CHESAPEAKE GRANITE WASH TRUST 10-K

ITEM 1. Business Introduction Chesapeake Granite Wash 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, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust maintains its offices at the office of the Trustee, which is located at 601 Travis Street, Floor 16, Houston, Texas 77002, and the telephone number of the Trustee is (212) 815-5787. The Trustee maintains a website for filings by the Trust with the SEC. Electronic filings by the Trust with the SEC are available free of charge through the Trust's website at www.chkgranitewashtrust.com and through the SEC's website at www.sec.gov . The Trust will also provide electronic and paper copies of its recent filings free of charge upon request to the Trustee. Documents and information on the Trust's website are not incorporated by reference herein. General The Trust was created to own the Royalty Interests for the benefit of Trust unitholders pursuant to a trust agreement dated as of June 29, 2011 and subsequently amended and restated as of November 16, 2011 by and among 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 specified oil and natural gas properties located in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma (the “Underlying Properties”). Chesapeake conveyed the Royalty Interests to the Trust from Chesapeake's interests in the Producing Wells and the Development Wells. The business and affairs of the Trust are managed by the Trustee. The Trust Agreement limits the Trust's business activities generally to owning the Royalty Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances applicable to the Royalty Interests . The royalty interests in the Producing Wells (the “PDP Royalty Interest”) entitle the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to Chesapeake's net revenue interest in the Producing Wells. The royalty interests in the Development Wells (the “Development Royalty Interest”) entitle the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to 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. Neither the Trust nor the Trustee is responsible for , or has any control over , any operating or capital costs of the Underlying Properties. The Trust's cash receipts with respect to the Royalty Interests in the Underlying Properties are determined after deducting certain post-production expenses and any applicable taxes associated with the Royalty Interests. Post-production expenses generally consist of costs incurred to gather , store, compress, transport, process, treat, dehydrate and market the oil, natural gas and NGL produced. However , the Trust is not responsible for costs of marketing services provided by affiliates of Chesapeake. Cash distributions to unitholders will continue to be reduced by the Trust's general and administrative expenses. The Trust will dissolve and begin to liquidate on June 30, 2031, 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 (the “Term Royalties”) 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. 1 The Trust is required to make quarterly cash distributions of substantially all of its quarterly cash receipts, after deducting the Trust's administrative expenses and any cash reserves, on or about 60 days following the completion of each quarter through (and including) the quarter ending June 30, 2031. Quarterly distributions to Trust unitholders will generally include royalty income attributable to sales of oil, natural gas and NGL for three months, including the first two months of the quarter just ended and the last month of the quarter prior to that one. The first quarterly distribution was made on December 28, 2011 to record unitholders as of December 15, 2011. Actual cash distributions to the Trust unitholders will fluctuate quarterly based on the quantity of oil, natural gas, and NGL sold from the Underlying Properties, the prices received for such sales, the timing of Chesapeake's receipt of payment for such sales, the Trust's expenses and other factors. Target distributions will decline over time as a result of the depletion of the reserves in the Underlying Properties. For the year ended December 31, 2019 , 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 ___________________________________________________ As of March 18, 2020 , Chesapeake owned 23,750,000 common units, which represent 50.8% of the outstanding Trust units. Administrative Services Agreement On November 16, 2011, the Trust entered into an administrative services agreement with Chesapeake, effective July 1, 2011, pursuant to which 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 an annual fee of $200,000, which is paid in equal quarterly installments and remains 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. The administrative services agreement will terminate upon the earliest to occur of (a) the date the Trust shall have been wound up in accordance with the Trust Agreement, (b) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (c) with respect to services to be provided with respect to any Underlying Properties being transferred by 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 by Chesapeake and the Trustee. Description of the Trust Common Units. Each Trust unit is a unit of the beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. The Trust has 46,750,000 Trust units issued and outstanding, all of which are common units. Distributions and Income Computations. The Trust is required to make quarterly cash distributions to unitholders from its available funds for such calendar quarter. Royalty Interest payments due to the Trust with respect to any calendar quarter are based on actual sales volumes attributable to the Trust's interests in the Underlying Properties (as measured at Chesapeake's metering systems) for the first two months of the quarter just ended as well as the last month of the immediately preceding quarter and actual revenues received for such volumes. Chesapeake makes the Royalty Interest payments to the Trust within 35 days of the end of each calendar quarter. Taking into account the receipt and disbursement of all such amounts, the Trustee determines for such calendar quarter the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust over 2 the Trust's expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The Trustee distributes cash approximately 60 days (or the next succeeding business day following such day if such day is not a business day) following each calendar quarter to each person who is a Trust unitholder of record on the quarterly record date together with interest expected to be earned on the amount of such quarterly distribution from the date of receipt thereof by the Trustee to the payment date. Unless otherwise advised by counsel or the IRS, the Trustee treats the income and expenses of the Trust for each quarter as belonging to the Trust unitholders of record on the quarterly record date that occurs in such quarter. Trust unitholders recognize income and expenses for tax purposes in the quarter the Trust receives or pays those amounts, rather than in the quarter the Trust distributes them. Minor variances may occur. For example, the Trustee could establish a reserve in one quarter that would not result in a tax deduction until a later quarter. The Trustee could also make a payment in one quarter that would be amortized for tax purposes over several months. Transfer of Trust Units. Trust unitholders may transfer their Trust units in accordance with the Trust Agreement. The Trustee does not require either the transferor or transferee to pay a service charge for any transfer of a Trust unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any Trust unit as shown by its records as the owner of the Trust unit. The Trustee will not be considered to know about any claim or demand on a Trust unit by any party except the record owner. A person who acquires a Trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of Trust units. Periodic Reports. The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust unitholders a Schedule K-1 and also causes to be prepared and filed reports required to be filed under the Exchange Act, and by the rules of the New York Stock Exchange. Each Trust unitholder and his representatives have the right, at his own expense and during reasonable business hours upon reasonable prior notice, to examine and inspect the records of the Trust and the Trustee in reference thereto for any purpose reasonably related to the Trust unitholder's interest as a Trust unitholder. Liability of Trust Unitholders. Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation. Voting Rights of Trust Unitholders. The Trustee or Trust unitholders owning at least 10% of the outstanding Trust units may call meetings of Trust unitholders. The Trust does not intend to hold annual meetings of the Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders unless such meeting is called by the Trust unitholders, in which case the Trust unitholders are responsible for all costs associated with calling such meeting of Trust unitholders. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast. Unless otherwise required by the Trust Agreement, a matter may be approved or disapproved by the vote of a majority of the Trust units held by the Trust unitholders voting in person or by proxy at a meeting where there is a quorum. Accordingly, a matter may be approved even if a majority of the total outstanding Trust units does not approve it. Until such time as Chesapeake and its affiliates own less than 10% of the outstanding Trust units, the affirmative vote of the holders of a majority of common units (excluding common units owned by Chesapeake and its affiliates) and a majority of Trust units voting in person or by proxy at a meeting of such holders at which a quorum is present is required to: • dissolve the Trust (except in accordance with its terms); • remove the Trustee or the Delaware Trustee; 3 • amend the Trust Agreement, the royalty conveyances, the administrative services agreement and the development agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any material respect); • merge, consolidate or convert the Trust with or into another entity; or • approve the sale of all or any material part of the assets of the Trust. At any time when Chesapeake and its affiliates own less than 10% of the outstanding Trust units, the vote of the holders of a majority of Trust units, including units owned by Chesapeake, voting in person or by proxy at a meeting of such holders at which a quorum is present will be required to take the actions described above. Certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders. The Trustee must consent before all or any part of the Trust assets can be sold except in connection with the dissolution of the Trust or limited sales directed by Chesapeake in conjunction with its sale of Underlying Properties. Description of the Trust Agreement. The Trust was created under Delaware law as a separate legal entity to acquire and hold the Royalty Interests for the benefit of the Trust unitholders pursuant to the Trust Agreement among Chesapeake, the Trustee and the Delaware Trustee. The Royalty Interests are passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. Neither Chesapeake nor other operators of the Underlying Properties have any contractual commitments to the Trust to provide additional funding for, to conduct further drilling on or to maintain their ownership interest in any of these properties other than the obligations of Chesapeake to drill the Development Wells. The Trust Agreement provides that the Trust's business activities are generally limited to owning the Royalty Interests and any activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not generally permitted to acquire other oil, natural gas and NGL properties or royalty interests. The Trust is not able to issue any additional Trust units. Contractual Rights and Assets of the Trust. Contractual rights of the Trust include those contained in the development agreement and the administrative services agreement. The assets of the Trust consist of the Royalty Interests and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the Trust unitholders. Duties and Powers of the Trustee. The duties and powers of the Trustee are specified in the Trust Agreement and by the laws of the State of Delaware, except as modified by the Trust Agreement. The Trust Agreement provides that the Trustee shall not have any duties or liabilities, including fiduciary duties, except as expressly set forth in the Trust Agreement and the duties and liabilities of the Trustee as set forth in the Trust Agreement replace any other duties and liabilities, including fiduciary duties, to which the Trustee might otherwise be subject. The Trustee's principal duties consist of: • collecting cash proceeds attributable to the Royalty Interests; • paying expenses, charges and obligations of the Trust from the Trust's assets; • determining whether cash distributions exceed subordination or incentive thresholds, and making cash distributions to the unitholders and Chesapeake (with respect to incentive distributions) in accordance with the Trust Agreement; • causing to be prepared and distributed a Schedule K-1 for each Trust unitholder and preparing and filing tax returns on behalf of the Trust; and • causing to be prepared and filed reports required to be filed under the Exchange Act, and by the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading. Chesapeake will provide administrative and other services to the Trust in fulfillment of certain of the foregoing duties pursuant to the administrative services agreement. The Trustee may create a cash reserve to pay for future expenses of the Trust. If the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust's expenses, the Trustee may cause the Trust to borrow funds required to pay the expenses. The Trust may borrow the funds from any person, including the 4 Trustee or its affiliates or, as described below, Chesapeake. The terms of such indebtedness, if funds were loaned by the entity serving as Trustee or Delaware Trustee, must be similar to the terms which such entity would grant to a similarly situated, unaffiliated commercial customer, and such entity shall be entitled to enforce its rights with respect to any such indebtedness as if it were not then serving as Trustee or Delaware Trustee. If the Trust borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid (except in certain circumstances, where the Trust borrows funds from Chesapeake). Each quarter, the Trustee will pay Trust obligations and expenses and distribute to the Trust unitholders the remaining proceeds received from the Royalty Interests. The cash held by the Trustee as a reserve against future liabilities must be invested in: • interest-bearing obligations of the U.S. government; • money market funds that invest only in U.S. government securities; • repurchase agreements secured by interest-bearing obligations of the U.S. government; or • bank certificates of deposit. Alternatively, cash held for distribution at the next distribution date may be held in a non-interest bearing account. The Trustee withheld approximately $1.0 million from the first distribution to establish an initial cash reserve available for Trust expenses. If the Trustee uses its cash reserve (or any portion thereof) to pay or reimburse Trust liabilities or expenses, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until the cash reserve is replenished. Additional cash reserves may also be established from time to time as determined by the Trustee to pay for future expenses of the Trust. This cash reserve will be part of the Trust estate and will bear interest at the same rate as other cash on hand in the Trust estate. Upon the dissolution of the Trust, after payment of Trust liabilities, the balance of the cash reserve (including accrued interest thereon) will be distributed to Trust unitholders on a pro rata basis. The Trust may not acquire any asset except the Royalty Interests, the other assets described above under Contractual Rights and Assets of the Trust and cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand. The Trust Agreement provides that the Trustee will not make business decisions affecting the assets of the Trust. However, the Trustee may: • prosecute or defend, and settle, claims of or against the Trust or its agents; • retain professionals and other third parties to provide services to the Trust; • charge for its services as Trustee; • retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the Trustee to the extent permitted by law); • lend funds at commercial rates to the Trust to pay the Trust's expenses; and • seek reimbursement from the Trust for its out-of-pocket expenses. In discharging its duty to Trust unitholders, the Trustee may act in its discretion and will be liable to the Trust unitholders only for willful misconduct, bad faith or gross negligence, and certain taxes, fees and other charges based on fees, commissions or compensation received by the Trustee in connection with the transactions contemplated by the Trust Agreement. The Trustee is not liable for any act or omission of its agents or employees unless the Trustee acts with willful misconduct, bad faith or gross negligence in its selection and retention. The Trustee will be indemnified individually or as the Trustee for any liability or cost that it incurs in the administration of the Trust, except in cases of willful misconduct, bad faith or gross negligence. The Trustee has a lien on the assets of the Trust as security for this indemnification and its compensation earned as Trustee. Trust unitholders are not liable to the Trustee for any indemnification. The Trustee is obligated to ensure that all contractual liabilities of the Trust are limited to the assets of the Trust. The Trust may merge or consolidate with or into, or convert into, one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the Trustee and approved by the vote of the holders of a majority of the Trust units 5 and a majority of the common units (excluding common units owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law. At any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding Trust units, however, the standard for approval will be the vote of a majority of the Trust units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum is present. Trustee's Power to Sell Trust Assets. The Trustee may sell Trust assets, including the Royalty Interests, under any of the following circumstances: • the sale is requested by Chesapeake, following the satisfaction of its drilling obligation, in accordance with the provisions of the Trust Agreement; or • the sale is approved by the vote of holders representing a majority of the Trust units and a majority of the common units (excluding common units owned by Chesapeake and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be the vote of a majority of the Trust units, including units owned by Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum is present. Upon dissolution of the Trust, the Trustee must sell the remaining Royalty Interests. No Trust unitholder approval is required in this event. The Trustee will distribute the net proceeds from any sale of the Royalty Interests and other assets to the Trust unitholders after payment or reasonable provision for payment of the liabilities of the Trust. Dispute Resolution. To the fullest extent permitted by law, any dispute, controversy or claim that may arise between Chesapeake and the Trustee relating to the Trust will be submitted to binding arbitration before a panel of three arbitrators. Trust Fees and Expenses. It is expected that the Trust will only incur liabilities for routine administrative expenses, such as legal, accounting, audit, tax advisory, engineering, printing and other administrative and out-of-pocket fees and expenses incurred by or at the direction of the Trustee or the Delaware Trustee, including tax return and Schedule K-1 preparation and mailing costs; independent auditor fees; and registrar and transfer agent fees. The Trust is also responsible for paying costs associated with annual and quarterly reports to unitholders. Moreover, the Trustee's and the Delaware Trustee's compensation, and the fee payable to Chesapeake pursuant to the administrative services agreement, are paid out of the Trust's assets. Chesapeake's Obligation to Fund Trust Expenses in Certain Circumstances . Chesapeake has agreed that, if at any time the Trust's cash on hand (including available cash reserves) is not sufficient to pay the Trust's ordinary course expenses as they become due, Chesapeake will lend 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 accrued current liabilities arising in the ordinary course of the Trust's business, and may not be used to satisfy Trust indebtedness for borrowed money. If Chesapeake lends 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. Any such loan will be on an unsecured basis. There were no loans outstanding as of December 31, 2019 or December 31, 2018. Duration of the Trust; Sale of Royalty Interests . The Trust will dissolve and begin to liquidate on June 30, 2031, or earlier upon the occurrence of certain events, and will soon thereafter wind up its affairs and terminate. At the Termination Date, the Term Royalties will revert automatically to Chesapeake. Following the Termination Date, the Perpetual Royalties will be sold by the Trust and the net proceeds of the sale, as well as any remaining Trust cash reserves, will be distributed to the unitholders pro rata. Chesapeake will have a right of first refusal to purchase the Perpetual Royalties from the Trust following the Termination Date. 6 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 Chesapeake 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 Chesapeake 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 Chesapeake voting in person or by proxy at a meeting of such holders at which a quorum is present; or • the Trust is judicially dissolved. In the case of any of the foregoing, the Trustee would sell all of the Trust's assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders after payment, or reasonable provision for payment, of all Trust liabilities. Federal Income Tax Considerations The Trust's federal income tax reporting position is that it is classified as a partnership for federal and applicable state income tax purposes. This position relies on the opinion of Bracewell & Giuliani L.L.P., former counsel to Chesapeake and the Trust, rendered in connection with the initial public offering of the Trust units, in which counsel opined that at least 90% of the Trust's gross income is qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended. The Trust's federal income tax reporting positions are consistent with the Federal Income Tax Considerations section in the prospectus filed by the Trust with the SEC on November 14, 2011, in connection with the initial public offering of its common units (the “Federal Income Tax Considerations Section in the Prospectus”). However, as discussed in detail below under Item 1A. Risk Factors – Tax Risks Related to the Units , the Trust has not requested a ruling from the IRS regarding its U.S. federal income tax reporting positions and its positions may not be sustained by a court or if contested by the IRS. Additional information regarding the opinion and material tax matters is discussed in the Federal Income Tax Considerations Section in the Prospectus. Competition and Markets The oil and natural gas industry is highly competitive. Chesapeake competes with both major integrated and other independent oil and natural gas companies in all aspects of its business to explore, develop and operate its properties and market its production. Some of Chesapeake's competitors may have larger financial and other resources than Chesapeake. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of Chesapeake's competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities, and overall economic conditions. Chesapeake also faces indirect competition from alternative energy sources, including wind, solar and electric power. Chesapeake believes that its technological expertise, combined with its exploration, land, drilling and production capabilities and the experience of its management team enable it to compete effectively. Recent volatility in oil, natural gas and NGL prices has impacted, and will continue to directly impact, Trust distributions, estimates of reserves attributable to the Trust's interest, and estimated and actual future net revenues to the Trust. In view of the many uncertainties that affect the supply and demand for oil, natural gas and NGL, neither the Trust nor Chesapeake can make reliable predictions of future supply and demand for oil, natural gas and NGL, future oil, natural gas and NGL prices or the effect of future oil, natural gas and NGL prices on the Trust. 7 Public Policy and Government Regulation All of Chesapeake's operations are conducted onshore in the United States. The U.S. oil and natural gas industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations that are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Chesapeake has advised the Trustee that Chesapeake actively monitors regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following are significant areas of government control and regulation affecting our operations. Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations Chesapeake's operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following: • reporting of workplace injuries and illnesses; • industrial hygiene monitoring; • worker protection and workplace safety; • approval or permits to drill and to conduct operations; • provision of financial assurances (such as bonds) covering drilling and well operations; • calculation and disbursement of royalty payments and production taxes; • seismic operations and data; • hydraulic fracturing • location, drilling, cementing and casing of wells; • well design and construction of pad and equipment; • construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance; • method of completing wells and hydraulic fracturing; • water withdrawal; • well production and operations, including processing and gathering systems; • emergency response, contingency plans and spill prevention plans; • emissions and discharges permitting; • climate change; • use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; • surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads; • plugging and abandoning of wells; and • transportation of production. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines or penalties or injunctions limiting Chesapeake's operations in affected areas. Moreover, multiple environmental laws provide for citizen suits that allow environmental organizations to act in the place of the government and sue operators for alleged 8 violations of environmental law. Chesapeake considers the costs of environmental protection and of safety and health compliance necessary, manageable parts of its business. Chesapeake has been able to plan for and comply with environmental, safety and health initiatives without materially altering its operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, Chesapeake's capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and may continue to increase. Chesapeake cannot predict with any reasonable degree of certainty its future exposure concerning such matters. Chesapeake's operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas Chesapeake can produce from its wells and the number of wells or the locations at which it can drill. For further discussion, see Item 1A. Risk Factors - Chesapeake is subject to extensive governmental regulation, which can change and could adversely impact Chesapeake's business. Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could make it prohibitive to conduct operations, and also reduce the amount of oil, natural gas and NGL that Chesapeake is ultimately able to produce in commercial quantities from its properties. Certain of Chesapeake's U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject to frequent delays. Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit Chesapeake's ability to execute its drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of Chesapeake's permits, inability to obtain new permits and the imposition of fines and penalties. For further discussion, see Item 1A. Risk Factors - Oil and natural gas drilling and producing operations can be hazardous and may expose Chesapeake to liabilities. Operating Hazards and Insurance The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, Chesapeake could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Chesapeake's horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations. As a passive entity, the Trust does not maintain insurance policies for the Underlying Properties. Chesapeake maintains a control of well insurance policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating its wells. There is no assurance that this insurance will be adequate to cover all losses or exposure to liability. Chesapeake also carries a $250 million comprehensive general liability umbrella insurance policy and a $50 million pollution liability insurance policy. Chesapeake provides workers' compensation insurance coverage to employees in all states in which it operates. While Chesapeake has informed us that it believes these policies are customary in the industry, they do 9 not provide complete coverage against all operating risks and policy limits scale to Chesapeake's working interest percentage in certain situations. In addition, Chesapeake's insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on Chesapeake's financial position, results of operations and cash flows. Chesapeake's insurance coverage may not be sufficient to cover every claim made against Chesapeake or may not be commercially available for purchase in the future. The Underlying Properties and the Royalty Interests Overview . The Underlying Properties consist of working interests owned by Chesapeake located in the Colony Granite Wash play in Washita County in western Oklahoma arising from leases and farmout agreements related to properties from which the Royalty Interests were conveyed. The AMI consists of approximately 40,500 gross acres ( 26,400 net acres). As of December 31, 2019 and 2018, the total reserves estimated to be attributable to the Trust were 4,175 mboe ( 58% natural gas by volume) and 5,075 mboe (57% natural gas by volume), respectively. These amounts include 4,175 mboe of proved developed reserves and no proved undeveloped reserves as of December 31, 2019 and 5,075 mboe of proved developed reserves and no proved undeveloped reserves as of December 31, 2018 . The decrease in estimated total reserves attributable to the Trust of 900 mboe is primarily attributable to 2019 production and lower oil and natural gas prices. See Item 1A. Risk Factors – Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the valu e of the Trust units and Risks and Uncertainties in Note 2 to the financial statements contained in Part II, Item 8 of this Annual Report for further discussion of the decrease in reserves. The Colony Granite Wash is a subset of the greater granite wash plays of the Anadarko Basin. The Colony Granite Wash is located at the eastern end of a series of Des Moines-age granite wash fields that extend along the southern flank of the Anadarko Basin, approximately 60 miles into the Texas Panhandle. These granite wash fields were generally deposited as deep-water turbidites that result in relatively low risk, laterally extensive reservoirs. The productive members of the Colony Granite Wash are encountered between approximately 11,500 and 13,000 feet and lie stratigraphically between the top of the Des Moines formation (or top of Colony Granite Wash 'A') and the top of the Prue formation (or base of Colony Granite Wash 'C'). The individual productive members within the Colony Granite Wash may reach 200 feet or more in gross interval thickness and the targeted porosity zones within these individual members are generally 20 to 75 feet thick. The Colony Granite Wash is primarily a natural gas and natural gas condensate reservoir based on reserve volumes. However, in the Colony Granite Wash, oil and NGL production currently generate more revenue than natural gas production due to higher relative prices for oil and NGL than for natural gas. No development costs were incurred in the years ended December 31, 2019 and 2018 due to no new wells being drilled by Chesapeake in the Colony Granite Wash after Chesapeake's fulfillment of its drilling obligation to the Trust. Royalty Interests. The Royalty Interests were conveyed from Chesapeake's interest in the Underlying Properties effective as of July 1, 2011. As of December 31, 2019 , the Trust on average owns a 47.6% net revenue interest in the Producing Wells and a 28.4% net revenue interest in the completed Development Wells. Chesapeake retains 10% of the proceeds from the sales of oil, natural gas and NGL production attributable to its net revenue interest in the Producing Wells, and 50% of the proceeds from the sales of production attributable to its net revenue interest in the Development Wells. The Royalty Interests were conveyed to the Trust by Chesapeake by means of conveyance instruments that were recorded in the appropriate real property records in Washita County , Oklahoma. The conveyance instruments obligate Chesapeake to act diligently and as a reasonably prudent oil and gas operator would act under the same or similar circumstances as if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens affecting such properties. We refer to this standard as the "Reasonably Prudent Operator Standard." The Trustee has no ability to manage or influence the operation of the Underlying Properties. Oil, Natural Gas and NGL Reserves. Proved reserve quantities attributable to the Royalty Interests are calculated by multiplying the gross reserves for each property attributable to Chesapeake's interest by the net revenue interest assigned to the Trust in each property. The reserves related to the Underlying Properties include all proved reserves expected to be economically produced during the life of the properties. The reserves attributable to the Trust's interests include only the reserves attributable to the Underlying Properties that are expected to be produced within the 20-year period prior to the Termination Date as well as the residual 50% interest in the Royalty Interests that the Trust will own on the Termination Date and subsequently sell. 10 All of the Trust's estimated oil, natural gas and NGL reserves are located within the U.S. The table below sets forth information as of December 31, 2019 with respect to the estimated proved reserves of the Underlying Properties and Royalty Interests and the associated PV-10. Because the Trust will not bear income tax expense, PV-10 and the standardized measure of estimated future net revenue of the Royalty Interests are the same. PV-10 is not intended to represent the current market value of the estimated oil, natural gas and NGL reserves attributable to the Royalty Interests. The reserve estimates were prepared by Software Integrated Solutions, Division of Schlumberger Technology Corporation, in accordance with the criteria established by the SEC. Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP. Proved Reserves Oil (mbbl) Natural Gas (mmcf) NGL (mbbl) Total (mboe) PV-10 ($ in thousands) Underlying Properties: Developed 918 30,884 2,776 8,841 $ 18,713 Undeveloped — — — — — Total 918 30,884 2,776 8,841 $ 18,713 Royalty Interests: Developed (1) 438 14,631 1,298 4,175 $ 22,858 Undeveloped (1) — — — — — Total 438 14,631 1,298 4,175 $ 22,858 _________________________________________________ (1) PV-10 for the Royalty Interests was calculated exclusive of any production or development costs. Proved Developed Proved Undeveloped Total Proved ($ in thousands) Estimated future net revenue (1) $ 37,046 $ — $ 37,046 Present value of estimated future net revenue (PV-10) (1) $ 22,858 $ — $ 22,858 Standardized measure (1) $ 22,858 _________________________________________________ (1) Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and costs, using prices and costs under existing economic conditions as of December 31, 2019 . PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted at 10% per annum to reflect timing of future cash flows and calculated without deducting future income taxes. PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted net cash flows, or the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, as the Trust is not subject to income tax expense, the two measures are the same as of December 31, 2019 . A comparison of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of the proved oil and gas reserves. 11 The proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil, natural gas and NGL for the period from January 1, 2019 through December 1, 2019, and were held constant for the life of the properties. The prices used in the reserve reports, as well as Chesapeake's internal reports, yield weighted average prices at the wellhead, which are based on first-day-of-the-month reference prices and before basis differential adjustments. For the Royalty Interests, costs of marketing services provided by Chesapeake's affiliates will not be charged to the Trust. The reference prices and the equivalent weighted average wellhead prices are presented in the table below. Oil Natural Gas (per bbl) (per mcf) Trailing 12-month average (SEC) pricing $ 55.69 $ 2.58 Weighted average wellhead prices (Underlying Properties) $ 49.99 $ 0.14 Weighted average wellhead prices (Royalty Interests) $ 49.99 $ 0.14 As of December 31, 2019 , no Royalty Interests were classified as PUDs. As of December 31, 2019 , of the total proved reserves, 8,841 mboe and 4,175 mboe attributable to the Underlying Properties and the Royalty Interests, respectively, were classified as proved developed reserves. Chesapeake's ownership interest used for calculating proved reserves and the associated estimated future net revenue assumed maximum participation by other parties to Chesapeake's farmout and participation agreements. SEC pricing used for calculating the estimated future net revenues attributable to proved reserves does not reflect actual market prices for oil, natural gas and NGL production sold subsequent to December 31, 2019 . The Trust's estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2019 and 2018, respectively, along with the changes in quantities and standardized measure of such reserves for the two years ended December 31, 2019 and 2018, respectively, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this Annual Report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond Chesapeake's control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions to such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures about Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities. Development Wells. Pursuant to the development agreement with the Trust, Chesapeake was obligated to drill, cause to be drilled or participate as a non-operator in the drilling of 118 Development Wells by June 30, 2016. Chesapeake had fulfilled its drilling obligation under the development agreement as of June 30, 2016. Chesapeake has retained an interest in each of the Producing Wells and Development Wells and currently operates approximately 96% of the Producing Wells and completed Development Wells. Prior to fulfilling its commitment to drill the Development Wells, Chesapeake was not allowed to drill or complete, or permit any other person within its control to drill or complete any well in the Colony Granite Wash formation or lease acreage included within the AMI for its own account. For the life of the Trust, Chesapeake will not be permitted to drill or complete any well that will have a perforated segment within 600 feet of any perforated interval of any Development Well or Producing Well. Chesapeake's average net revenue interest in the oil and gas properties underlying the Development Royalty Interest is approximately 63%. The Development Royalty Interest entitles the Trust to receive 50% of the proceeds attributable to Chesapeake's net 12 revenue interest in future production of oil, natural gas and NGL from the Development Wells. The Trust was not responsible for any costs related to the drilling of the Development Wells and is not responsible for any other operating or capital costs of the Underlying Properties. Chesapeake granted to the Trust a lien on its interest in the AMI (except the Producing Wells and any other wells that were already producing as of July 1, 2011 and are not subject to the Royalty Interests) in order to secure the estimated amount of the drilling costs for the Trust's interests in the Development Wells (the "Drilling Support Lien"). The Trust did not obtain any amounts from Chesapeake under the Drilling Support Lien during the period in which Chesapeake was drilling the Development Wells, and the Drilling Support Lien has been reduced to zero. Due to Chesapeake's completion of its drilling obligation under the development agreement, it may now sell all or any part of its retained interest in the Underlying Properties, without the consent or approval of the Trust unitholders. In any such sale by Chesapeake, the Underlying Properties must be sold subject to and burdened by the Royalty Interests, except that Chesapeake may require the Trust to release the Royalty Interests on such Underlying Properties with an aggregate value of up to $5.0 million during any 12-month period. In such event, the Trust must receive an amount equal to the fair value to the Trust of any royalty interests it sells. Drilling Activity . The following table sets forth information with respect to the wells Chesapeake drilled or participated in during the periods indicated that were located in the AMI. The information presented is not necessarily indicative of future performance and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Gross wells are the total number of producing wells in which Chesapeake has a working interest and net wells are the sum of Chesapeake's fractional working interest owned in such gross wells. 2019 2018 Gross Net Gross Net Wells Drilled: Development productive — — — — Exploratory productive — — — — Dry — — — — Total — — — — Developed and Undeveloped Acreage . The following table sets forth information regarding developed and undeveloped acreage held by Chesapeake within the AMI as of December 31, 2019 . All of the leases associated with the Underlying Properties are held by production and not subject to expiration so long as production continues in paying quantities. Developed Acreage (1) Undeveloped Acreage Gross Net Gross Net Acreage Held by Chesapeake within the AMI 40,236 26,195 — — _________________________________________________ (1) Gross and net developed acres are acres spaced or assignable to productive wells. The drilling unit for each Colony Granite Wash horizontal well comprises 640 acres. As such, developed acreage may include up to 640 acres assigned to each Colony Granite Wash horizontal well. Marketing and Post-Production Services. Pursuant to the terms of the conveyances creating the Royalty Interests, Chesapeake has the responsibility to market, or cause to be marketed, the oil, natural gas and NGL production related to the Underlying Properties. While marketing costs of non-affiliates of Chesapeake are deducted from the proceeds upon which the royalty payments are calculated, the Trust is not responsible for costs of marketing services provided by Chesapeake or any of its affiliates. Chesapeake Energy Marketing, L.L.C. ("CEMLLC"), a wholly owned subsidiary of Chesapeake, markets the majority of Chesapeake's operated production. CEMLLC enters into oil, natural gas and NGL sales arrangements with large aggregators of supply, and these arrangements may be on a month-to-month basis or for a term of up to one year or longer . The oil, natural gas and NGL are sold at market prices and subsequently any applicable post-production expenses will be deducted. CEMLLC sells production from the Underlying Properties to a diverse group of aggregators, the identity of which changes from time to time. As a result, the proceeds to the 13 Trust from the sales of oil, natural gas and NGL production from the Underlying Properties is determined based on the same price (net of post-production costs and production taxes) that Chesapeake receives from third parties for oil, natural gas and NGL production attributable to Chesapeake's remaining interest in the Underlying Properties. Post-production expenses are deducted from proceeds paid to the Trust. Williams Partners, L.P. ("WMB"), provides gathering, treating, compression and other post-production services and Enable Midstream Partners, LP ("Enable") provides gathering, processing, transportation and other post-production services. The proceeds paid to the Trust are reduced by deductions for these post-production expenses. Post-production expenses may be deducted by the ultimate purchaser of the oil, natural gas and NGL prior to payment being made to Chesapeake or CEMLLC for such production. At other times, Chesapeake or CEMLLC makes payments directly to the applicable provider of such post-production services. In either instance, the Trust's cash available for distribution is reduced by the expenses incurred by Chesapeake or CEMLLC for such post-production services. If the post-production expenses are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is less the applicable percentage charged, and as a result the reserves associated with that well that are attributable to the Royalty Interest are reduced accordingly . The post-production expenses are negotiated based on market conditions at the time or pursuant to a state or federal regulatory proceeding. Chesapeake is permitted to deduct from the proceeds available to the Trust other post-production expenses necessary to enhance the value of the oil, natural gas and NGL from the Underlying Properties and to transport such production to market. Natural gas and NGL produced from the Underlying Properties are gathered by gathering pipelines owned by WMB under a contract that expires in approximately 10 years. NGL and natural gas are gathered and processed at facilities owned by Enable under a contract that expires in 2023 and then sold to a number of primary purchasers in the area. Oil produced from the Underlying Properties is gathered by gathering pipelines and equipment owned by WMB or transported by trucks owned by third parties and sold to various counterparties. In the event of a loss of its contracts with WMB or Enable, Chesapeake believes that the availability of other customers and service providers in the area is sufficient to accommodate such loss. Any new oil, natural gas and NGL supply arrangements or those entered into for providing post-production services will be utilized in determining the proceeds for the Underlying Properties. Discussion and Analysis of Results from the Underlying Properties Historical Results . The Underlying Properties consist of the working interests owned by Chesapeake in the Colony Granite Wash in Washita County in western Oklahoma arising under leases and farmout agreements related to properties from which the PDP Royalty Interest and the Development Royalty Interest were conveyed. The following table provides revenues and direct operating expenses for the years ended December 31, 2019 , and 2018, as derived from the Underlying Properties' statements of revenues and direct operating expenses. Years Ended December 31, 2019 2018 ($ in thousands) Oil, natural gas and NGL revenues (1) $ 12,887 $ 20,792 Direct operating expenses: Production expenses excluding taxes 7,201 7,670 Production taxes 838 1,538 Ad valorem taxes 4 4 Total direct operating expenses 8,043 9,212 Revenues in excess of direct operating expenses $ 4,844 $ 11,580 _________________________________________________ (1) Oil, natural gas and NGL revenues are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses. 14 The following table sets forth the production, average sales prices, and average cost per boe for production expenses and production taxes for the Underlying Properties for the years ended December 31, 2019 , and 2018. Years Ended December 31, 2019 2018 Production: Oil (mbbls) 162 181 Natural gas (mmcf) 3,841 4,613 NGL (mbbls) 337 413 Total production (mboe) 1,140 1,363 Average sales prices: (1) Oil (per bbl) $ 50.12 $ 60.32 Natural gas (per mcf) $ 0.17 $ 0.62 NGL (per bbl) $ 12.18 $ 16.91 Average (per boe) $ 11.30 $ 15.25 Direct operating expenses: Production expenses (per boe) (2) $ 6.32 $ 5.63 Production taxes (per boe) (3) $ 0.74 $ 1.13 ___________________________________________________ (1) Average sales prices are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses. (2) Production expenses include lease operating costs. (3) Production taxes are generally based upon volume produced and prices received for production and include ad valorem taxes. Oil, Natural Gas and NGL Revenues. For the year ended December 31, 2019 , oil, natural gas and NGL revenues were $12.9 million compared to $20.8 million for the year ended 2018 . The $7.9 million decrease in revenues from 2018 to 2019 was due to a decrease in average sales prices received and a decrease in production. The overall decrease in the price received per boe in 2019 compared to 2018 resulted in a $4.5 million decrease in oil, natural gas and NGL revenues. Decreased sales volumes resulted in a $3.4 million decrease in oil, natural gas and NGL revenues. Production Expenses. For the year ended December 31, 2019 , production expenses were $7.2 million compared to $7.7 million for the year ended 2018 . On a unit-of-production basis, production expenses were $6.32 per boe in 2019 compared to $5.63 per boe in 2018 . Production Taxes. For the year ended December 31, 2019 , production taxes were $0.8 million , compared to $ 1.5 million for the year ended 2018 . On a unit-of-production basis, production taxes were $0.74 per boe in 2019 compared to $ 1.13 per boe in 2018 . The decrease in production taxes from 2018 to 2019 was primarily due to the decrease in commodity prices. The Reserve Report for the Underlying Properties and the Royalty Interests The oil, natural gas and NGL reserves in this Annual Report were estimated by Software Integrated Solutions, Division of Schlumberger Technology Corporation ("Software Integrated Solutions"). The process to review and estimate the reserves begins with Chesapeake's Corporate Reserves Department collecting and verifying all pertinent data, including but not limited to well test data, production data, historical pricing, cost information, property ownership interests, reservoir data, and geosciences data. This data is reviewed by various levels of Chesapeake management for accuracy before consultation with Software Integrated Solutions. Software Integrated Solutions was consulted with regularity during the reserve estimation process to review properties, assumptions, and any new data available. Internal reserve estimates and methodologies are compared to Software Integrated Solutions' estimates and methodologies to test the reserve estimates and conclusions before the reserve estimates are included in this Annual Report. Additionally, Chesapeake's senior management reviews and approves the reserve report contained herein. 15 Internal Controls . Chesapeake's Director - Corporate Reserves is the technical person primarily responsible for overseeing the preparation of the Trust's reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. Her qualifications include the following: • over 17 years of practical experience in the oil and gas industry, with 15 years in reservoir engineering; • Bachelor of Science degree in Geology and Environmental Sciences; • Master's Degree in Petroleum and Natural Gas Engineering; • Executive MBA; and • member in good standing of the Society of Petroleum Engineers. Chesapeake ensures that the key members of Chesapeake's Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserves estimates. Each of Chesapeake's Corporate Reserves Engineers has significant experience in reserve estimation. Each of its engineering technicians has a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. Chesapeake also maintains a continuous education program for its engineers and technicians on new technologies and industry advancements and offers refresher training on basic skills and analytical techniques. Chesapeake maintains internal controls such as the following to ensure the reliability of reserves estimations: • Chesapeake follows comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserves estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Chesapeake's Corporate Reserve Engineers. • Chesapeake's Corporate Reserves Department reviews all of Chesapeake's and the Trust's proved reserves at the close of each quarter. • Each quarter, Chesapeake's Reservoir Managers, the Director - Corporate Reserves, the Vice Presidents of its business units, the Vice President of Corporate and Strategic Planning and the Executive Vice President - Exploration and Production review all significant reserves changes and all new proved undeveloped reserves additions. • Chesapeake's Corporate Reserves Department reports independently of Chesapeake's operations. Technologies . The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells, as defined by the SEC. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset undeveloped wells in the field. The continuity of the play across the AMI area was established by reviewing electronic well logs from wells, geologically mapping the analogous reservoir and reviewing extensive production data from horizontal wells within the larger Colony Granite Wash area. Software Integrated Solutions . Chesapeake engaged Software Integrated Solutions, a third-party engineering firm, to prepare all of the Trust's estimated proved reserves as of December 31, 2019 . A copy of the report issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical person at the firm primarily responsible for overseeing the preparation of 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. Miscellaneous The Trustee may consult with counsel (which may include counsel to Chesapeake), accountants, tax advisors, geologists and engineers and other parties the Trustee believes to be qualified as experts on the matters for which advice is sought. The Trustee is protected for any action it takes in good faith reliance upon the opinion of the expert. 16 The Delaware Trustee and the Trustee may resign at any time or be removed with or without cause at any time by the vote of a majority of the outstanding Trust units (excluding common units owned by Chesapeake and its affiliates) voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Chesapeake and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be the vote of a majority of the Trust units, including units owned by Chesapeake, voting in person or by proxy at a meeting of such holders at which a quorum is present. Abstentions and broker non-votes shall not be deemed to be votes cast. Any successor must be a bank or trust company meeting certain requirements, including having combined capital, surplus and undivided profits of at least $20 million, in the case of the Delaware Trustee, and $100 million, in the case of the Trustee. 17