CHESAPEAKE GRANITE WASH TRUST 10-K/A

ITEM 8. Financial Statements and Supplementary Data 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 of Chesapeake Granite Wash Trust (the “Trust”) as of December 31, 2019 and 2018, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and its distributable income and its changes in trust corpus for each of the three years in the period ended December 31, 2019 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. 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 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. /s/ PricewaterhouseCoopers LLP Oklahoma City, Oklahoma March 19, 2020 We have served as the Trust’s auditor since 2011. 41 CHESAPEAKE GRANITE WASH TRUST STATEMENTS OF ASSETS AND TRUST CORPUS December 31, 2019 2018 ($ in thousands) ASSETS: Cash and cash equivalents $ 1,600 $ 1,337 Investment in royalty interests 487,793 487,793 Less: accumulated amortization (467,588 ) (464,752 ) Net investment in royalty interests 20,205 23,041 Total assets $ 21,805 $ 24,378 TRUST CORPUS: Trust corpus; 46,750,000 common units issued and outstanding 21,805 24,378 Total Trust corpus $ 21,805 $ 24,378 The accompanying notes are an integral part of these financial statements. 42 CHESAPEAKE GRANITE WASH TRUST STATEMENTS OF DISTRIBUTABLE INCOME Years Ended December 31, 2019 2018 2017 ($ in thousands, except per unit data) REVENUES: Royalty income $ 9,806 $ 13,504 $ 15,665 Total revenues 9,806 13,504 15,665 EXPENSES: Production taxes (525 ) (878 ) (669 ) Trust administrative expenses (1,335 ) (1,330 ) (1,685 ) Total expenses (1,860 ) (2,208 ) (2,354 ) Cash reserves withheld (317 ) — — Distributable income available to unitholders $ 7,629 $ 11,296 $ 13,311 Distributable income per common unit (46,750,000 units) $ 0.1632 $ 0.2416 $ 0.3577 CHESAPEAKE GRANITE WASH TRUST STATEMENTS OF CHANGES IN TRUST CORPUS Years Ended December 31, 2019 2018 2017 ($ in thousands) TRUST CORPUS: Beginning of period $ 24,378 $ 27,604 $ 31,938 Cash reserve surplus 263 38 (683 ) Amortization of investment in royalty interests (2,836 ) (3,264 ) (4,419 ) Distributable income available to unitholders 7,629 11,296 13,311 Distributions paid to unitholders (1) (7,629 ) (11,296 ) (12,543 ) TRUST CORPUS: End of period $ 21,805 $ 24,378 $ 27,604 (1) See Note 5 - Distributions to Unitholders. The accompanying notes are an integral part of these financial statements. 43 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 (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 Chesapeake, 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 69 existing horizontal wells (the “Producing Wells”) and (b) Chesapeake’s interests in 118 horizontal development wells (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. Chesapeake has retained an interest in each of the Producing Wells and Development Wells and currently operates 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 NGL production attributable to Chesapeake’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 Chesapeake’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. The subordinated units were converted into common units on a one-for-one basis as of June 30, 2017. All distributions made on common units after September 30, 2017 no longer have the benefit of the subordination threshold, and all Trust unitholders share on a pro rata basis in the Trust's distributions. Prior to their conversion on June 30, 2017, the subordinated units were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash to provide a cash distribution on the common units that was no less than 80% of the target distribution set forth in the Trust Agreement for the corresponding quarter (the “subordination threshold”). If there was insufficient cash to fund such a distribution on all of the Trust units, the distribution made with respect to the subordinated units was either reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. Prior to the conversion of the subordinated units on June 30, 2017, Chesapeake was entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Trust units in any quarter was 20% greater than the target distribution for such quarter (the “incentive threshold”). The remaining 50% of cash available for distribution in excess of the applicable incentive threshold, if any, was to be paid to Trust unitholders, including Chesapeake, on a pro rata basis. On June 30, 2017, the last day of the fourth full calendar quarter subsequent to Chesapeake's satisfaction of its drilling obligation under the development agreement, the subordinated units automatically converted into common 44 CHESAPEAKE GRANITE WASH TRUST NOTES TO FINANCIAL STATEMENTS – (Continued) units on a one-for-one basis and Chesapeake's right to receive incentive distributions with respect to quarters after the 2017 second quarter terminated. The distribution for the quarter ended June 30, 2017 which was paid on August 31, 2017, was still subject to the subordination threshold. As a result, distributable income available to unitholders for the three and nine months ended September 30, 2017 was still subject to the subordination threshold. As such, distributable income per common unit as of September 30, 2017 was based upon 35,062,500 common units (see Note 5). Beginning with the November 30, 2017 distribution, the distributable income available to unitholders is based on the 46,750,000 common units that are currently outstanding. The Trust will dissolve and begin to liquidate on June 30, 2031, or earlier upon certain events (the “Termination Date”), and will soon thereafter wind up its affairs and terminate. At the Termination Date, (a) 50% of the total Royalty Interests conveyed by Chesapeake will revert automatically to Chesapeake and (b) 50% of the total Royalty Interests conveyed by Chesapeake (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. Chesapeake will have a right of first refusal to purchase the Perpetual Royalties retained by the Trust at the Termination Date. 2. Basis of Presentation and Significant 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 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 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. Significant estimates that impact the Trust’s financial statements include estimates of proved oil, natural gas and NGL reserves, which 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. The Trust does not have the ability to enter into derivative contracts to mitigate the effect of this price volatility. The Trust's revenues and distributable income available to unitholders have been adversely affected throughout 2018 and 2019 due to natural declines in production. The Trust expects production to decline further and expects distributable income to continue to be adversely affected. On February 5, 2020 , the Trust declared a cash distribution of $0.0371 per common unit, consisting of proceeds attributable to production from September 1, 2019 to November 30, 2019 . The distribution was paid on March 2, 2020 to record unitholders as of February 19, 2020 . See Note 5 for information regarding prior distributions paid and Note 6 for information regarding the distribution paid on March 2, 2020 . Chesapeake’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 Chesapeake’s control. In the event of a bankruptcy of Chesapeake or the wholly owned subsidiaries of Chesapeake that conveyed the Royalty Interests to the Trust, the Trust could lose the value of all of the Royalty Interests if a bankruptcy court were to hold that the Royalty Interests constitute an asset of the bankruptcy estate. Chesapeake could also 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, 2019 , 2018 and 2017 there were no impairments to the carrying value of the Investment in Royalty Interests. 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, Chesapeake 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 45 CHESAPEAKE GRANITE WASH TRUST NOTES TO FINANCIAL STATEMENTS – (Continued) cash distribution amount and unless Chesapeake agrees otherwise) until the loan is repaid. There were no loans outstanding as of December 31, 2019 or December 31, 2018 . Revenues and Expenses. Neither the Trust nor the Trustee is responsible for, or has any control over, any costs related to the drilling of the Development Wells or any other 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 Chesapeake'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 affiliates of Chesapeake. Cash distributions to unitholders will be reduced by the Trust’s general and administrative expenses. 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. 46 CHESAPEAKE GRANITE WASH TRUST NOTES TO FINANCIAL STATEMENTS – (Continued) 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 2.1% in 2017, 2.1% in 2018, and 1.9% in 2019 to the current amount of $185,893. Agreements with Chesapeake. In connection with the initial public offering and the conveyance of the Royalty Interests to the Trust, the Trust entered into an administrative service agreement, a development agreement and a registration rights agreement with Chesapeake. Pursuant to the administrative services agreement, Chesapeake 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 Chesapeake under the administrative services agreement, the Trust pays Chesapeake, in equal quarterly installments, an annual fee of $200,000, which will remain fixed for the life of the Trust. Chesapeake 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. Chesapeake was paid approximately $164,000, $270,000 and $218,000 in fees and reimbursements in 2019, 2018 and 2017, respectively. The $106,000 decrease from 2018 to 2019 was 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 with respect to any Underlying Properties being transferred by Chesapeake, the date that either Chesapeake or the Trustee may designate by delivering 90-days prior written notice, provided that Chesapeake’s drilling obligation has been completed and the transferee of such Underlying Properties assumes responsibility to perform the services in place of Chesapeake or (d) a date mutually agreed upon by Chesapeake and the Trustee. The Trust also entered into a registration rights agreement for the benefit of Chesapeake 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. In connection with the preparation and filing of any registration statement, Chesapeake 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) is insufficient to pay the Trust’s ordinary course expenses as they become due, Chesapeake will loan funds to the Trust necessary to pay such expenses. Any funds loaned by Chesapeake 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 Chesapeake loans funds pursuant to this commitment, unless Chesapeake 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. In March 2019, the Trust's cash on hand (including cash reserves) was insufficient to pay the Trust's ordinary course expenses as they became due. Chesapeake loaned $275,000 to the Trust necessary to pay such expenses and agreed to permit the Trust to continue making distributions while the loan was outstanding. The Trust repaid the loan in the second quarter of 2019. There were no loans outstanding as of December 31, 2019 or December 31, 2018 . 47 CHESAPEAKE GRANITE WASH TRUST NOTES TO FINANCIAL STATEMENTS – (Continued) 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, 2019 , 2018 and 2017 the Trust declared and paid the following cash distributions: Production Period Distribution Date Cash Distribution per Common Unit June 2019 – August 2019 November 29, 2019 $ 0.0374 March 2019 - May 2019 August 29, 2019 $ 0.0323 December 2018 - February 2019 May 30, 2019 $ 0.0303 September 2018 - November 2018 March 1, 2019 $ 0.0631 June 2018 – August 2018 November 29, 2018 $ 0.0534 March 2018 – May 2018 August 30, 2018 $ 0.0626 December 2017 – February 2018 May 31, 2018 $ 0.0469 September 2017 – November 2017 March 2, 2018 $ 0.0787 June 2017 – August 2017 (1) November 30, 2017 $ 0.0657 March 2017 – May 2017 August 31, 2017 $ 0.1003 December 2016 – February 2017 June 1, 2017 $ 0.1005 September 2016 – November 2016 March 2, 2017 $ 0.0912 (1) The Trust inadvertently failed to pay Chesapeake its quarterly distribution on November 30, 2017 with respect to Chesapeake's common units that converted from subordinated units on June 30, 2017. The unpaid distribution was paid in full in February 2018. Distributions paid to Trust unitholders and distributions paid to Chesapeake with respect to its common units for such period were calculated pursuant to the Trust Agreement. 48 CHESAPEAKE GRANITE WASH TRUST NOTES TO FINANCIAL STATEMENTS – (Continued) 6. Subsequent Events Subsequent Distribution. The Trust's quarterly income available for distribution was $0.0371 per common unit for the production period from September 1, 2019 to November 30, 2019 . On February 5, 2020 , the Trust declared a cash distribution of $0.0371 per common unit attributable to such production period. The distribution was paid on March 2, 2020 to record unitholders as of February 19, 2020 . All Trust unit holders share on a pro rata basis in the Trust's distributable income. Distributable income attributable to production from September 1, 2019 to November 30, 2019 , was calculated as follows (in thousands except for unit and per unit amounts): Revenues: Royalty income (1) $ 2,016 Expenses: Production taxes 164 Trust administrative expenses (2) (377 ) Total expenses (213 ) Cash withheld to increase cash reserves (3) (70 ) Distributable income available to unitholders $ 1,733 Distributable income per common unit (46,750,000 units) $ 0.0371 ___________________________________________________ (1) Net of certain post-production expenses. (2) Includes the cash advance for administrative expenses. (3) Commencing with the distribution to unitholders payable in the first quarter of 2019, the Trustee began withholding the greater of $70,000 or 3.5% of the funds otherwise available for distribution each quarter to gradually increase existing cash reserves by a total of approximately $850,000. 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. Cash held in reserve for payment of the quarterly cash distribution or sales proceeds amounts or for the payment of any liabilities other than routine administrative costs 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. NYSE Delisting. On August 28, 2019, the Trust received written notification from the NYSE that the Trust was not in compliance with the continued listing standards set forth in Rule 802.01C of the NYSE Listed Company Manual because the average closing price of the Trust’s common units was less than $1.00 over a consecutive 30 trading-day period. Because the Trust was unable to regain compliance with the applicable standards within a six-month cure period concluded February 28, 2020, the NYSE announced the suspension of trading of the Trust's common units due to non-compliance with Rule 802.01C of the NYSE Listed Company Manual, effective as of the close of trading on February 28, 2020. As a result of the suspension and delisting, the Trust's common units began trading on March 2, 2020 under the symbol "CHKR" on the OTC Pink. 49 CHESAPEAKE GRANITE WASH TRUST SUPPLEMENTARY INFORMATION Quarterly Financial Data (unaudited) The following is a summary of royalty income and distributable income by quarter for 2019 and 2018: Year Ended December 31, 2019 Q1 Q2 Q3 Q4 2019 ($ in thousands, except per unit data) Royalty income $ 3,363 $ 2,510 $ 2,157 $ 1,776 $ 9,806 Distributable income $ 2,952 $ 1,417 $ 1,511 $ 1,749 $ 7,629 Distributable income per common unit $ 0.0631 $ 0.0303 $ 0.0323 $ 0.0374 $ 0.1632 Year Ended December 31, 2018 Q1 Q2 Q3 Q4 2018 ($ in thousands, except per unit data) Royalty income $ 3,925 $ 3,362 $ 3,171 $ 3,046 $ 13,504 Distributable income $ 3,680 $ 2,193 $ 2,925 $ 2,498 $ 11,296 Distributable income per common unit $ 0.0787 $ 0.0469 $ 0.0626 $ 0.0534 $ 0.2416 Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited) Net Capitalized Costs. C apitalized costs related to the Trust's oil, natural gas and NGL producing activities are summarized as follows: December 31, 2019 2018 ($ in thousands) Oil and natural gas properties: Proved $ 487,793 $ 487,793 Unproved — — Total 487,793 487,793 Less accumulated amortization (467,588 ) (464,752 ) Net capitalized costs $ 20,205 $ 23,041 The Royalty Interests 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 $487.8 million of initial investment in proved properties at the inception of the Trust. The Trust will not acquire or dispose of properties and is not burdened with drilling and completion costs. 50 CHESAPEAKE GRANITE WASH TRUST SUPPLEMENTARY INFORMATION – (Continued) Results of Operations from Oil, Natural Gas and NGL Producing Activities. Chesapeake's results of operations from oil, natural gas and NGL producing activities for the Trust's interest are presented below for the years ended December 31, 2019 , 2018 and 2017. The following table includes revenues and expenses associated directly with the Trust's oil and natural gas producing activities. Production expenses and production taxes are deducted by Chesapeake prior to remittance of royalty income to the Trust. The following calculation does not include any interest income or general and administrative costs and, therefore, is not necessarily indicative of distributable income: Years Ended December 31, 2019 2018 2017 ($ in thousands) Sales of oil, natural gas and NGL $ 9,806 $ 13,504 $ 15,665 Production taxes (525 ) (878 ) (669 ) Amortization of investment in royalty interests (2,836 ) (3,264 ) (4,419 ) Results of operations from oil, natural gas and NGL producing activities $ 6,445 $ 9,362 $ 10,577 The following oil, natural gas and NGL information was prepared on an accrual basis, which is the basis upon which Chesapeake maintains its records and is different from the modified cash basis on which the Trust financial statements are prepared. A reconciliation of information presented on the modified cash basis to the accrual basis for the year ended December 31, 2019 is as follows: For the Period Ended Year Ended December 31, 2019 Modified Cash Basis (1) September 1, 2018 to December 31, 2018 September 1, 2019 to December 31, 2019 Accrual Basis (2) Production Data: Oil (mbbl) 91 (30 ) 26 87 Natural Gas (mmcf) 2,238 (835 ) 632 2,035 NGL (mbbl) 186 (50 ) 43 179 Total (mboe) 650 (219 ) 174 605 Royalty income (in thousands) $ 9,806 $ (3,779 ) $ 2,153 $ 8,180 Production taxes (in thousands) (525 ) 407 (93 ) (211 ) $ 9,281 $ (3,372 ) $ 2,060 $ 7,969 ___________________________________________________ (1) Oil, natural gas and NGL volumes attributable to the Royalty Interests and related revenues and expenses included in Chesapeake's 2019 net revenue distributions to the Trust. Represents oil, natural gas and NGL production from September 1, 2018 to August 31, 2019. (2) Oil, natural gas and NGL volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis, from January 1, 2019 through December 31, 2019 , a portion of which will be reflected on the modified cash basis in distributable income in subsequent quarters. 51 CHESAPEAKE GRANITE WASH TRUST SUPPLEMENTARY INFORMATION – (Continued) A reconciliation of information presented on the modified cash basis to the accrual basis for the year ended December 31, 2018 is as follows: For the Period Ended Year Ended December 31, 2018 Modified Cash Basis (1) September 1, 2017 to December 31, 2017 September 1, 2018 to December 31, 2018 Accrual Basis (2) Production Data: Oil (mbbl) 97 (31 ) 30 96 Natural Gas (mmcf) 2,492 (903 ) 835 2,424 NGL (mbbl) 265 (92 ) 50 223 Total (mboe) 777 (274 ) 219 722 Royalty income (in thousands) $ 13,504 $ (4,644 ) $ 3,779 $ 12,639 Production taxes (in thousands) (878 ) 437 (407 ) (848 ) $ 12,626 $ (4,207 ) $ 3,372 $ 11,791 ___________________________________________________ (1) Oil, natural gas and NGL volumes attributable to the Royalty Interests and related revenues and expenses included in Chesapeake's 2018 net revenue distributions to the Trust. Represents oil, natural gas and NGL production from September 1, 2017 to August 31, 2018. (2) Oil, natural gas and NGL volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis, from January 1, 2018 through December 31, 2018 , a portion of which will be reflected on the modified cash basis in distributable income in subsequent quarters. A reconciliation of information presented on the modified cash basis to the accrual basis for the year ended December 31, 2017 is as follows: For the Period Ended Year Ended December 31, 2017 Modified Cash Basis (1) September 1, 2016 to December 31, 2016 September 1, 2017 to December 31, 2017 Accrual Basis (2) Production Data: Oil (mbbl) 134 (47 ) 31 118 Natural Gas (mmcf) 3,296 (1,189 ) 903 3,010 NGL (mbbl) 332 (108 ) 92 316 Total (mboe) 1,015 (353 ) 274 936 Royalty income (in thousands) $ 15,665 $ (18,146 ) $ 17,304 $ 14,823 Production taxes (in thousands) (669 ) 228 (437 ) (878 ) $ 14,996 $ (17,918 ) $ 16,867 $ 13,945 ___________________________________________________ (1) Oil, natural gas and NGL volumes attributable to the Royalty Interests and related revenues and expenses included in Chesapeake's 2017 net revenue distributions to the Trust. Represents oil, natural gas and NGL production from September 1, 2016 to August 31, 2017. (2) Oil, natural gas and NGL volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis, from January 1, 2017 through December 31, 2017, a portion of which will be reflected on the modified cash basis in distributable income in subsequent quarters. 52 CHESAPEAKE GRANITE WASH TRUST SUPPLEMENTARY INFORMATION – (Continued) Estimated Oil, Natural Gas and NGL Reserve Quantities. The Trust's independent petroleum engineering firm, Software Integrated Solutions, Division of Schlumberger Technology Corporation, estimated all of the proved reserves as of December 31, 2019 for the Royalty Interests. The qualifications of the technical person at Software Integrated Solutions 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; • registered professional geologist licensed in the Commonwealth of Pennsylvania; • member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and • Bachelor of Science degree in Geological Sciences. 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 producibility from a reservoir is to be determined. 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 such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 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. 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 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: (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. 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 or in which the cost of the required equipment is relatively minor compared to the cost of a new well. The information below on the oil, natural gas and NGL reserves attributed to the Royalty Interests is presented in accordance with regulations prescribed by the SEC in effect as of the date of such estimates. 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. Such changes could be material and could occur in the near term. 53 CHESAPEAKE GRANITE WASH TRUST SUPPLEMENTARY INFORMATION – (Continued) Presented below is a summary of changes in estimated reserves of the Royalty Interests for 2019, 2018 and 2017. December 31, 2019 Oil Natural Gas NGL Total (mbbl) (mmcf) (mbbl) (mboe) Proved reserves, beginning of period 511 17,261 1,687 5,075 Revisions of previous estimates, price (1) (68 ) (2,698 ) (244 ) (761 ) Revisions of previous estimates, other (2) 82 2,103 34 466 Production (87 ) (2,035 ) (179 ) (605 ) Proved reserves, end of period 438 14,631 1,298 4,175 Proved developed reserves: Beginning of period 511 17,261 1,687 5,075 End of period 438 14,631 1,298 4,175 Proved undeveloped reserves: Beginning of period — — — — End of period — — — — December 31, 2018 Oil Natural Gas NGL Total (mbbl) (mmcf) (mbbl) (mboe) Proved reserves, beginning of period 604 19,657 2,058 5,938 Revisions of previous estimates, price (3) 27 649 54 190 Revisions of previous estimates, other (4) (24 ) (621 ) (202 ) (331 ) Production (96 ) (2,424 ) (223 ) (722 ) Proved reserves, end of period 511 17,261 1,687 5,075 Proved developed reserves: Beginning of period 604 19,657 2,058 5,938 End of period 511 17,261 1,687 5,075 Proved undeveloped reserves: Beginning of period — — — — End of period — — — — 54 CHESAPEAKE GRANITE WASH TRUST SUPPLEMENTARY INFORMATION – (Continued) December 31, 2017 Oil Natural Gas NGL Total (mbbl) (mmcf) (mbbl) (mboe) Proved reserves, beginning of period 686 23,296 2,033 6,601 Revisions of previous estimates, price (5) 58 1,860 166 533 Revisions of previous estimates, other (6) (22 ) (2,489 ) 175 (260 ) Production (118 ) (3,010 ) (316 ) (936 ) Proved reserves, end of period 604 19,657 2,058 5,938 Proved developed reserves: Beginning of period 686 23,296 2,033 6,601 End of period 604 19,657 2,058 5,938 Proved undeveloped reserves: Beginning of period — — — — End of period — — — — ___________________________________________________ (1) During 2019, the Trust recorded downward reserve revisions of 761 mboe to the December 31, 2018 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, 2019 compared to December 31, 2018 using the trailing 12-month average prices required by the SEC. Oil prices decreased by $9.87 per bbl, or 15%, to $55.69 per bbl from $65.56 per bbl. Natural gas prices decreased $0.52 per mcf, or 17%, to $2.58 per mcf from $3.10 per mcf. (2) During 2019, the Trust recorded upward reserve revisions of 466 mboe to the December 31, 2018 estimates of reserves resulting from changes to previous estimates. These non-price related revisions were primarily attributable to a positive production forecast revision and a reduction to future operating expenses. (3) During 2018, the Trust recorded upward reserve revisions of 190 mboe to the December 31, 2017 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, 2018 compared to December 31, 2017 using the trailing 12-month average prices required by the SEC. Oil prices increased by $14.22 per bbl, or 28%, to $65.56 per bbl from $51.34 per bbl. Natural gas prices increased $0.12 per mcf, or 4%, to $3.10 per mcf from $2.98 per mcf. (4) During 2018, the Trust recorded downward reserve revisions of 331 mboe to the December 31, 2017 estimates of reserves resulting from changes to previous estimates. These non-price related revisions were primarily attributable to lower production in forecasts. (5) During 2017, the Trust recorded upward reserve revisions of 533 mboe to the December 31, 2016 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, 2017 compared to December 31, 2016 using the trailing 12-month average prices required by the SEC. Oil prices increased by $8.59 per bbl, or 20%, to $51.34 per bbl from $42.75 per bbl. Natural gas prices increased $0.49 per mcf, or 20%, to $2.98 per mcf from $2.49 per mcf. (6) During 2017, the Trust recorded downward reserve revisions of 260 mboe to the December 31, 2016 estimates of reserves resulting from changes to previous estimates. These non-price related revisions were primarily attributable to lower production in forecasts. 55 CHESAPEAKE GRANITE WASH TRUST SUPPLEMENTARY INFORMATION – (Continued) Presented below is a summary of the adjustment to the estimated reserves attributable to the Royalty Interests to adjust the reserves to the balance attributable to the Trust under the modified cash basis of accounting as of December 31, 2019 and 2018. As of December 31, 2019 , 2018 and 2017 the Trust had not received royalty income associated with the production sold from each of the production periods from September 1 – December 31, 2019 , September 1 – December 31, 2018 and September 1 – December 31, 2017, respectively. December 31, 2019 Oil Natural Gas NGL Total (mbbl) (mmcf) (mbbl) (mboe) Proved reserves, accrual basis 438 14,631 1,298 4,175 Production September 1 – December 31, 2019 26 632 43 174 Adjusted Proved reserves, on a modified cash basis 464 15,263 1,341 4,349 December 31, 2018 Oil Natural Gas NGL Total (mbbl) (mmcf) (mbbl) (mboe) Proved reserves, accrual basis 511 17,261 1,687 5,075 Production September 1 – December 31, 2018 30 835 50 219 Adjusted Proved reserves, on a modified cash basis 541 18,096 1,737 5,294 December 31, 2017 Oil Natural Gas NGL Total (mbbl) (mmcf) (mbbl) (mboe) Proved reserves, accrual basis 604 19,657 2,058 5,938 Production September 1 – December 31, 2017 31 903 92 274 Adjusted Proved reserves, on a modified cash basis 635 20,560 2,150 6,212 Standardized Measure of Discounted Future Net Cash Flows. Accounting Standards Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has advised the Trustee that Chesapeake followed these guidelines, which are briefly discussed below. Future cash inflows and future production costs as of December 31, 2019 , 2018 and 2017 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 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 the Financial Accounting Standards Board 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. 56 CHESAPEAKE GRANITE WASH TRUST SUPPLEMENTARY INFORMATION – (Continued) 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, 2019 2018 2017 ($ in thousands) Future cash inflows $ 39,920 (1) $ 78,267 (2) $ 82,305 (3) Future production costs (4) (2,874 ) (5,647 ) (5,923 ) Future development costs (5) — — — Future income tax provisions (6) — — — Future net cash flows 37,046 72,620 76,382 Less effect of a 10% discount factor (14,188 ) (30,301 ) (31,765 ) Standardized measure of discounted future net cash flows $ 22,858 $ 42,319 $ 44,617 ___________________________________________________ (1) Calculated using prices of $ 2.58 per mcf of natural gas and $ 55.69 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, 2019 were $0.14 per mcf of natural gas, $49.99 per barrel of oil and $12.28 per barrel of NGL. (2) Calculated using prices of $3.10 per mcf of natural gas and $65.56 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, 2018 were $0.69 per mcf of natural gas, $61.61 per barrel of oil and $20.62 per barrel of NGL. (3) Calculated using prices of $2.98 per mcf of natural gas and $51.34 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, 2017 were $0.39 per mcf of natural gas, $46.64 per barrel of oil and $22.61 per barrel of NGL. (4) Future production costs include the Trust's proportionate share of production taxes and post-production costs. The Trust does not bear any operational costs related to the wells. (5) Future net cash flow has been calculated without deduction for future development costs as the Trust does not bear those costs. (6) No provision for federal or state income taxes has been provided for in the calculation because taxable income is passed through to the unitholders of the Trust. Changes in Standardized Measure of Discounted Future Net Cash Flows . The following schedule reconciles the changes for the years ended December 31, 2019 , 2018 and 2017 in the standardized measure of discounted future net cash flows relating to proved reserves: Years Ended December 31, 2019 2018 2017 ($ in thousands) Standardized measure, beginning of period $ 42,319 $ 44,617 $ 34,485 Sales of oil and gas produced, net of production costs (7,970 ) (11,791 ) (13,945 ) Net changes in prices and production costs (17,841 ) 5,879 17,645 Revision of previous quantity estimates 2,327 (1,169 ) 2,108 Accretion of discount 4,232 4,462 3,449 Production timing and other (209 ) 321 875 Standardized measure, end of period $ 22,858 $ 42,319 $ 44,617 57 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.