investment in Royalty Interests will not necessarily be indicative of the fair value of such Royalty Interests.
This investment is amortized as a single cost center on a units-of-production basis over total proved reserves. Such amortization does not reduce distributable income, rather it is charged directly to Trust corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.
On a quarterly basis, the Trust evaluates the carrying value of the Investment in Royalty Interests under the full cost accounting method prescribed by the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, the carrying value of the Investment in Royalty Interests may not exceed an amount equal to the PV-10 for the Trust's proved reserves. Any write-downs resulting from the ceiling test will be non-cash charges to Trust corpus and will not affect distributable income.
Revenues and Expenses. Revenues received by the Trust are net of existing royalties and overriding royalties associated with the Operator's interests and are reduced by certain post-production expenses, production taxes and other allowable expenses, such as the Trust's administrative expenses, in order to determine distributable income. The Royalty Interests are not burdened by field and lease operating expenses.
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
Oil, Natural Gas and NGL Price Risk. The Trust’s primary asset and source of income is the Royalty Interests, which generally entitles the Trust to receive a portion of the net proceeds from the sales of oil, natural gas and NGL from the Underlying Properties. The Trust is significantly exposed to fluctuations in the prices received for oil, natural gas and NGL produced and sold.
Credit Risk Associated With the Operator. The Trust is highly dependent on the Operator for multiple services, including the operation of wells, remittance of net proceeds generated by the interests in specified oil and natural gas properties located within the AMI, and administrative services performed on behalf of the Trust. The Operator's ability to perform its obligations to the Trust will depend on its future results of operations, financial condition, liquidity and ability to comply with the financial covenants contained in its debt instruments, which in turn will depend upon the supply and demand for oil, natural gas and NGL, prevailing economic conditions and financial, business and other factors, many of which are beyond the Operator’s control. In the event of a bankruptcy of the Operator or its wholly-owned subsidiaries, the Operator could be unable to provide support to the Trust through loans and performance of its management duties.
44
ITEM 8. Financial Statements and Supplementary Data
| Page | |||||
45
Report of Independent Registered Public Accounting Firm
To the Unitholders of Chesapeake Granite Wash Trust and The Bank of New York Mellon Trust Company, N.A., as Trustee
Opinion on the Financial Statements
We have audited the accompanying statements of assets and trust corpus (modified cash basis) of Chesapeake Granite Wash Trust (the “Trust”) as of December 31, 2023 and 2022, and the related statements of distributable income and of changes in trust corpus for the years then ended, including the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets and trust corpus of the Trust as of December 31, 2023 and 2022, and its distributable income and its changes in trust corpus for the years then ended in conformity with the modified cash basis of accounting described in Note 2.
Basis for Opinion
These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Basis of Accounting
As described in Note 2, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the Trustee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil, Natural Gas and NGL Reserves on Net Investment in Royalty Interests
As described in Note 2 to the financial statements, the Trust’s investment in royalty interests is amortized as a single cost center on a units-of-production basis over total proved reserves. Such amortization does not reduce distributable income, but rather it is charged directly to Trust corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date such revisions are known. Management
46
evaluates the carrying value of the investment in royalty interests under the full cost accounting method on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, the carrying value of the investment in royalty interests may not exceed an amount equal to the sum of the present value (using a 10% discount rate) of the estimated future net revenues from proved reserves. The Trust’s net investment in royalty interests balance was $7.5 million as of December 31, 2023, and amortization of investment in royalty interests for the year ended December 31, 2023 was $742 thousand. As disclosed by management, proved reserve quantities attributable to the royalty interests are calculated by multiplying the gross reserves for each property attributable to the operator's interest by the net revenue interest assigned to the Trust in each property. Management applies significant judgment in developing the estimates of reserve volumes including estimates of oil, natural gas and NGL reserves and their values, future production rates, and commodity pricing differentials. The estimates of proved oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.
The principal considerations for our determination that performing procedures relating to the impact of proved oil, natural gas and NGL reserves on the net investment in royalty interests is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil, natural gas and NGL reserves, (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil, natural gas and NGL reserves and management’s assumptions applied to the data used in the ceiling test related to the commodity pricing differentials.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. The work of management’s specialists was used in performing procedures to evaluate the reasonableness of the proved oil, natural gas and NGL reserves. As a basis for using this work, the specialists’ qualifications were understood and the Trust’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing of the data used by the specialists, and evaluating the specialists’ findings. The procedures performed also included, among others, i) testing the completeness and accuracy of the data related to commodity pricing differentials used in the ceiling test and ii) evaluating whether the assumptions applied to the data were reasonable considering the past performance of the Trust.
/s/PricewaterhouseCoopers LLP
Birmingham, Alabama
April 1, 2024
We have served as the Trust’s auditor since 2022.
47
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Trustee and Unitholders
Chesapeake Granite Wash Trust
Opinion on the financial statements
We have audited the accompanying statements of distributable income and changes in trust corpus of Chesapeake Granite Wash Trust (the "Trust") for the year ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, its distributable income and its changes in trust corpus for the year ended December 31, 2021, in conformity with the modified cash basis of accounting described in Note 2 to the financial statements.
Basis of accounting
We draw attention to Note 2 of the financial statements, which describes the basis of accounting. The financial statements are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
Basis for opinion
These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
Critical audit matters
Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Trustee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.
/s/ GRANT THORNTON LLP
We served as the Trust’s auditor for 2021.
Oklahoma City, Oklahoma
April 1, 2024
48
CHESAPEAKE GRANITE WASH TRUST
STATEMENTS OF ASSETS AND TRUST CORPUS
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| ($ in thousands) | ||||||||||||||
| ASSETS: | ||||||||||||||
| Cash and cash equivalents | $ | 2,688 | $ | 2,564 | ||||||||||
| Investment in royalty interests | 487,793 | 487,793 | ||||||||||||
| Less: accumulated amortization | (480,277) | (479,535) | ||||||||||||
| Net investment in royalty interests | 7,516 | 8,258 | ||||||||||||
| Total assets | $ | 10,204 | $ | 10,822 | ||||||||||
| TRUST CORPUS: | ||||||||||||||
Trust corpus; 46,750,000 common units issued and outstanding | 10,204 | 10,822 | ||||||||||||
| Total Trust corpus | $ | 10,204 | $ | 10,822 | ||||||||||
The accompanying notes are an integral part of these financial statements.
49
CHESAPEAKE GRANITE WASH TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
| Years Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| ($ in thousands, except per unit data) | ||||||||||||||||||||
| REVENUES: | ||||||||||||||||||||
| Royalty income | $ | 10,693 | $ | 15,842 | $ | 8,697 | ||||||||||||||
| Total revenues | 10,693 | 15,842 | 8,697 | |||||||||||||||||
| EXPENSES: | ||||||||||||||||||||
| Production taxes | (699) | (1,111) | (590) | |||||||||||||||||
| Trust administrative expenses | (1,551) | (1,272) | (1,370) | |||||||||||||||||
| Total expenses | (2,250) | (2,383) | (1,960) | |||||||||||||||||
| Cash reserves withheld | (395) | (471) | (197) | |||||||||||||||||
| Distributable income available to unitholders | $ | 8,048 | $ | 12,988 | $ | 6,540 | ||||||||||||||
Distributable income per common unit (46,750,000 units) | $ | 0.1721 | $ | 0.2778 | $ | 0.1399 | ||||||||||||||
CHESAPEAKE GRANITE WASH TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
| Years Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| ($ in thousands) | ||||||||||||||||||||
TRUST CORPUS: Beginning of period | $ | 10,822 | $ | 11,240 | $ | 13,147 | ||||||||||||||
| Cash reserve surplus | 294 | 471 | 355 | |||||||||||||||||
| Amortization of investment in royalty interests | (742) | (889) | (1,425) | |||||||||||||||||
| Impairment of investment in royalty interests | — | — | (837) | |||||||||||||||||
| Distributable income available to unitholders | 8,048 | 12,988 | 6,540 | |||||||||||||||||
Distributions paid to unitholders(1) | (8,218) | (12,988) | (6,540) | |||||||||||||||||
TRUST CORPUS: End of period | $ | 10,204 | $ | 10,822 | $ | 11,240 | ||||||||||||||
(1)See Note 5 - Distributions to Unitholders.
The accompanying notes are an integral part of these financial statements.
50
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS
1.Organization of the Trust
Chesapeake Granite Wash Trust (the “Trust”) is a statutory trust formed in June 2011 under the Delaware Statutory Trust Act pursuant to an initial trust agreement by and among Chesapeake Energy Corporation ("Chesapeake"), as Trustor, The Bank of New York Mellon Trust Company, N.A, as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”).
The Trust was created to own royalty interests in the Producing Wells and Development Wells (as defined herein) (the “Royalty Interests”) for the benefit of Trust unitholders pursuant to a trust agreement dated as of June 29, 2011, and subsequently amended and restated as of November 16, 2011 by and among Tapstone Energy, LLC ("Tapstone") (as successor to Chesapeake and Chesapeake Exploration, L.L.C., a wholly owned subsidiary of Chesapeake), the Trustee and the Delaware Trustee (the “Trust Agreement”). The Royalty Interests are derived from Chesapeake’s interests in the Underlying Properties, all of which are located within an area of mutual interest (the "AMI") in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma. Chesapeake conveyed the Royalty Interests to the Trust from (a) Chesapeake’s interests in the Producing Wells and (b) Chesapeake’s interests in the Development Wells that have since been drilled on properties held by Chesapeake within the AMI. Pursuant to a development agreement with the Trust, Chesapeake was obligated to drill, cause to be drilled or participate as a non-operator in the drilling of the 118 Development Wells by June 30, 2016. Additionally, based on Chesapeake’s assessment of the ability of a Development Well to produce in paying quantities, Chesapeake was obligated to either complete and tie into production or plug and abandon each Development Well. The Operator retained an interest in each of the Producing Wells and Development Wells, and Diversified Energy Company PLC ("Diversified"), and its subsidiaries, currently operates approximately 96% of the Producing Wells and the completed Development Wells. As of June 30, 2016, Chesapeake had fulfilled its drilling obligation under the development agreement.
The business and affairs of the Trust are managed by the Trustee. The Trust Agreement limits the Trust’s business activities generally to owning the Royalty Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. The Royalty Interests in the Producing Wells entitle the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and natural gas liquids ("NGL") production attributable to the Operator’s net revenue interest in the Producing Wells. The Royalty Interests in the Development Wells entitle the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to the Operator’s net revenue interest in the Development Wells.
Through an initial public offering in November 2011, the Trust sold to the public 23,000,000 common units, representing beneficial interests in the Trust, for cash proceeds of approximately $409.7 million, net of offering costs. The Trust delivered the net proceeds of the initial public offering, along with 12,062,500 common units and 11,687,500 subordinated units, to certain wholly owned subsidiaries of Chesapeake in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions, there were 46,750,000 Trust units issued and outstanding, consisting of 35,062,500 common units and 11,687,500 subordinated units which were converted into common units on a one-for-one basis as of June 30, 2017.
On December 11, 2020, Tapstone acquired 23,750,000 common units and the Underlying Properties of the Trust from Chesapeake in a 363 transaction under the Bankruptcy Code. All of Chesapeake’s responsibilities and obligations regarding the Trust transferred to Tapstone in connection with the acquisition, pursuant to the Assignment Agreement. As such, duties previously performed by Chesapeake with respect to the Trust were performed by Tapstone and all agreements between Chesapeake and the Trust transferred from Chesapeake to Tapstone.
On October 6, 2021, Tapstone Energy Holdings, LLC, the parent of Tapstone, ("Tapstone Holdings"), entered into an Agreement and Plan of Merger (the "Merger Agreement") with Diversified, the parent of Diversified Production LLC ("Diversified Production"), and certain of its affiliates, including Diversified Production. Upon the terms and subject to the conditions set forth in the Merger Agreement, a wholly owned subsidiary of Diversified merged with and into Tapstone Holdings with Tapstone Holdings as the surviving entity, resulting in Tapstone
51
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
Holdings and Tapstone becoming wholly owned subsidiaries of Diversified. The terms and conditions of the Merger Agreement were fulfilled on December 7, 2021, and Tapstone Holdings became a wholly owned subsidiary of Diversified (the "Merger").
Tapstone’s right, title and interest in and to, and all of its duties and obligations under all documents related to the Trust (including the Amended and Restated Trust Agreement (dated as of November 16, 2011), the Administrative Services Agreement (dated as of November 16, 2011) and the related royalty interest conveyances) remained unchanged as a result of the Merger, although there have been certain changes in the management of the Underlying Properties. However, as a result of the Merger, Diversified may be deemed the beneficial owner of the 23,750,000 common units of the Trust, representing the entire 50.8% beneficial ownership interest in the Trust held by Tapstone immediately prior to the effective time of the Merger. Following consummation of the Merger, duties previously performed by Tapstone and its subsidiaries with respect to the Trust are now performed by Diversified. On September 22, 2023, the 23,750,000 common units were assigned to DP Bluegrass LLC, another indirect, wholly-owned subsidiary of Diversified Production.
The Trust will dissolve and begin to liquidate on the Termination Date, and will soon thereafter wind up its affairs and terminate. At the Termination Date, (a) the Term Royalties will revert automatically to the Operator and (b) the Perpetual Royalties will be retained by the Trust and thereafter sold. The net proceeds of the sale of the Perpetual Royalties, as well as any remaining Trust cash reserves, will be distributed to the unitholders on a pro rata basis. The Operator will have a right of first refusal to purchase the Perpetual Royalties retained by the Trust at the Termination Date.
The Trust will not dissolve until the Termination Date, unless:
•the Trust sells all of the Royalty Interests;
•the aggregate quarterly cash distribution amounts for any four consecutive quarters is less than $1.0 million;
•the holders of a majority of the Trust units and a majority of the common units (excluding common units owned by Diversified and its affiliates), in each case voting in person or by proxy at a meeting of such holders at which a quorum is present, vote in favor of dissolution; except that at any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be a majority of the Trust units, including units owned by Diversified and its affiliates voting in person or by proxy at a meeting of such holders at which a quorum is present; notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units; or
•the Trust is judicially dissolved.
In the case of any of the foregoing, the Trustee would sell all of the Trust's assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders after payment, or reasonable provision for payment, of all Trust liabilities.
2.Accounting Policies
Basis of Accounting. Financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") as the Trust records revenues when received and expenses when paid and may also establish certain cash reserves for contingencies which would not be accrued in financial statements prepared in accordance with GAAP. This non-GAAP comprehensive basis of accounting corresponds to the accounting principles permitted for royalty trusts by the United States Securities and Exchange Commission ("SEC") as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the
52
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
modified cash basis as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.
Use of Estimates. The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets, liabilities and Trust corpus during the reporting period. Management applies significant judgement in developing the estimates of reserve volumes including estimates of oil, natural gas and NGL reserves and their values, future production rates, and commodity pricing differentials. The estimates of proved oil, natural gas and NGL reserves have been developed by specialists, specifically petroleum engineers. These reserves are used to compute the Trust’s amortization of the Investment in Royalty Interests (as defined in Investment in Royalty Interests below) and, as necessary, to evaluate potential impairments of Investment in Royalty Interests. Actual results could differ from those estimates.
Risks and Uncertainties. The Trust’s revenue and distributions are substantially dependent upon the prevailing and future prices for oil, natural gas and NGL, each of which depends on numerous factors beyond the Trust’s control such as economic conditions, regulatory developments and competition from other energy sources. Oil, natural gas and NGL prices historically have been volatile and may be subject to significant fluctuations in the future, which would have an impact on revenues and distributable income. The Trust does not have the ability to enter into derivative contracts to mitigate the effect of this price volatility.
The Operator’s ability to perform its obligations to the Trust will depend on its future results of operations, financial condition and liquidity, which in turn will depend upon the supply and demand for oil, natural gas and NGL, prevailing economic conditions and financial, business and other factors, many of which are beyond the Operator’s control.
In the event of a bankruptcy of the Operator or its wholly-owned subsidiaries, the Operator could be unable to provide support to the Trust through loans and performance of its management duties.
Cash and Cash Equivalents. Cash equivalents include all highly-liquid instruments with maturities of three months or less at the time of acquisition. The Trustee maintains a minimum cash reserve of $1.0 million and may, at the Trustee’s discretion, reserve funds for future expected administrative expenses.
Investment in Royalty Interests. The Investment in Royalty Interests is amortized as a single cost center on a units-of-production basis over total proved reserves. Such amortization does not reduce distributable income, rather it is charged directly to Trust corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date such revisions are known. The carrying value of the Trust’s Investment in Royalty Interests will not necessarily be indicative of the fair value of such Royalty Interests. The Trust is not burdened by development costs of the Royalty Interests.
On a quarterly basis, the Trust evaluates the carrying value of the Investment in Royalty Interests under the full cost accounting rules of the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, the carrying value of the Investment in Royalty Interests may not exceed an amount equal to the sum of the present value (using a 10% discount rate) of the estimated future net revenues from proved reserves. During the years ended December 31, 2023 and 2022, the Trust did not recognized any impairment of the Royalty Interests. Due to the decrease in commodity prices in 2021, the present value of the estimated future net revenues from proved reserves fell below the carrying value of the Investment in Royalty Interest, resulting in an impairment recognized of $0.8 million during the year ended December 31, 2021.
Loan Commitment. Pursuant to the Trust Agreement, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course expenses as they become due, the Operator will loan funds to the Trust necessary to pay such expenses. Such loans will be recorded as a liability on the Statements of Assets, Liabilities and Trust Corpus until repaid. A loan neither increases nor decreases distributions to unitholders; however, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount and unless the Operator agrees otherwise) until the loan is repaid. There were no loans outstanding as of December 31, 2023 and December 31, 2022.
Revenues and Expenses. Neither the Trust nor the Trustee is responsible for, or has any control over, any operating or capital costs of the Underlying Properties. The Trust’s revenues with respect to the Royalty Interests in the Underlying Properties are net of existing royalties and overriding royalties associated with the Operator's interests and are determined after deducting certain post-production expenses and any applicable taxes associated
53
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
with the Royalty Interests. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil, natural gas and NGL produced. However, the Trust is not responsible for costs of marketing services provided by the Operator or affiliates of the Operator. Cash distributions to unitholders will be reduced by the Trust’s general and administrative expenses.
Trust administrative expenses for the years ended December 31, 2023 and 2022 generally includes administrative expenses related to invoices paid between the periods of November 1, 2022 to October 31, 2023 and November 1, 2021 to October 31, 2022, respectively. Trust administrative expenses also includes a change in cash advance that estimates three months of subsequent Trust administration expense payments each quarter.
3. Income Taxes
The Trust is a Delaware statutory trust that is treated as a partnership for U.S. federal income tax purposes. The Trust is not required to pay federal or state income taxes. Accordingly, no provision for federal or state income tax has been made.
Trust unitholders are treated as partners of the Trust for U.S. federal income tax purposes. The Trust Agreement contains tax provisions that generally allocate the Trust’s income, deductions and credits among the Trust unitholders in accordance with their percentage interests in the Trust. The Trust Agreement also sets forth the tax accounting principles to be applied by the Trust.
4.Related Party Transactions
Trustee Administrative Fee. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $175,000 to the Trustee, paid in equal quarterly installments. The administrative fee may be adjusted for inflation by no more than 3% in any calendar year beginning in 2015. The Trustee's annual administrative fees were adjusted upward by 1.4% in 2021, 3.0% in 2022 and 3.0% in 2023 to the current amount of $204,574.
Agreements with the Administrative Servicer. In connection with the initial public offering and the conveyance of the Royalty Interests to the Trust, the Trust entered into an administrative services agreement, a development agreement and a Registration Rights Agreement with the Administrative Servicer.
Pursuant to the Administrative Services Agreement, the Administrative Servicer provides the Trust with certain accounting, tax preparation, bookkeeping and information services related to the Royalty Interests and the Registration Rights Agreement. In return for the services provided by the Administrative Servicer under the Administrative Services Agreement, the Trust pays the Administrative Servicer, in equal quarterly installments, an annual fee of $200,000, which will remain fixed for the life of the Trust. The Administrative Servicer is also entitled to receive reimbursement for its actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement. The Administrative Servicer was paid approximately $397,000, $340,000 and $212,000 in fees and reimbursements in 2023, 2022 and 2021, respectively. Variances in fees and reimbursements paid is primarily due to the timing of payments.
The Administrative Services Agreement will terminate upon the earliest to occur of (a) the date the Trust shall have dissolved and wound up its business and affairs in accordance with the Trust Agreement, (b) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (c) with respect to services to be provided to any Underlying Properties being transferred by the Operator, the date that either the Administrative Servicer or the Trustee may designate by delivering 90-days prior written notice, provided that the transferee of such Underlying Properties assumes responsibility to perform the services in place of the Administrative Servicer or (d) a date mutually agreed upon by the Administrative Servicer and the Trustee.
The Trust also entered into a Registration Rights Agreement for the benefit of the Operator and certain of its affiliates (each, a “holder”). Pursuant to the Registration Rights Agreement, the Trust agreed to register the Trust units held by each such holder for resale under the Securities Act of 1933, as amended, under certain circumstances. In connection with the preparation and filing of any registration statement, the Operator will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trust, and any underwriting discounts and commissions, which will be borne by the seller of the Trust units.
54
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
Loan Commitment. Pursuant to the Trust Agreement, if at any time the Trust’s cash on hand (including available cash reserves, if any) is insufficient to pay the Trust’s ordinary course expenses as they become due, the Operator will loan funds to the Trust necessary to pay such expenses. Any funds loaned by the Operator pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other current liabilities arising in the ordinary course of the Trust’s business, and may not be used to satisfy Trust indebtedness for borrowed money of the Trust. If the Operator loans funds pursuant to this commitment, unless the Operator agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. There were no loans outstanding as of December 31, 2023 or December 31, 2022.
5.Distributions to Unitholders
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting the Trust’s expenses, approximately 60 days following the completion of each quarter through (and including) the quarter ending June 30, 2031.
For the years ended December 31, 2023, 2022 and 2021 the Trust declared and paid the following cash distributions:
Production Period | Distribution Date | Cash Distribution per Common Unit | ||||||||||||
| June 2023 – August 2023 | November 30, 2023 | $ | 0.0336 | |||||||||||
| March 2023 - May 2023 | August 31, 2023 | $ | 0.0178 | |||||||||||
| December 2022 - February 2023 | June 1, 2023 | $ | 0.0487 | |||||||||||
| September 2022 - November 2022 | March 1, 2023 | $ | 0.0757 | |||||||||||
| June 2022 – August 2022 | December 1, 2022 | $ | 0.0722 | |||||||||||
| March 2022 - May 2022 | August 29, 2022 | $ | 0.0849 | |||||||||||
| December 2021 - February 2022 | May 31, 2022 | $ | 0.0540 | |||||||||||
| September 2021 - November 2021 | March 3, 2022 | $ | 0.0667 | |||||||||||
| June 2021 – August 2021 | November 29, 2021 | $ | 0.0496 | |||||||||||
| March 2021 - May 2021 | August 30, 2021 | $ | 0.0373 | |||||||||||
| December 2020 - February 2021 | June 1, 2021 | $ | 0.0467 | |||||||||||
| September 2020 - November 2020 | March 1, 2021 | $ | 0.0063 | |||||||||||
55
CHESAPEAKE GRANITE WASH TRUST
NOTES TO FINANCIAL STATEMENTS – (Continued)
6. Subsequent Events
Subsequent Distribution. The Trust's quarterly income available for distribution was $0.0214 per common unit for the production period from September 1, 2023 to November 30, 2023 (net of administrative expenses incurred between November 1, 2023 to January 31, 2024). On February 5, 2024, the Trust declared a cash distribution of $0.0214 per common unit attributable to such production period. The distribution was paid on February 29, 2024 to record unitholders as of February 19, 2024. All Trust unitholders share on a pro rata basis in the Trust's distributable income.
56
CHESAPEAKE GRANITE WASH TRUST
SUPPLEMENTARY INFORMATION
Quarterly Financial Data (unaudited)
The following is a summary of royalty income and distributable income by quarter for 2023 and 2022:
| Year Ended December 31, 2023 | ||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | 2023 | ||||||||||||||||||||||||||||
| ($ in thousands, except per unit data) | ||||||||||||||||||||||||||||||||
| Royalty income | $ | 3,969 | $ | 2,915 | $ | 1,878 | $ | 1,931 | $ | 10,693 | ||||||||||||||||||||||
| Distributable income | $ | 3,537 | $ | 2,274 | $ | 832 | $ | 1,405 | $ | 8,048 | ||||||||||||||||||||||
| Distributable income per common unit | $ | 0.0757 | $ | 0.0487 | $ | 0.0178 | $ | 0.0300 | $ | 0.1721 | ||||||||||||||||||||||
| Year Ended December 31, 2022 | ||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | 2022 | ||||||||||||||||||||||||||||
| ($ in thousands, except per unit data) | ||||||||||||||||||||||||||||||||
| Royalty income | $ | 3,693 | $ | 3,233 | $ | 4,429 | $ | 4,487 | $ | 15,842 | ||||||||||||||||||||||
| Distributable income | $ | 3,120 | $ | 2,524 | $ | 3,968 | $ | 3,376 | $ | 12,988 | ||||||||||||||||||||||
| Distributable income per common unit | $ | 0.0667 | $ | 0.0540 | $ | 0.0849 | $ | 0.0722 | $ | 0.2778 | ||||||||||||||||||||||
Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited)
Net Capitalized Costs. Capitalized costs related to the Trust's oil, natural gas and NGL producing activities are summarized as follows:
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| ($ in thousands) | ||||||||||||||
| Oil and natural gas properties: | ||||||||||||||
| Proved | $ | 487,793 | $ | 487,793 | ||||||||||
| Unproved | — | — | ||||||||||||
Total | 487,793 | 487,793 | ||||||||||||
| Less accumulated amortization | (480,277) | (479,535) | ||||||||||||
| Net capitalized costs | $ | 7,516 | $ | 8,258 | ||||||||||
The Royalty Interests originally conveyed to the Trust by Chesapeake consist of interests in proved properties only. The Trust capitalized approximately $487.8 million for the properties conveyed to the Trust concurrent with the initial public offering.
Costs Incurred in Oil and Natural Gas Drilling and Completion and Investment in Royalty Interest. Costs incurred in oil and natural gas drilling and completion, acquisition and divestiture activities which have been capitalized are limited to the $487.8 million of initial investment in proved properties at the inception of the Trust. The Trust will not acquire or dispose of properties and is not burdened with drilling and completion costs.
57
CHESAPEAKE GRANITE WASH TRUST
SUPPLEMENTARY INFORMATION – (Continued)
Results of Operations from Oil, Natural Gas and NGL Producing Activities. The Operator's results of operations from oil, natural gas and NGL producing activities for the Trust's interest are presented below for the years ended December 31, 2023, 2022 and 2021. The following table includes revenues and expenses associated directly with the Trust's oil and natural gas producing activities. Production expenses and production taxes are deducted by the Operator prior to remittance of royalty income to the Trust. The following calculation does not include any interest income or general and administrative costs and, therefore, is not necessarily indicative of distributable income:
| Years Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| ($ in thousands) | ||||||||||||||||||||
| Sales of oil, natural gas and NGL | $ | 10,693 | $ | 15,842 | $ | 8,697 | ||||||||||||||
| Production taxes | (699) | (1,111) | (590) | |||||||||||||||||
| Amortization of investment in royalty interests | (742) | (889) | (1,425) | |||||||||||||||||
| Impairment of investment in royalty interests | — | — | (837) | |||||||||||||||||
Results of operations from oil, natural gas and NGL producing activities | $ | 9,252 | $ | 13,842 | $ | 5,845 | ||||||||||||||
Estimated Oil, Natural Gas and NGL Reserve Quantities. The Trust's independent petroleum engineering firm, NSAI, estimated all of the proved reserves as of December 31, 2023 for the Royalty Interests. The qualifications of the technical person at NSAI primarily responsible for overseeing the firm's preparation of the Trust's reserve estimates are set forth below.
•over 30 years of practical experience in the estimation and evaluation of reserves;
•licensed professional engineer in the State of Texas; and
•Bachelor of Science in Mechanical Engineering, Bachelor of Science in Geology and Master of Science in Geology.
Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic productibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
58
CHESAPEAKE GRANITE WASH TRUST
SUPPLEMENTARY INFORMATION – (Continued)
Developed oil, natural gas and NGL reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods where production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
The information provided below on our oil, natural gas and NGL reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term.
Presented below is a summary of changes in estimated reserves of the Royalty Interests for 2023, 2022 and 2021.
| December 31, 2023 | ||||||||||||||||||||||||||
| Oil | Natural Gas | NGL | Total | |||||||||||||||||||||||
| (mbbl) | (mmcf) | (mbbl) | (mboe) | |||||||||||||||||||||||
| Proved reserves, beginning of period | 367 | 13,165 | 1,286 | 3,846 | ||||||||||||||||||||||
Revisions of previous estimates, price(1) | (4) | (164) | (14) | (45) | ||||||||||||||||||||||
Revisions of previous estimates, other(2) | 104 | 1,434 | (155) | 188 | ||||||||||||||||||||||
| Production | (48) | (1,400) | (116) | (396) | ||||||||||||||||||||||
| Proved reserves, end of period | 419 | 13,035 | 1,001 | 3,593 | ||||||||||||||||||||||
| Proved developed reserves: | ||||||||||||||||||||||||||
| Beginning of period | 367 | 13,165 | 1,286 | 3,846 | ||||||||||||||||||||||
| End of period | 419 | 13,035 | 1,001 | 3,593 | ||||||||||||||||||||||
| Proved undeveloped reserves: | ||||||||||||||||||||||||||
| Beginning of period | — | — | — | — | ||||||||||||||||||||||
| End of period | — | — | — | — | ||||||||||||||||||||||
| December 31, 2022 | |||||||||||||||||||||||||||||
| Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||||
| (mbbl) | (mmcf) | (mbbl) | (mboe) | ||||||||||||||||||||||||||
| Proved reserves, beginning of period | 385 | 12,756 | 1,356 | 3,867 | |||||||||||||||||||||||||
Revisions of previous estimates, price(3) | 16 | 441 | 42 | 131 | |||||||||||||||||||||||||
Revisions of previous estimates, other(4) | 19 | 1,286 | 4 | 236 | |||||||||||||||||||||||||
| Production | (53) | (1,318) | (116) | (388) | |||||||||||||||||||||||||
| Proved reserves, end of period | 367 | 13,165 | 1,286 | 3,846 | |||||||||||||||||||||||||
| Proved developed reserves: | |||||||||||||||||||||||||||||
| Beginning of period | 385 | 12,756 | 1,356 | 3,867 | |||||||||||||||||||||||||
| End of period | 367 | 13,165 | 1,286 | 3,846 | |||||||||||||||||||||||||
| Proved undeveloped reserves: | |||||||||||||||||||||||||||||
| Beginning of period | — | — | — | — | |||||||||||||||||||||||||
| End of period | — | — | — | — | |||||||||||||||||||||||||
59
CHESAPEAKE GRANITE WASH TRUST
SUPPLEMENTARY INFORMATION – (Continued)
| December 31, 2021 | ||||||||||||||||||||||||||
| Oil | Natural Gas | NGL | Total | |||||||||||||||||||||||
| (mbbl) | (mmcf) | (mbbl) | (mboe) | |||||||||||||||||||||||
| Proved reserves, beginning of period | 274 | 9,390 | 897 | 2,736 | ||||||||||||||||||||||
Revisions of previous estimates, price(5) | 125 | 4,543 | 434 | 1,316 | ||||||||||||||||||||||
Revisions of previous estimates, other(6) | 40 | 105 | 188 | 246 | ||||||||||||||||||||||
| Production | (54) | (1,282) | (163) | (431) | ||||||||||||||||||||||
| Proved reserves, end of period | 385 | 12,756 | 1,356 | 3,867 | ||||||||||||||||||||||
| Proved developed reserves: | ||||||||||||||||||||||||||
| Beginning of period | 274 | 9,390 | 897 | 2,736 | ||||||||||||||||||||||
| End of period | 385 | 12,756 | 1,356 | 3,867 | ||||||||||||||||||||||
| Proved undeveloped reserves: | ||||||||||||||||||||||||||
| Beginning of period | — | — | — | — | ||||||||||||||||||||||
| End of period | — | — | — | — | ||||||||||||||||||||||
___________________________________________________
(1)During 2023, the Trust recorded downward reserve revisions of 45 mboe to the December 31, 2022 estimates of reserves resulting from changes in oil and natural gas prices. Before basis differential adjustments, oil and natural gas prices used in estimating proved reserves decreased as of December 31, 2023 compared to December 31, 2022 using the trailing 12-month average prices required by the SEC. Oil prices decreased by $15.93 per bbl, or 17%, to $78.21 per bbl from $94.14 per bbl. Natural gas prices decreased $3.72 per mcf, or 58%, to $2.64 per mcf from $6.36 per mcf.
(2)During 2023, the Trust recorded upward reserve revisions of 188 mboe to the December 31, 2022 estimates of reserves resulting from changes to previous estimates. These non-price related revisions were primarily attributable to a positive production forecast revision.
(3)During 2022, the Trust recorded upward reserve revisions of 131 mboe to the December 31, 2021 estimates of reserves resulting from changes in oil and natural gas prices. Before basis differential adjustments, oil and natural gas prices used in estimating proved reserves increased as of December 31, 2022 compared to December 31, 2021 using the trailing 12-month average prices required by the SEC. Oil prices increased by $27.59 per bbl, or 41%, to $94.14 per bbl from $66.55 per bbl. Natural gas prices increased $2.76 per mcf, or 77%, to $6.36 per mcf from $3.60 per mcf.
(4)During 2022, the Trust recorded upward reserve revisions of 236 mboe to the December 31, 2021 estimates of reserves resulting from changes to previous estimates. These non-price related revisions were primarily attributable to a positive production forecast revision.
(5)During 2021, the Trust recorded upward reserve revisions of 1,316 mboe to the December 31, 2020 estimates of reserves resulting from changes in oil and natural gas prices. Before basis differential adjustments, oil and natural gas prices used in estimating proved reserves decreased as of December 31, 2021 compared to December 31, 2020 using the trailing 12-month average prices required by the SEC. Oil prices increased by $26.98 per bbl, or 68%, to $66.55 per bbl from $39.57 per bbl. Natural gas prices increased $1.62 per mcf, or 82%, to $3.60 per mcf from $1.98 per mcf.
(6)During 2021, the Trust recorded upward reserve revisions of 246 mboe to the December 31, 2020 estimates of reserves resulting from changes to previous estimates. These non-price related revisions were primarily attributable to a positive production forecast revision.
60
CHESAPEAKE GRANITE WASH TRUST
SUPPLEMENTARY INFORMATION – (Continued)
Standardized Measure of Discounted Future Net Cash Flows. Financial Accounting Standards Board ("FASB") Accounting Standards Topic 932, Extractive Activities - Oil & Gas, prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Operator has advised the Trustee that the Operator followed these guidelines, which are briefly discussed below.
Future cash inflows and future production costs as of December 31, 2023, 2022 and 2021 were determined by applying the trailing average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the trailing 12-month average prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by FASB and, as such, do not necessarily reflect the expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computation since these estimates reflect the valuation process.
The following summary sets forth the future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure:
| Years Ended December 31, | |||||||||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||||||||
| ($ in thousands) | |||||||||||||||||||||||
| Future cash inflows | $ | 74,471 | (1) | $ | 135,524 | (2) | $ | 81,328 | (3) | ||||||||||||||
Future production costs(4) | (3,351) | (9,615) | (5,684) | ||||||||||||||||||||
Future development costs(5) | — | — | — | ||||||||||||||||||||
Future income tax provisions(6) | — | — | — | ||||||||||||||||||||
| Future net cash flows | 71,120 | 125,909 | 75,644 | ||||||||||||||||||||
| Less effect of a 10% discount factor | (36,039) | (59,261) | (34,100) | ||||||||||||||||||||
Standardized measure of discounted future net cash flows | $ | 35,081 | $ | 66,648 | $ | 41,544 | |||||||||||||||||
(1)Calculated using prices of $2.64 per mcf of natural gas and $78.21 per bbl of oil, before field differentials. Including the effect of price differential adjustments, the prices used in computing the reserves attributable to the Royalty Interests as of December 31, 2023 were $1.68 per mcf of natural gas, $74.57 per barrel of oil and $21.35 per barrel of NGL.
(2)Calculated using prices of $6.36 per mcf of natural gas and $94.14 per bbl of oil, before field differentials. Including the effect of price differential adjustments, the prices used in computing the reserves attributable to the Royalty Interests as of December 31, 2022 were $4.45 per mcf of natural gas, $92.25 per barrel of oil and $33.58 per barrel of NGL.
(3)Calculated using prices of $3.60 per mcf of natural gas and $66.55 per bbl of oil, before field differentials. Including the effect of price differential adjustments, the prices used in computing the reserves attributable to the Royalty Interests as of December 31, 2021 were $1.77 per mcf of natural gas, $62.68 per barrel of oil and $25.56 per barrel of NGL.
(4)Future production costs include the Trust's proportionate share of production taxes and post-production costs. The Trust does not bear any operational costs related to the wells.
(5)Future net cash flow has been calculated without deduction for future development costs as the Trust does not bear those costs.
(6)No provision for federal or state income taxes has been provided for in the calculation because taxable income is passed through to the unitholders of the Trust.
61
CHESAPEAKE GRANITE WASH TRUST
SUPPLEMENTARY INFORMATION – (Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows. The following schedule reconciles the changes for the years ended December 31, 2023, 2022 and 2021 in the standardized measure of discounted future net cash flows relating to proved reserves:
| Years Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| ($ in thousands) | ||||||||||||||||||||
| Standardized measure, beginning of period | $ | 66,648 | $ | 41,544 | $ | 11,411 | ||||||||||||||
| Sales of oil and gas produced, net of production costs | (9,994) | (14,080) | (11,085) | |||||||||||||||||
| Net changes in prices and production costs | (25,458) | 31,879 | 24,362 | |||||||||||||||||
| Revision of previous quantity estimates | 121 | 3,523 | 15,777 | |||||||||||||||||
| Accretion of discount | 6,665 | 3,686 | 1,023 | |||||||||||||||||
| Production timing and other | (2,901) | 96 | 56 | |||||||||||||||||
| Standardized measure, end of period | $ | 35,081 | $ | 66,648 | $ | 41,544 | ||||||||||||||
62
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
As previously reported in the Trust’s Current Report on Form 8-K filed on December 15, 2022, on December 9, 2022, the Trust dismissed Grant Thornton LLP (“GT”) (PCAOB ID 248) as its independent registered public accounting firm. Following the dismissal of GT, the Trust engaged PricewaterhouseCoopers LLP (“PwC”) (PCAOB ID 238) as its new independent registered public accounting firm effective December 15, 2022. For more information, please refer to the Trust’s Current Report on Form 8-K filed on December 15, 2022.
ITEM 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures.
The Trust’s disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, are designed to ensure that the information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by the Operator to the Trustee, as the Trustee of the Trust, and the Trustee's employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.
Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (a) the Trust Agreement, (b) the Administrative Services Agreement, (c) the development agreement and (d) the conveyances granting the Royalty Interests, the Trust’s disclosure controls and procedures necessarily rely on (i) information provided by the Operator, including information relating to results of operations, the costs and revenues attributable to the Trust’s interests under the conveyance and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties and the Royalty Interests, and (ii) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. Although the Trustee does rely on the Operator to perform certain functions and to provide certain information that impact the Trust’s financial statements, the Trustee remains responsible for evaluating, as appropriate, the Trust’s disclosure controls and procedures as well as its internal control over financial reporting.
The Trustee has evaluated the effectiveness of the Trust's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this Annual Report. Based on this evaluation, as of December 31, 2023, the Trustee has concluded that the Trust's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.
Trustee’s Report on Internal Control over Financial Reporting.
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). The Trust’s internal control over financial reporting is a process designed under the supervision of the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Trust’s financial statements for external purposes in accordance with the modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
As of December 31, 2023, the Trustee assessed the effectiveness of the Trust's internal control over financial reporting based on the criteria described in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that assessment, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2023 based on those criteria.
63
Changes in Internal Control over Financial Reporting.
There were no changes in internal controls over financial reporting that occurred during the quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.
ITEM 9B. Other Information
(a) None.
(b) The Trust does not have any directors (as defined in Section 3(a)(7) of the Exchange Act) or officers (as defined in Rule 16a-1(f) promulgated under the Exchange Act) and, as a result, no such persons adopted, terminated or modified any Rule 10b5-1 trading arrangement or any non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).
ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
64
PART III
ITEM 10. Directors, Executive Officers and Corporate Governance
The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust units at a meeting at which a quorum is present.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Exchange Act does not apply to the Trust or its unitholders because the units are not registered with the SEC under Section 12 of the Exchange Act.
Audit Committee and Nominating Committee
Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Code of Ethics
The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with the Trustee's code of ethics.
ITEM 11. Executive Compensation
During the years ended December 31, 2023, 2022 and 2021, the Trustee received an administrative fee of $204,574, $198,616 and $192,831 from the Trust, respectively. The Trust does not have any executive officers, directors or employees. Additionally, no equity compensation plan is maintained by the Trust. Because the Trust does not have a board of directors, it does not have a compensation committee.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
(a) Equity Compensation Plans
Reference is made to "Item 5 - Equity Compensation Plans," which is incorporated herein by reference.
(b) Security Ownership of Certain Beneficial Owners
Based on filings with the SEC, the Trustee is not aware of any holders of 5% or more of the units except as set forth below. The following information has been obtained from Diversified.
| Beneficial Owner | Trust Units Beneficially Owned | Percent of Class | ||||||||||||
DP Bluegrass LLC(1) | 23,750,000 Common Units | 50.8% | ||||||||||||
________________________________________________
(1)DP Bluegrass LLC, which is the holder of the common units reported in the above table, is an indirect, wholly-owned subsidiary of Diversified. Diversified is located at 1600 Corporate Drive, Birmingham, AL 35242. Diversified may be deemed to beneficially own the common units held by DP Bluegrass.
(c) Security Ownership of Management
Not Applicable.
(d) Changes in Control
The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or its parent, the operation of which may at a subsequent date result in a change of control of the registrant.
65
ITEM 13. Certain Relationships and Related Transactions and Director Independence
Related Party Transactions
Under the terms of the Trust Agreement, the Trust pays an annual administrative fee to the Trustee of $175,000 (which may be adjusted beginning on January 1, 2015), paid in four quarterly installments and billed in arrears. As of December 31, 2023, a 3.0% inflation adjustment had been made for the 2023 calendar year. As the Trust uses the modified cash basis of accounting, general and administrative expenses in the Trust's statements of distributable income for the years ended December 31, 2023, 2022 and 2021 include $204,574, $198,616, and $192,831 for administrative fees paid to the Trustee, respectively.
Administrative Services Agreement
In return for the services provided by the Administrative Servicer under the Administrative Services Agreement, the Trust pays the Administrative Servicer, on a quarterly basis, a total annual fee of $200,000, which will remain fixed for the life of the Trust. the Administrative Servicer will also be entitled to receive reimbursement for its actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement.
The Administrative Services Agreement will terminate upon the earliest to occur of (a) the date the Trust shall have been wound up in accordance with the Trust Agreement, (b) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (c) with respect to services to be provided with respect to any Underlying Properties being transferred by the Operator, the date that either the Administrative Servicer or the Trustee may designate by delivering 90-days prior written notice, provided that the transferee of such Underlying Properties assumes responsibility to perform the services in place of the Administrative Servicer or (d) a date mutually agreed upon by the Operator and the Trustee.
Registration Rights Agreement
On November 16, 2011, the Trust entered into a Registration Rights Agreement for the benefit of the Operator and certain of its affiliates. Pursuant to the Registration Rights Agreement, the Trust agreed, for the benefit of each holder, to register the Trust units held by each such holder for resale under the Securities Act. Specifically, the Trust agrees:
•subject to certain lock-up restrictions, to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units;
•to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and
•to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the Trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable Trust units:
•have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;”
•have been sold in a private transaction in which the transferor's rights under the Registration Rights Agreement are not assigned to the transferee of the Trust units; or
•become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act).
The holders will have the right to require the Trust to file no more than five registration statements in aggregate.
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In connection with the preparation and filing of any registration statement, the Operator will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trust, and any underwriting discounts and commissions, which will be borne by the seller of the Trust units.
Director Independence
The Trust has no directors or executive officers; therefore, no determination has been made relative to director independence.
ITEM 14. Principal Accountant Fees and Services
PricewaterhouseCoopers LLP ("PwC") has served as the Trust's independent registered public accounting firm since December 15, 2022 and has audited the Trust's financial statements for the years ended December 31, 2023 and 2022. Estimated fees for services performed by PwC for the years ended December 31, 2023 and 2022, were as follows:
| Years Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
Audit Fees(1) | $ | 300,000 | $ | — | |||||||
| Tax Fees | 529,623 | 346,673 | |||||||||
| Total | $ | 829,623 | $ | 346,673 | |||||||
_____________________________________________________________________
(1)Fees for audit services in 2023 and 2022 include fees for the reviews of the Trust's quarterly financial statements.
As a modified cash basis entity, the Trust expenses these fees when paid.
As referenced in Item 10, Directors, Executive Officers and Corporate Governance, above, the Trust has no audit committee, and as a result, any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.
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PART IV
ITEM 15. Exhibits and Financial Statement Schedules
____________________________________________
(a) The following financial statements, financial statement schedules and exhibits are filed as a part of this report:
1.Financial Statements. Chesapeake Granite Wash Trust's financial statements are included in Item 8 of Part II of this report.
2.Financial Statement Schedules. Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
3.Exhibits. The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
INDEX OF EXHIBITS
| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | SEC File Number | Exhibit | Filing Date | Filed Herewith or Furnished | ||||||||||||||||||||||||||||||||
| 3.1 | S-1 | 333-175395 | 3.1 | 7/7/2011 | ||||||||||||||||||||||||||||||||||
| 3.2 | 8-K | 001-35343 | 3.1 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
| 4.1 | 10-K | 001-35343 | 4.1 | 3/19/2021 | ||||||||||||||||||||||||||||||||||
| 10.1 | 8-K | 001-35343 | 10.1 | 12/11/2020 | ||||||||||||||||||||||||||||||||||
| 10.2 | 8-K | 001-35343 | 10.1 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
| 10.3 | 8-K | 001-35343 | 10.2 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
| 10.4 | 8-K | 001-35343 | 10.3 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
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| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | SEC File Number | Exhibit | Filing Date | Filed Herewith or Furnished | ||||||||||||||||||||||||||||||||
| 10.5 | 8-K | 001-35343 | 10.4 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
| 10.6 | 8-K | 001-35343 | 10.5 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
| 10.7 | 8-K | 001-35343 | 10.6 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
| 10.8 | 8-K | 001-35343 | 10.7 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
| 10.9 | 8-K | 001-35343 | 10.9 | 11/21/2011 | ||||||||||||||||||||||||||||||||||
| 16.1 | 8-K | 001-35343 | 16.1 | 12/15/2022 | ||||||||||||||||||||||||||||||||||
| 31.1 | X | |||||||||||||||||||||||||||||||||||||
| 32.1 | X | |||||||||||||||||||||||||||||||||||||
| 99.1 | X | |||||||||||||||||||||||||||||||||||||
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ITEM 16. Form 10-K Summary
None.
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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.
Date: April 1, 2024
| CHESAPEAKE GRANITE WASH TRUST | ||||||||
| By: | THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., Trustee | |||||||
| By: | /s/ Sarah Newell | |||||||
| Sarah Newell | ||||||||
| Vice President | ||||||||
The registrant, Chesapeake Granite Wash Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust Agreement under which it serves.
Exhibit 31.1
Certification
I, Sarah Newell, certify that:
1.I have reviewed this annual report on Form 10-K of Chesapeake Granite Wash Trust, for which The Bank of New York Mellon Trust Company, N.A., acts as Trustee;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this report.
4.I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and I have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant is made known to me by others within that entity, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in conformity with the modified cash basis of accounting which is a comprehensive basis of accounting other than generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors:
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report information; and
(b) Any fraud, whether or not material, that involves any persons who have a significant role in the registrant's internal control over financial reporting.
In giving the foregoing certifications in paragraphs 4 and 5, I have relied to the extent I consider reasonable on information provided to me by Diversified Energy Company PLC.
| Date: | April 1, 2024 | /s/ Sarah Newell | |||||||||
Sarah Newell Vice President The Bank of New York Mellon Trust Company, N.A., Trustee of Chesapeake Granite Wash Trust | |||||||||||
Exhibit 32.1
April 1, 2024
Via EDGAR
Securities and Exchange Commission
100 F. Street, N.E.
Washington, D.C. 20549
| Re: | Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. § 1350) | ||||
Ladies and Gentlemen:
In connection with the Annual Report of Chesapeake Granite Wash Trust (the “Trust”) on Form 10-K for the year ended December 31, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Annual Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:
(1) The Annual Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operation of the Trust.
The above certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. § 1350) and is not being filed as part of the Annual Report or as a separate disclosure document. In giving the foregoing certifications, the undersigned has relied to the extent she considers reasonable on information provided to her by Diversified Energy Company PLC.
| The Bank of New York Mellon Trust Company, N.A. Trustee for Chesapeake Granite Wash Trust | |||||
| By: | /s/ Sarah Newell | ||||
Sarah Newell Vice President | |||||
Exhibit 99.1
March 4, 2024
Mr. Bradley G. Gray
Diversified Energy Company PLC
1800 Corporate Drive
Birmingham, Alabama 35242
Dear Mr. Gray:
In accordance with your request, we have estimated the proved developed producing reserves and future revenue, as of December 31, 2023, to the Chesapeake Granite Wash Trust (CGWT) royalty interest in certain oil and gas properties located in Colony Granite Wash Field, Oklahoma. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by CGWT. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for CGWT's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the CGWT royalty interest in these properties, as of December 31, 2023, to be:
| Net Reserves | Future Net Revenue (M$) | |||||||||||||||||||||||||||||||||||||
| Oil | NGL | Gas | Oil Equivalent | Present Worth | ||||||||||||||||||||||||||||||||||
| Category | (MBBL) | (MBBL) | (MMCF) | (MBOE) | Total | at 10% | ||||||||||||||||||||||||||||||||
| Proved Developed Producing | 418.6 | 1,001.4 | 13,035.4 | 3,592.6 | 71,119.9 | 35,080.6 | ||||||||||||||||||||||||||||||||
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Oil equivalent volumes shown in this report are expressed in thousands of barrels of oil equivalent (MBOE), determined using the ratio of 6 MCF of gas to 1 barrel of oil.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2023, there are no proved developed non-producing or proved undeveloped reserves for these properties. No study was made to determine whether probable or possible reserves might be established for these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage.
Gross revenue is CGWT's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for CGWT's share of production taxes but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2023. For oil and NGL volumes, the average West Texas Intermediate spot price of $78.21 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.637 per MMBTU is adjusted for energy content, transportation fees, and market differentials. The adjusted product prices of $74.57 per barrel of oil, $21.35 per barrel of NGL, and $1.678 per MCF of gas are held constant throughout the lives of the properties.
Because CGWT owns no working interest in these properties, no operating costs would be incurred. However, estimated operating costs have been used to confirm economic producibility and determine economic limits for the properties. These costs are based on operating expense records of Diversified Energy Company PLC (DEC), the operator of the majority of the properties. Operating costs are not escalated for inflation. CGWT would not incur any costs due to abandonment, nor would it realize any salvage value for the lease and well equipment.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. Since CGWT owns a royalty interest rather than a working interest in these properties, it would not incur any costs due to possible environmental liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the CGWT royalty interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on CGWT receiving its royalty interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred by the working interest owners in recovering such reserves may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from DEC, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Robert C. Barg, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1989 and has over 6 years of prior industry experience. William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By: /s/ Richard B. Talley, Jr.
Richard B. Talley, Jr., P.E.
Chief Executive Officer
By: /s/ Robert C. Barg By: /s/ William J. Knights
Robert C. Barg, P.E. 71658 William J. Knights, P.G. 1532
Senior Vice President Vice President
Date Signed: March 4, 2024 Date Signed: March 4, 2024
RCB:DCC
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iiii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities include:
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D) Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
(A) Costs of labor to operate the wells and related equipment and facilities.
(B) Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E) Severance taxes.
(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
•The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
•The company's historical record at completing development of comparable long-term projects;
•The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
•The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
•The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.