10-K/A
 10-K/A

 Document

 UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K A
 (Amendment No. 1)

 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)

 (512) 236-6555

 (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

 EXPLANATORY NOTE
 Chesapeake Granite Wash Trust (the Trust) filed its Annual Report on Form 10-K for the fiscal year ended December 31, 2023 (the 2023 Form 10-K) with the U.S. Securities and Exchange Commission ( SEC) on April 1, 2024. The Trust is filing this Amendment No. 1 to the 2023 Form 10-K (this Amendment) solely to correct a clerical error in the report titled Report of Independent Registered Public Accounting Firm provided by Grant Thornton LLP (the Audit Report) that was contained in the 2023 Form 10-K. Specifically, the Audit Report inadvertently contained an incorrect date.

 This Amendment contains the complete text of Item 8. Financial Statements and Supplementary Data, Item 15. Exhibits and Financial Statement Schedules, and certifications of the Trust's Trustee required under Items 302 and 906 of the Sarbanes-Oxley Act of 2002, as amended, dated as of the date of this Amendment, which are filed as Exhibits 31.1 and 32.1, respectively, to this Amendment.

 Except as specifically noted in this Amendment, this Amendment does not reflect events occurring after the filing of the 2023 Form 10-K or modify or update disclosures contained in the 2023 Form 10-K. Accordingly, this Form 10-K A should be read in conjunction with the 2023 Form 10-K and the Trust's other filings with the SEC.

 ITEM 8. Financial Statements and Supplementary Data

 Page

 Report of Independent Registered Public Accounting Firm (PCAOB ID 238)

 Statements of Assets and Trust Corpus

 Statements of Distributable Income

 Statements of Changes in Trust Corpus

 Notes to the Financial Statements

 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

 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.

 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
 March 21, 2022

 STATEMENTS OF ASSETS AND TRUST CORPUS

 December 31,

 2023

 2022

 ASSETS

 Cash and cash equivalents

 $
 2,688

 $
 2,564

 Investment in royalty interests

 Less accumulated amortization

 (480,277)

 (479,535)

 Net investment in royalty interests

 7,516

 8,258

 Total assets

 $
 10,204

 $

 TRUST CORPUS

 Trust corpus 46,750,000 common units issued and outstanding

 10,204

 Total Trust corpus

 $
 10,204

 $

 The accompanying notes are an integral part of these financial statements.

 STATEMENTS OF DISTRIBUTABLE INCOME

 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

 STATEMENTS OF CHANGES IN TRUST CORPUS

 2023

 2022

 2021

 TRUST CORPUS Beginning of period

 $

 $
 11,240

 $
 13,147

 Cash reserve surplus

 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

 $

 $
 11,240

 (1)See Note 5 - Distributions to Unitholders.

 The accompanying notes are an integral part of these financial statements.

 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

 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

 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

 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.

 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

 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.

 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

 $

 $
 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

 Oil and natural gas properties

 Proved

 $

 $

 Unproved

 —

 —

 Total

 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.

 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

 2023

 2022

 2021

 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.

 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

 (mmcf)

 (mboe)

 Proved reserves, beginning of period

 13,165

 1,286

 3,846

 Revisions of previous estimates, price(1)

 (4)

 (164)

 (14)

 (45)

 Revisions of previous estimates, other(2)

 1,434

 (155)

 Production

 (48)

 (1,400)

 (116)

 (396)

 Proved reserves, end of period

 13,035

 1,001

 3,593

 Proved developed reserves

 13,165

 1,286

 3,846

 13,035

 1,001

 3,593

 Proved undeveloped reserves

 —

 —

 —

 —

 —

 —

 —

 —

 December 31, 2022

 Oil

 Natural Gas

 NGL

 Total

 (mmcf)

 (mboe)

 Proved reserves, beginning of period

 12,756

 1,356

 3,867

 Revisions of previous estimates, price(3)

 Revisions of previous estimates, other(4)

 1,286

 Production

 (53)

 (1,318)

 (116)

 (388)

 Proved reserves, end of period

 13,165

 1,286

 3,846

 Proved developed reserves

 12,756

 1,356

 3,867

 13,165

 1,286

 3,846

 Proved undeveloped reserves

 —

 —

 —

 —

 —

 —

 —

 —

 December 31, 2021

 Oil

 Natural Gas

 NGL

 Total

 (mmcf)

 (mboe)

 Proved reserves, beginning of period

 9,390

 2,736

 Revisions of previous estimates, price(5)

 4,543

 1,316

 Revisions of previous estimates, other(6)

 Production

 (54)

 (1,282)

 (163)

 (431)

 Proved reserves, end of period

 12,756

 1,356

 3,867

 Proved developed reserves

 9,390

 2,736

 12,756

 1,356

 3,867

 Proved undeveloped reserves

 —

 —

 —

 —

 —

 —

 —

 —

 ___________________________________________________
 (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.

 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

 2023

 2022

 2021

 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.

 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

 2023

 2022

 2021

 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

 3,523

 15,777

 Accretion of discount

 6,665

 3,686

 1,023

 Production timing and other

 (2,901)

 Standardized measure, end of period

 $
 35,081

 $
 66,648

 $
 41,544

 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

 Certificate of Trust of Chesapeake Granite Wash Trust.

 S-1

 333-175395

 3.1

 7 7 2011

 3.2

 Amended and Restated Trust Agreement, dated as of November 16, 2011, by and among Chesapeake Energy Corporation, Chesapeake Exploration, L.L.C., The Bank of New York Mellon Trust Company, N.A., as Trustee, and The Corporation Trust Company, as Delaware Trustee.

 3.1

 4.1

 Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934.

 4.1

 3 19 2021

 10.1

 Assignment and Assumption Agreement, dated as of December 11, 2020, by and among Chesapeake Energy Corporation. Chesapeake Exploration, L.L.C., Chesapeake E P Holding, L.L.C., and Tapstone Energy, LLC.

 10.1

 12 11 2020

 10.2

 Perpetual Overriding Royalty Interest Conveyance (PDP), dated as of November 16, 2011, by and between Chesapeake Exploration, L.L.C. and Chesapeake Granite Wash Trust.

 10.1

 10.3

 Perpetual Overriding Royalty Interest Conveyance (PUD), dated as of November 16, 2011, by and between Chesapeake Exploration, L.L.C. and Chesapeake Granite Wash Trust.

 10.2

 10.4

 Term Overriding Royalty Interest Conveyance (PDP), dated as of November 16, 2011, by and between Chesapeake Exploration, L.L.C. and Chesapeake E P Holding Corporation.

 10.3

 Incorporated by Reference

 Exhibit Number

 Exhibit Description

 Form

 SEC File Number

 Exhibit

 Filing Date

 Filed Herewith or Furnished

 10.5

 Term Overriding Royalty Interest Conveyance (PUD), dated as of November 16, 2011, by and between Chesapeake Exploration, L.L.C. and Chesapeake E P Holding Corporation.

 10.4

 10.6

 Assignment of Term Overriding Royalty Interests, dated as of November 16, 2011, by and between Chesapeake E P Holding Corporation and Chesapeake Granite Wash Trust.

 10.5

 10.7

 Administrative Services Agreement, dated as of November 16, 2011, by and between Chesapeake Energy Corporation and Chesapeake Granite Wash Trust.

 10.6

 10.8

 Development Agreement, dated as of November 16, 2011, by and among Chesapeake Energy Corporation, Chesapeake Exploration, L.L.C. and Chesapeake Granite Wash Trust.

 10.7

 10.9

 Registration Rights Agreement, dated as of November 16, 2011, by and among Chesapeake Energy Corporation, Chesapeake Exploration, L.L.C. and Chesapeake Granite Wash Trust.

 10.9

 16.1

 Letter of Grant Thornton LLP dated December 15, 2022 to the SEC

 16.1

 12 15 2022

 31.1

 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Trustee's Vice President.

 X

 32.1

 Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Trustee's Vice President

 X

 99.1

 Report of Netherland, Sewell Associates, Inc.

 99.1

 4 1 2024

 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 3, 2024

 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.