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  • Location: Oklahoma 
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    2018 ANNUAL REPORT CHAPARRAL


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    A LETTER FROM OUR CEO This past year was without question a truly historic year As part of our commitment to cost management, we for Chaparral. Marked by our uplisting to the New York will be reducing our rig count from four to three rigs in Stock Exchange, $300 million senior notes offering, record- the second quarter. This strategic reduction will allow setting STACK production and commencement of our first us to lower our capital budget, while still competitively STACK spacing tests, we were able to strengthen our balance growing production. In fact, we expect to grow STACK sheet, enhance operations and significantly increase STACK production by an estimated 45% to 59% and total company production and reserves, while maintaining one of the production between 22% and 32% in 2019. As a result, industry’s lowest operating cost structures. we anticipate total company production to surpass our pre-EOR divestiture level before the end of this year. Over the last two years, we have successfully optimized our asset portfolio to focus on low-cost, high-return properties Maintaining liquidity and a commitment to financial — primarily in Oklahoma’s STACK Play. As a result, we discipline will continue to be crucial to our success, have been able to generate significant returns on our capital while our growing asset base has allowed us to increase our investment as we have grown production and decreased costs borrowing base capacity. Likewise we will continue to look for through a laser focus on operational and financial efficiency. opportunities to further strengthen our balance sheet, create As such, our total company lease operating expense per barrel long-term value and increase the price per share of our stock. (LOE/Boe) has decreased almost $4, and we expect it to continue to decline as low-cost STACK production continues to Driven by our core values of promoting integrity, driving grow into a greater percentage of our total company production. results, building relationships and employing technical excellence, Chaparral will continue to aggressively pursue our Chaparral will continue to build upon this tremendous goal to be the premier STACK operator and deliver strong momentum in 2019 as we remain focused on capital value to our shareholders while maintaining our reputation efficiency and long-term shareholder value creation. In as one of the safest and most efficient operators in the basin. 2019, we will invest all of our drilling and completion capital within the STACK as we continue to develop our outstanding 131,000-acre position and conduct spacing tests across Kingfisher, Canadian and Garfield counties. K. Earl Reynolds Chief Executive Officer March 14, 2019 CHAPARRAL


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    We have been able to generate significant returns on our capital investment as we have grown production and decreased costs through a laser focus on operational and financial efficiency. STACK/Merge Production 23.0 25 16 - 2019E) 20 rowth (20 200% G 21.0 16.50 15 ~ 15.50 14.5 10 9.5 5 7.3 5.4 0 2016 2017 FY 2018E FY 2019 E 1 2019 Stack Guidance Range Q1 2019 Guidance (Low) Q1 2019 Guidance (High) 1 Based on mid-point of 2019 production guidance Total Company LOE/Boe STACK Reserves $12.00 80 $10.00 $10.96 70 74.1 $10.14 60 $8.00 50 $7.24 49.4 $6.00 40 $5.25 $4.00 30 31.2 20 $2.00 10 $0.00 0 2016 2017 2018 FY 2019 E1 2016 2017 2018 LOE/Boe MMBoe 1 Based on mid-point of 2019 production guidance 2018 ANNUAL REPORT - PAGE 2


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    HIGH-QUALITY Chaparral’s approximately 131,000-acre STACK position provides access to multiple ASSETS oil-rich formations and contains decades of robust drilling inventory in the Meramec, Osage and Woodford formations. The company STACK continued to focus on strategic 131,000 acquisitions and divestitures as it 260,000 secured a 131,000 net acre position in the heart of the STACK. TOTAL Strengthening its STACK position, Chaparral acquired a 7,000 contiguous net acre position in the heart of the 7,000 black-oil window of the STACK. Acre Bolt-on Acquisition in Kingfisher County 100 Chaparral’s $100 million joint venture with Bayou City Energy accelerated its ability to de-risk 80% of its Canadian County Merge and Drilling Joint Venture 50% of its Garfield County position by year-end 2018. The company began its first operated spacing tests in Canadian and Kingfisher counties. TESTING Conducts First Spacing Tests CHAPARRAL


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    RECORD-SETTING OPERATIONAL Driven by low-cost operations and the pursuit of continuous improvement, Chaparral PERFORMANCE continues to deliver industry-leading operational results in one of America’s most economical and active plays. Chaparral replaced 519% of its STACK production as it grew year-over-year reserves by approximately 50% to 74.1 MMBoe. Total 2018 company proved reserves grew 35% on a pro-forma basis for asset sales. PROVED STACK Reserves 52% Strong Canadian County Merge and Garfield County results helped grow STACK production STACK by more than 50% to 14.5 MBoe/d in 2018. PRODUCTION GROWTH Chaparral’s commitment to low-cost operations resulted in a STACK STACK drillbit finding and development cost DRILLBIT of $7.80/Boe. FINDING & DEVELOPMENT $7.80/Boe Determined to lower operating costs, Chaparral 34% reduced its total company LOE/Boe by almost $4 compared to 2017, which included an impressive $4.86 DECREASE LOE/Boe in the STACK. OF 34% In Total Company LOE/Boe 2018 ANNUAL REPORT - PAGE 4


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    OUTSTANDING INVESTMENT Chaparral is committed to maintaining a strong balance sheet and the financial flexibility necessary to succeed in the ever-changing market condition. Focused on profitably growing OPPORTUNITY production and delivering strong returns, employees continuously work to identify methods to lower costs, deliver results and improve the return on capital investments. A historic milestone, Chaparral began trading on the New York Stock Exchange in July 2018 under the symbol “CHAP.” The uplisting event provided greater opportunities to create long-term value and increased the company’s investor base. NYSE UPLISTING Under Symbol CHAP Recognition of the value of Chaparral’s premier STACK assets helped drive an increase in the company’s borrowing base from $265 million to $325 million and its credit facility from $400 million to $750 million. With no debt due until 2022, the company NO DEBT has ample liquidity MATURITIES to continue to grow regardless of changes UNTIL in market conditions. 2022 300 Chaparral completed a $300 million senior notes offering. Proceeds allowed the company to pay down all of its outstanding borrowings on its revolving Sr. Notes Offering create facility and further strengthen its balance sheet. CHAPARRAL


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    UNWAVERING COMMITMENT TO ENVIRONMENTAL, HEALTH AND SAFETY SAFETY METRICS Chaparral’s culture is driven by a ZERO incident mentality. Nothing is more important than the safety of our employees, partners, neighbors and the communities where we operate. As such we hold our employees and partners to standards which often exceed those of regulatory agencies to ensure safe and environmentally friendly operations. Every employee who sets foot on a Chaparral location has the ability and responsibility to stop any work they believe could present a hazard. Through the company’s safety observation program, employees are rewarded for reporting near-miss and hazard observations both in the field and at our corporate office so potential issues can be identified and addressed before an incident ever occurs. In addition, all of Chaparral’s vendors and partners must complete a rigorous screening and verification process to ensure they are properly trained and certified to complete work at any Chaparral facility. Thanks to these efforts and more, Chaparral has seen a consistent improvement during the last 10 years across all of our health and safety metrics, making us an industry EHS leader. 2018 ANNUAL REPORT - PAGE 6


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    UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K 侌 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2018 OR 侊 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from Commission file number: 001-38602 Chaparral Energy, Inc. (Exact name of registrant as specified in its charter) Delaware 73-1590941 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 701 Cedar Lake Boulevard Oklahoma City, Oklahoma 73114 (Address of principal executive offices) (Zip code) (405) 478-8770 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of class Name of each exchange on which registered Class A common stock, par value, $0.01 per share The New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None. Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 侊 No 侌 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes 侊 No 侌 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes _ No 侊 Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes _ No 侊 Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 侊 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer 侊 Accelerated filer _ Non-accelerated filer 侊 Smaller reporting company 侊 Emerging growth company 侊 If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 侊 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes 侊 No 侌 As of June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s Class A common stock held by non-affiliates was $580.1 million. As of June 30, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s Class B common stock held by non-affiliates was not determinable as such shares are privately held and there is no public market for such shares. Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.Yes 侌 No 侊 Number of shares outstanding of each of the issuer’s classes of common stock as of March 12, 2019: Class Number of shares Class A Common Stock, $0.01 par value 46,451,200 Documents incorporated by reference: Certain information called for in Items 10, 11, 12, 13 and 14 of Part III will be included in an amendment to this Annual Report on Form 10-K.


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    CHAPARRAL ENERGY, INC. Index to Form 10-K Part I Items 1. and 2. Business and Properties 7 Item 1A. Risk Factors 33 Item 1B. Unresolved Staff Comments 51 Item 2. Properties 51 Item 3. Legal Proceedings 51 Item 4. Mine Safety Disclosures 55 Part II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 56 Item 6. Selected Financial Data 59 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 60 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 87 Item 8. Financial Statements and Supplementary Data 91 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 152 Item 9A. Controls and Procedures 152 Item 9B. Other Information 155 Part III Item 10. Directors, Executive Officers and Corporate Governance 155 Item 11. Executive Compensation 155 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 155 Item 13. Certain Relationships and Related Transactions and Director Independence 155 Item 14. Principal Accounting Fee Services 155 Part IV Item 15. Exhibits and Financial Statement Schedules 156 Signatures 159 1


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    CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about: • fluctuations in demand or the prices received for oil and natural gas; • the amount, nature and timing of capital expenditures; • drilling, completion and performance of wells; • competition and government regulations; • timing and amount of future production of oil and natural gas; • costs of exploiting and developing properties and conducting other operations, in the aggregate and on a per-unit equivalent basis; • changes in proved reserves; • operating costs and other expenses; • our future financial condition, results of operations, revenue, cash flows and expenses; • estimates of proved reserves; • exploitation of property acquisitions; and • marketing of oil and natural gas. These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described under the heading “Risk Factors,” the factors include: • worldwide supply of and demand for oil and natural gas; • volatility and declines in oil and natural gas prices; • drilling plans (including scheduled and budgeted wells); • our new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from current values; • the number, timing or results of any wells; • changes in wells operated and in reserve estimates; • future growth and expansion; • future exploration; • integration of existing and new technologies into operations; • future capital expenditures (or funding thereof) and working capital; • effectiveness and extent of our risk management activities; • availability and cost of equipment; • risks related to the concentration of our operations in the mid-continent geographic area; • borrowings and capital resources and liquidity; • covenant compliance under instruments governing any of our existing or future indebtedness; • changes in strategy and business discipline, including our post-emergence business strategy; • future tax matters; 2


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    • legislation and regulatory initiatives; • any loss of key personnel; • geopolitical events affecting oil and natural gas prices; • weather, including its impact on oil and natural gas demand and weather-related delays on operations; • outcome, effects or timing of legal proceedings; • the effect of litigation and contingencies; • the outcome, timing or effects of environmental litigation; • the ability to generate additional prospects; and • the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture. Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions may change the schedule of any future production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered. Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. 3


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    GLOSSARY OF CERTAIN DEFINED TERMS The terms defined in this section are used throughout this annual report on Form 10-K: Bankruptcy Court United States Bankruptcy Court for the District of Delaware A low region or natural depression in the earth’s crust where sedimentary deposits Basin accumulate. Bbl One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate, or natural gas liquids. BBtu One billion British thermal units. Boe Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil. Boe/d Barrels of oil equivalent per day. Btu British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. Completion The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned. CO2 Carbon dioxide. Developed acreage The number of acres that are assignable to productive wells. Development well A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Disclosure Statement Disclosure Statement for the Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code. Dry well or dry hole An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. EOR Areas Areas where we previously injected, planned to inject and/or recycled CO2 as a means of oil recovery. Enhanced oil recovery (EOR) The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after Secondary Recovery. Exit Credit Facility Ninth Restated Credit Agreement, dated as of March 21, 2017, by and among us, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent and each of the Lenders named therein, as amended. Exit Revolver A first-out revolving facility under the Exit Credit Facility. Exit Term Loan A second-out term loan under the Exit Credit Facility. Exploratory well A well drilled to find a new field or to find a new reservoir in a field previously found to produce oil or natural gas in another reservoir. Field An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. Horizontal drilling A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval. 4


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    Limestone/carbonate A sedimentary rock composed primarily of calcium carbonate. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It can be composed of various calcium carbonate grains or chemically precipitated. It often contains variable amounts of silica, silt, and clay. It is highly soluble which often results in secondary porosity and karsting. This can vary greatly from place to place. These factors all generally make this rock type a more heterogeneous deposit than sandstone. MBbls One thousand barrels of crude oil, condensate, or natural gas liquids. MBoe One thousand barrels of crude oil equivalent. Mcf One thousand cubic feet of natural gas. MERGE An area which represents the intersection of historical STACK and SCOOP (acronym for South Central Oklahoma Oil Province, a play in the Anadarko Basin of Oklahoma) play outlines in Central Oklahoma. MMBoe One million barrels of crude oil equivalent. MMBtu One million British thermal units. MMcf One million cubic feet of natural gas. MMcf/d Millions of cubic feet per day. Natural gas liquids (NGLs) Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline. Net acres The percentage of total acres an owner has out of a particular number of acres, or in a specified tract. An owner who has a 50% interest in 100 acres owns 50 net acres. New Credit Facility Tenth Restated Credit Agreement, as amended, by and among Chaparral Energy, Inc., Royal Bank of Canada as Administrative Agent and the Lenders and Prepetition Borrowers Party Hereto. NYMEX The New York Mercantile Exchange. OPEC Organization of the Petroleum Exporting Countries Play A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves. Prior Credit Facility Eighth Restated Credit Agreement, dated as of April 12, 2010, by and among us, Chaparral Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and The Lenders and Prepetition Borrowers Party Hereto. Prior Senior Notes Collectively, our 9.875% senior notes due 2020, 8.25% senior notes due 2021, and 7.625% senior notes due 2022, of which all obligations have been discharged upon consummation of our Reorganization Plan. Productive well A well that is currently producing oil or natural gas or is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. Proved developed reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved reserves The quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved undeveloped reserves Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. 5


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    PV-10 value When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non- property-related expenses, discounted to a present value using an annual discount rate of 10%. Registration Rights Agreement Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein. Reorganization Plan First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors under Chapter 11 of the Bankruptcy Code. Royalty Interest An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. SEC The Securities and Exchange Commission. Secondary recovery The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure. Seismic survey Also known as a seismograph survey, it is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations. Senior Notes Our 8.75% senior notes due 2023. STACK An acronym standing for Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko Basin of Oklahoma in which we operate. Undeveloped acreage Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves. Unit The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement. Wellbore The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole. Working interest The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis. Zone A layer of rock which has distinct characteristics that differs from nearby layers of rock. 6


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    PART I Unless the context requires otherwise, references in this annual report to the “Company,” “Chaparral,” “we,” “our” and “us” refer to Chaparral Energy, Inc. and its subsidiaries on a consolidated basis. We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of Certain Defined Terms” at the beginning of this annual report. ITEMS 1. AND 2. BUSINESS AND PROPERTIES Overview A Delaware corporation formed in 1988, and publicly held since 2017, Chaparral Energy, Inc. (NYSE: CHAP) is an independent oil and natural gas exploration and production company headquartered in Oklahoma City. Chaparral is an operator focused in Oklahoma’s hydrocarbon rich STACK Play, where it has approximately 131,000 net acres primarily in Kingfisher, Canadian and Garfield counties. The company has approximately 260,000 net surface acres in the Mid-Continent region. Beginning in the early 1990s, our operations in the area later to become known as the STACK were focused on vertical wells and waterfloods. Since late 2013, however, we have concentrated on the horizontal development of the Mississippian-age Osage and Meramec formations, the Pennsylvanian-age Oswego formation, as well as Devonian-age Woodford Shale formation. Building on early success achieved from our initial STACK drilling activities to delineate the Osage, Meramec, Woodford and Oswego formations through the drilling of single section horizontal wells, we significantly increased our leasing and drilling activities in 2017 and 2018. Our activities focused on expanding our understanding of the productive extent and hydrocarbon content of the play and holding acreage with production. Through our 2017 and 2018 activities in the STACK, we have successfully tested productive zones in the play, applied optimized completions to improve recoveries, demonstrated repeatability of results, reduced cycle times, and de-risked a sizeable portion of our acreage in the play. Additionally, in 2018, we commenced the evaluation of full section infill development multi-well patterns to help determine optimum well spacing and to maximize economic recovery of oil and natural gas from each formation. As of December 31, 2018, we had estimated proved reserves of 94.8 MMBoe with a PV-10 value of approximately $686.0 million. Our estimated proved reserve life is approximately 12.7 years. These estimated proved reserves included 74.1 MMBoe of reserves in our STACK play which represents a 50% increase from the prior year. Our total reserves were 59% proved developed, 34% crude oil, 27% natural gas liquids and 39% natural gas. Our average daily net production in the fourth quarter of 2018 was approximately 21.7 MBoe of which approximately 16.6 MBoe was attributable to our STACK assets. We intend to grow our reserves and production through the development of our multi-year inventory of identified drilling locations within the STACK. From 2016 to 2018, we increased our STACK production at a compound annual growth rate of approximately 39%. At present, we are operating four horizontal drilling rigs in the STACK. In response to recent lower commodity prices and volatility, we plan to decrease our activity from four to three rigs in the second quarter of 2019. We have allocated our entire drilling and completions budget for 2019 to our STACK play. Our 2019 activities will focus on delineating and de-risking our acreage, expanding the known productive extent of the play through the completion of well spacing projects, monitoring production from optimized completions, and continued refinement of our geologic and economic models in the area. Business Strategy Our business strategy is to create economic and stockholder value by applying our core strengths in execution and cost control to exploit our robust inventory of horizontal drilling opportunities in the higher-return STACK unconventional resource play. Key components of our long-term business strategy include: Preserving a strong and flexible capital structure. Maintaining a strong capital structure that protects our balance sheet and liquidity remains central to our business strategy. We believe our cash, internally generated cash flows, borrowing capacity, non-core asset sales and access to capital markets will provide us with sufficient liquidity to execute our current capital program and strategy. We do not have significant near-term debt maturities. Our 2019 capital expenditure budget for acquisition, exploration and 7


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    development activities will be a range of $275 million to $300 million. To preserve or enhance liquidity, we may adjust our capital investment program throughout the year. Efficiently develop our STACK leasehold position / resource play. We are developing our acreage position to maximize the value of our resource potential, while maintaining flexibility to preserve future value when oil prices are low. Our capital program is designed to allocate investments to projects that provide opportunities to exploit our large inventory of drilling locations, convert our undeveloped acreage to acreage held by production, and improve hydrocarbon recoveries and rates of return on capital employed. Adopt and employ leading drilling and completion techniques. Our team is focused on enhancing our drilling and completion techniques to maximize overall well economics. We use an integrated workflow approach to optimize our STACK development combining expertise in geoscience and engineering. We have acquired over 600 square miles of high-fold 3D seismic data which we integrated with state-of-the-art logs, core data, well-completion and production histories to build a predictive 3D geologic “Earth Model” that describes in detail the subsurface from both a structural and reservoir perspective. Dynamic reservoir simulations from our Earth Model yield us a better understanding of the complexities of our multi-zone stacked resource. During the planning stage, Earth Model reservoir quality volume and stimulated rock volume are utilized to optimize well locations, lateral lengths and placement, hydraulic fracturing design and well spacing. We utilize real-time geo-steering of the horizontal laterals to stay in the zone defined by our Earth Model to reach the ideal planned landing point. Our completions are designed to maximize near well-bore complexity, optimize cluster spacing and strategically utilize diverter. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. We expect that this continuous improvement process allows us to enhance our initial production rates, increase ultimate recovery factors, lower well capital costs and improve rates of return on invested capital. Continuously improving operations and returns. Managing the costs to find, develop and produce oil, natural gas and NGLs is critical to delivering returns on capital employed and creating stockholder value. Our focus areas in the STACK are characterized by large, contiguous acreage positions and multiple stacked geologic horizons. Building on historical progress, we continue to preserve or improve on efficiency gains in various aspects of our business, with a focus on reducing drilling times and costs in our STACK Area. In addition to lowering our drilling costs, we also work to optimize cash flows using enhanced completion technologies that we believe will help improve recoveries and rates of returns. Stabilizing cash flow and managing risk exposure for a substantial portion of production by hedging production. As appropriate, we enter into derivative contracts to mitigate a portion of the commodity price volatility inherent in the oil and natural gas industry. By increasing the predictability of cash inflows for a portion of the Company's future production, we are better able to mitigate funding risks for our development plans and lock in rates of return on our capital projects. While our commodity derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect a portion of our cash flows, borrowing base, and liquidity during periods of depressed commodity prices. We strive to scale our overall hedging position to be appropriate relative to our current and expected level of indebtedness and consistent with our goals of preserving balance sheet strength and liquidity, as well as our internal price view. Competitive strengths Management and technical teams with substantial technical and operational expertise. Our management and technical teams have significant industry experience. Our technical team has substantial experience and expertise in applying the most advanced technologies in unconventional resource play development to improve recoveries and rates of return, including 3-D seismic interpretation, horizontal drilling, comprehensive multi-stage hydraulic fracture stimulation programs and other exploration, production and processing technologies. We believe this technical expertise largely contributes to our management’s strong track record of successful exploration and development which has helped us continue our reserve and production growth through periods of commodity price pressure and cost inflation, and other challenging environments. We continually refine our drilling and completion techniques to deliver improved results across our properties. STACK Focus with Established Acreage Position in the Core of the Anadarko Basin. We believe we have assembled a substantial portfolio of Anadarko Basin properties that offers significant exploration and low-risk development opportunities, including highly attractive rates of return. As of December 31, 2018, we hold over 252,000 gross (131,000 net) acres in the core of the 8


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    STACK resource play. In addition, 73% of our net acreage position is held by production, and we operate or expect to operate approximately 70% of our STACK net acreage, which we believe gives us significant control over the pace of development and the ability to design a more efficient and profitable drilling program to maximize recovery of oil and natural gas. Based on our drilling and production results to date and offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core acreage. Multi-year Portfolio of Drilling and Development Opportunities. We have a significant inventory of drilling and development locations in our STACK resource play. Our acreage has multiple productive zones and we believe that our inventory of drilling locations will allow us to grow our reserves and production at attractive rates of return based on current expectations for commodity prices. We plan to drill and/or complete 60 to 70 gross operated wells with a working interest of approximately 70% - 80% in our STACK resource play in 2019. 2018 Highlights The following are material events in 2018 that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods. • Income. We reported net income of $33.4 million and basic earnings per share of $0.74. • Decreased LOE. Lease operating expenses ("LOE") declined 41% from the prior year to $54.2 million in 2018 primarily due the divestitures of our EOR assets in late 2017 and other non-core assets in 2018, which were assets characterized by higher operating costs compared to our STACK assets. Our lease operating expense per Boe of $7.24 in 2018 was 34% lower than the prior year. • Production. Production in our STACK play increased 52% from the prior year to 5,279 Mboe in 2018. Total Company production was 7,490 MBoe in 2018 which was 11% lower than the prior year as the loss of production from divesting our EOR and other non-core assets was only partially offset by the production increase from our STACK play. • Divestitures. We generated proceeds of $50.5 million from divestitures of non-core assets which included certain properties in the Oklahoma/Texas Panhandle and certain salt water disposal infrastructure assets. • Issuance of Senior Notes. On June 29, 2018, we completed our offering of $300.0 million of senior unsecured notes due 2023 which provided net proceeds, after deducting estimated issuance costs, of $292.7 million. Upon receipt of the offering proceeds, we repaid the entire outstanding balance on our New Credit Facility with the remaining proceeds used for general corporate purposes. • Uplisting. On July 24, 2018, we transferred our stock exchange listing for our Class A common stock from the OTCQB market to the New York Stock Exchange (the "NYSE") and began trading under the new ticker symbol “CHAP.” • Share conversion. On December 19, 2018, all outstanding shares of our Class B common stock converted into the same number of shares of Class A common stock. With the conversion, all our common stock is now traded on the NYSE. • Reserve growth. We increased year-end 2018 proved reserves to 94.8 MMBoe, an increase of 24% compared to year-end 2017 proved reserves. Our STACK proved reserves of 74.1 MBoe increased 24.7 MMBoe or approximately 50% compared to year-end 2017 proved reserves. • Amendment to New Credit Facility. On December 7, 2018, we amended our New Credit Facility. Provisions in the amendment included: (i) increasing the aggregate principal amount from $400 million to $750 million; (ii) increasing the borrowing base from $265 million to $325 million; (iii) decreasing the applicable margin on outstanding borrowings by 50 basis points and (iv) changing hedge capacity to 80% of internally forecasted production for the first 24 months. • Capital expenditure. Our oil and natural gas capital expenditures were $341.0 million in 2018 compared to $212.5 million in 2017. The increase in capital expenditure was primarily driven by an increase in the number of wells we drilled and in our leasehold acquisitions. Our 2018 capital activity was comprised of $194.7 million for drilling and completions and $111.4 million for acquisitions, which included $10.9 million in costs we recorded for non-monetary acreage trades. We deployed three rigs for the better part of 2018 but added a fourth rig in October 2018. See "Capital Program" in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report for details of our capital activity. 9


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    • Joint development agreement (“JDA”). We made substantial progress in 2018 towards completing our 30-well JDA program. During 2018, we drilled and completed 18 wells, completed one well drilled in the prior year and drilled five wells to be completed in 2019. As of December 31, 2018, we have eight wells to drill and/or complete in order to complete the JDA. Operational Areas The following tables present our production and proved reserves by our areas of operation. Our operational areas currently include the STACK and Other. Please see Item 8. Financial Statements and Supplementary Data of this report for the results of our operations and financial position. Quarter ended Twelve months ended Net production (Mboe) December 31, 2018 December 31, 2018 STACK: STACK - Kingfisher 514 2,194 STACK - Canadian 558 1,648 STACK - Garfield 405 1,183 STACK - Other 53 254 Total STACK 1,530 5,279 Other 464 2,211 Total 1,994 7,490 Proved reserves as of December 31, 2018 Natural PV-10 Oil Natural gas gas liquids Total Percent of value (MBbls) (MMcf) (MBbls) (MBoe) total MBoe ($MM) STACK STACK - Kingfisher 16,185 60,052 7,356 33,550 35% $ 271 STACK - Canadian 3,890 56,210 10,306 23,564 25% 161 STACK - Garfield 3,074 49,647 4,219 15,568 16% 80 STACK - Other 105 7,041 133 1,412 2% 4 Total STACK 23,254 172,950 22,014 74,094 78% 516 Other 9,043 47,268 3,793 20,713 22% 170 Total 32,297 220,218 25,807 94,807 100.0% 686 STACK Area The STACK is an acronym for Sooner Trend Anadarko Canadian Kingfisher which is indicative of a play area in the Anadarko Basin of Oklahoma which has been our predominant focus in recent years. It is a horizontal drilling play in an area with multiple productive reservoirs which had previously been drilled with vertical wells. It encompasses all or parts of Blaine, Canadian, Garfield, Kingfisher and Major counties in Oklahoma. Our STACK play’s borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations and includes the Woodford, Osage, Meramec, Oswego, and other intervals within the STACK Area. The organic-rich Woodford Shale is the primary source of hydrocarbon generation and migration into and present in the target reservoirs, which act as natural traps and conduits for the oil migration from the Woodford. These complex carbonate-silt-shale stratigraphic intervals have proven to be very conducive to horizontal drilling and completion techniques. The stacking of plays allows us to effectively recover oil and gas from multiple formations using pad drilling, well spacing techniques and other operational efficiencies, which result in significant cost savings, reduced environmental impacts and attractive rates of return. Our acreage is primarily in the “black oil” normal pressure window. As of December 31, 2018, we owned approximately 131,000 net surface acres in this play which includes 131 gross operated producing horizontal wells and ownership interests in an additional 329 gross horizontal producing wells operated by others. 10


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    Primarily as a result of our drilling activity, our production from this area increased to 5,279 MBoe in 2018 compared to 3,464 MBoe in 2017 and 2,723 MBoe in 2016. During 2018, we spent $194.7 million on drilling and completion activities in our STACK play where we drilled and/or participated in the drilling of 165 (37 net) horizontal wells. For 2019, our capital budget includes drilling and/or completing 60 to 70 gross operated wells, including eight remaining JDA wells, completing wells drilled in the prior year and participating in non-operated wells with a budget range of $228 million to $248 million. We made substantial progress in 2018 towards completing our 30-well JDA program centered in the STACK. During 2018, we drilled and completed 18 wells, completed one well drilled in the prior year and drilled five wells to be completed in 2019. As of December 31, 2018, we have eight wells remaining to drill and/or complete in 2019. Our drilling opportunities across the counties included within the STACK are described below: STACK – Kingfisher. As of December 31, 2018, we owned approximately 34,000 net acres in the STACK play located in Kingfisher County, Oklahoma of which substantially all were held by production. The productive reservoirs in this area are the Meramec, Osage and Oswego. Of the various Oklahoma counties encompassed by the STACK play, our historical drilling experience has been predominantly in Kingfisher County which included operating 64 gross (46 net) horizontal wells as of December 31, 2018. Including wells operated by others, we brought online 83 gross (13 net) wells in this county in 2018. For 2019, we plan to allocate approximately 20% of our operated drilling and completions capital to this area. STACK – Canadian. At December 31, 2018, we owned approximately 22,000 net acres in the STACK play located in Canadian County, Oklahoma of which substantially all were held by production. The productive reservoirs in this area are the Meramec and Woodford. Our STACK operations within this county include operating 29 gross (13 net) horizontal wells as of December 31, 2018. Including wells operated by others, we brought online 47 gross (9 net) wells in this county in 2018. For 2019, we plan to allocate approximately 60% of our operated drilling and completions capital to this area. STACK – Garfield. At December 31, 2018, we owned approximately 55,000 net acres in the STACK play located in Garfield County, Oklahoma of which approximately 38% is held by production. The productive reservoirs in this area are the Meramec and Osage. Our STACK operations within this county include operating 34 gross (26 net) horizontal wells as of December 31, 2018. Including wells operated by others, we brought online 27 gross (14 net) wells in this county in 2018. For 2019, we plan to allocate approximately 20% of our operated drilling and completions capital to this area. STACK – Other. We include our STACK assets dispersed across Major, Blaine, Dewey, and Woodward counties, Oklahoma, within this category. The majority of our leasehold is held by production. As a result of the recent increase in seismic activity, the Oklahoma Corporation Commission (the “OCC”) issued multiple directives to operators of salt water disposal wells to reduce water injection volumes in various “areas of interest.” These areas include those in central Oklahoma that encompass our STACK play. However, these directives have not significantly impacted our operations in the STACK at this time. Please see “Studies by both state and federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens” in Item 1A. Risk Factors of this report for a further discussion of the OCC seismic-related directives. During 2018, we incurred $111.4 million in acquisitions which included approximately 24,600 acres acquired through leasing and pooling and $7.7 million in expenditures on seismic data. The amount above includes the closing payment of $54.8 million in January 2018 on our 7,000 acre leasehold purchase in Kingfisher County, Oklahoma as well as $10.9 million in costs we recorded for non-monetary acreage trades. Our 2019 capital budget allocates between $12.5 million and $17.5 million for additional acquisitions in the STACK Area. 11


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    EOR Areas We divested these assets in late 2017 although our operating results in this area are included in this report for comparative purposes. Our prior EOR activities encompassed the North Burbank Unit located in northeastern Oklahoma (Osage County, Oklahoma) and several other units located in the Panhandle. The CO2 required to operate these units was sourced from supply agreements with nearby ethanol and fertilizer plants and delivered to our field locations via CO2 pipelines built and operated by us. Other Areas With our focus on being a STACK operator, our footprint outside the STACK continues to diminish. During 2018, our divestitures included certain properties in the Oklahoma/Texas Panhandle and various other non-core assets located throughout our Other Areas. Our properties in these areas are mature fields that require low maintenance capital. We deploy the free cash flow from these properties to expand our development activities in the STACK. Our leasehold in this area is less attractive for drilling in the current price environment compared to our STACK play and therefore we have not expended any significant capital to these areas in recent years nor do we intend to in 2019. Due to our asset sales and because we have not focused our capital spending in these areas in recent years, production has declined from 4,135 MBoe in 2016 to 3,173 MBoe in 2017 and 2,211 MBoe in 2018. Oil and Natural Gas Reserves Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and exclude escalations based upon future conditions. Our policies regarding internal controls over the recording of reserves are structured to objectively estimate our oil and natural gas reserve quantities and values in compliance with SEC regulations. Users of this information should be aware that the process of estimating quantities of crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. The estimates of oil, natural gas and NGL reserves in this report are based on reserve reports, all of which are currently prepared by independent petroleum engineers. To achieve reasonable certainty, our engineers relied on an analysis and reporting software system designed specifically for reserves management that has been demonstrated to yield results with consistency and repeatability. Technical and economic data used include, but are not limited to, updated production data, well performance, formation logs, geological maps, reservoir pressure tests, and wellbore mechanical integrity information. Our Vice President - Completions & Operations is the technical person primarily accountable for overseeing the preparation of our reserve estimates as of December 31, 2018. He holds a Bachelor of Science degree in petroleum engineering and a Masters in Business Administration with 18 years of industry experience that includes diverse petroleum engineering roles. Our Corporate Reserves engineers continually monitor asset performance in collaboration with our other reservoir engineers, making reserve estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Technical reviews are performed throughout the year by our geologic and engineering staff who evaluate pertinent geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of proved reserve quantities. 12


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    We have internal guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserves. Internal controls within the reserve estimation process include: • The Corporate Reserve team follows comprehensive SEC-compliant internal policies to determine and report proved reserves including: • confirming that reserves estimates include all properties owned and are based upon proper working and net revenue interests; • reviewing and using in the estimation process data provided by other departments within the Company such as Accounting; and • comparing and reconciling internally generated reserves estimates to those prepared by third parties. • The Corporate Reserve team reports directly to our Chief Executive Officer regarding publicly disclosed reserve estimates. • Our reserves are reviewed by senior management, which includes the Chief Executive Officer and the Chief Financial Officer, and they are responsible for verifying that the estimate of proved reserves is reasonable, complete, and accurate. Members of senior management may also meet with the key representatives from the independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc. to discuss their processes and findings. In addition, the audit committee of our board of directors (the “Board”) also meets with Cawley, Gillespie & Associates, Inc. to review their findings. Final approval of the reserves is required by our Chief Executive Officer and Chief Financial Officer. Our Corporate Reserve team works closely with the independent petroleum consultants to ensure the integrity, accuracy and timeliness of annual independent reserve estimates. Our internal reserve data is provided each year to the independent petroleum engineering firm of Cawley, Gillespie & Associates, Inc. who prepares reserve estimates for all of our proved reserves using their own engineering assumptions and the economic data which we provide (prior to the sale of our EOR assets, we also utilized Ryder Scott Company, L.P. to estimate reserves for the divested assets). The person responsible for overseeing the preparation of our reserve estimates at Cawley, Gillespie & Associates, Inc. is a registered Professional Engineer with more than 21 years of petroleum consulting experience. Copies of the summary reserve reports prepared by these independent reserve engineers are attached as exhibits 99.1 to this annual report. The table below shows the percentage of the PV-10 value of our total proved reserves of oil, natural gas and NGLs prepared by each of our independent petroleum consultants for the years shown. December 31, 2018 2017 2016 Cawley, Gillespie & Associates, Inc. 100% 100% 51% Ryder Scott Company, L.P. —% —% 49% 13


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    Proved Reserves The following table summarizes our estimates of net proved oil and natural gas reserves, estimated future net revenues from proved reserves, the PV-10 value, the standardized measure of discounted future net cash flows, and the prices used in projecting those measures over the past three years. All of our reserves are located in the United States. We set forth our definition of PV-10 value (a non-GAAP measure) in the Glossary of Certain Defined Terms at the beginning of this annual report and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value below under “Non-GAAP Financial Measures and Reconciliations.” As of December 31, 2018 2017 2016 Estimated proved reserve volumes: Oil (MBbls) 32,297 29,604 96,621 Natural gas (MMcf) 220,218 170,166 135,449 Natural gas liquids (MBbls) 25,807 18,322 12,105 Oil equivalent (MBoe) 94,807 76,287 131,301 Proved developed reserve percentage 59% 67% 43% Estimated proved reserve values (in thousands): Future net revenue $ 1,618,480 $ 1,095,732 $ 1,490,090 PV-10 value $ 686,366 $ 497,873 $ 528,781 Standardized measure of discounted future net cash flows $ 686,366 $ 497,873 $ 528,781 Oil and natural gas prices: (1) Oil (per Bbl) $ 65.56 $ 51.34 $ 42.75 Natural gas (per Mcf) $ 3.10 $ 2.98 $ 2.49 Natural gas liquids (per Bbl) $ 25.56 $ 24.17 $ 13.47 Estimated reserve life in years (2) 12.7 11.5 14.7 _____________________________________ (1) Prices were based upon the average first day of the month prices for each month during the respective year and do not reflect differentials. (2) Calculated by dividing net proved reserves by net production volumes for the year indicated. The 2017 amount disclosed above excludes production from our EOR Areas as those assets have been sold. Our net proved oil and natural gas reserves and PV-10 values consisted of the following: Net proved reserves as of December 31, 2018 Oil Natural gas Natural gas Total PV-10 value (MBbls) (MMcf) liquids (MBbls) (MBoe) (in thousands) Developed—producing 17,329 131,305 14,361 53,574 $ 509,691 Developed—non-producing 722 4,120 485 1,894 22,595 Undeveloped 14,246 84,793 10,961 39,339 154,080 Total proved 32,297 220,218 25,807 94,807 686,366 14


  • Page 25

    Proved Undeveloped Reserves The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2018: (in MBoe) Total Proved undeveloped reserves as of January 1, 2018 25,553 Undeveloped reserves transferred to developed (1) (248) Sales of minerals in place — Extensions and discoveries 14,533 Revisions and other (499) Proved undeveloped reserves as of December 31, 2018 39,339 (1) Approximately $6.3 million of developmental costs incurred during 2018 related to undeveloped reserves that were transferred to developed. Productive Wells The following table sets forth the number of productive wells in which we have a working interest and the number of wells we operated as of December 31, 2018, by area. Productive wells consist of producing wells and wells capable of producing. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Gross wells is the total number of producing wells in which we have a working interest, and net wells is the sum of our working interest in all producing wells. Oil Natural Gas Total Gross Net Gross Net Gross Net Operated Wells: STACK (1) 183 136 102 74 285 210 Other 432 363 119 88 551 451 Total 615 499 221 162 836 661 Non-Operated Wells: STACK 412 27 312 35 724 62 Other 845 92 401 31 1,246 123 Total 1,257 119 713 66 1,970 185 Total Wells: STACK 595 163 414 109 1,009 272 Other 1,277 455 520 119 1,797 574 Total 1,872 618 934 228 2,806 846 (1) Within the STACK, we have 120 gross (85 net) operated horizontal oil wells and 11 gross (4 net) operated horizontal natural gas wells. 15


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    Drilling Activity The following table sets forth information with respect to wells drilled and completed during the periods indicated. Development wells are wells drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return. 2018 2017 2016 Gross Net Gross Net Gross Net Development wells Productive 159 33 127 27 20 12 Dry 1 — — — — — Exploratory wells Productive 9 4 5 1 32 4 Dry — — — — — — Total wells Productive 168 37 132 28 52 16 Dry 1 — — — — — Total 169 37 132 28 52 16 Percent productive 99% 100% 100% 100% 100% 100% As of December 31, 2018, we had 12 gross operated wells drilled and awaiting completion in 2019. Included in these wells were five wells under our JDA. Developed and Undeveloped Acreage The following table sets forth our gross and net interest in developed and undeveloped acreage as of December 31, 2018, by state. This does not include acreage in which we hold only royalty interests. Developed Undeveloped Total Gross Net Gross Net Gross Net Oklahoma: Kingfisher County 57,219 32,846 4,179 789 61,398 33,635 Canadian County 56,132 21,986 2,138 199 58,270 22,185 Garfield County 35,440 24,773 45,601 34,762 81,041 59,535 Other 281,042 129,457 3,479 403 284,521 129,860 Texas 21,343 13,382 120 120 21,463 13,502 Other 2,484 1,609 — — 2,484 1,609 Total 453,660 224,053 55,517 36,273 509,177 260,326 16


  • Page 27

    Many of our leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage is established prior to such date, in which event the lease will remain in effect until production has ceased. The following table sets forth as of December 31, 2018 the expiration periods and net acres that are subject to leases in the undeveloped acreage summarized in the above table. Acres Expiring During The Year Ending December 31, Location 2019 2020 2021 2022 2023 Total Oklahoma: Kingfisher County - gross 755 925 2,339 — 160 4,179 Kingfisher County - net 350 407 32 — — 789 Canadian County - gross 790 732 616 — — 2,138 Canadian County - net 103 22 74 — — 199 Garfield County - gross 16,545 14,828 7,179 7,047 2 45,601 Garfield County - net 12,981 11,654 5,722 4,399 6 34,762 Other - gross 2,141 1,338 — — — 3,479 Other - net 234 169 — — — 403 Texas - gross — 120 — — — 120 Texas - net — 120 — — — 120 Property Acquisition, Development and Exploration Costs The following tables summarize our costs incurred for oil and natural gas properties and our reserve replacement ratio: Twelve Months Ended December 31, 2018 (in thousands) STACK Other Total Acquisitions (1) $ 111,384 $ — $ 111,384 Drilling (2) 194,682 — 194,682 Enhancements 4,804 6,248 11,052 Operational capital expenditures incurred 310,870 6,248 $ 317,118 Other (3) — — $ 23,900 Total capital expenditures incurred $ 310,870 $ 6,248 $ 341,018 _________________________________ (1) Includes non-monetary acreage trades of $10.9 million. (2) Includes $38.0 million on development of wells operated by others and $30.4 million on our joint development agreement (see discussion below). (3) This amount includes $10.7 million for capitalized general and administrative expenses, $10.9 million for capitalized interest and $2.3 million on asset retirement obligations for future plugging and abandonment. For a discussion of the costs incurred in oil and natural gas producing activities for each of the last three years, please see “Note 18—Oil and natural gas activities (unaudited)” in Item 8. Financial Statements and Supplementary Data of this report. Our reserve replacement ratio is calculated below by dividing the sum of reserve additions (from purchases of minerals in place, extensions and discoveries, and improved recoveries) by the production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table located in "Note 19—Disclosures about oil and natural gas activities (unaudited)” in Item 8. Financial Statements and Supplementary Data of this report. Management uses the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow reserves, thereby providing some information of the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. 17


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    The reserve replacement ratio is comprised of the following: Year ended December 31, 2018 (2) 2017 (1) 2016 Reserves Percent of Reserves Percent of Reserves Percent of replaced total replaced total replaced total Purchases of minerals in place —% —% —% —% —% —% Extensions and discoveries 366% 100.0% 251% 100.0% 96% 100.0% Improved recoveries —% —% —% —% —% —% Total reserve replacement ratio 366% 100.0% 251% 100.0% 96% 100.0% _________________________________________________ (1) The denominator in calculating the 2017 ratio includes production from our EOR Areas, which has since been divested. Excluding production from our EOR Areas, the reserve replacement ratio in 2017 would have been 317%. (2) Our STACK Area reserve replacement ratio for 2018 was 519%. Production and Price History The following table sets forth certain information regarding our historical net production volumes, average prices realized and production costs associated with sales of oil and natural gas for the periods indicated. Successor Predecessor Period from Period from Period from Period from January 1, 2018 March 22, 2017 January 1, 2017 January 1, 2016 through through through through December 31, 2018 December 31, 2017 March 21, 2017 December 31, 2016 Production: Oil (MBbls) 2,684 3,535 1,036 4,870 Natural gas (MMcf) 17,549 11,552 3,046 15,889 Natural gas liquids (MBbls) 1,881 1,143 252 1,408 Combined (MBoe) 7,490 6,603 1,796 8,926 Average daily production: Oil (Bbls) 7,354 12,404 12,950 13,306 Natural gas (Mcf) 48,078 40,533 38,075 43,413 Natural gas liquids (MBbls) 5,153 4,011 3,150 3,847 Combined (Boe) 20,520 23,171 22,446 24,388 Average prices (excluding derivative settlements): Oil (per Bbl) $ 63.99 $ 48.40 $ 50.05 $ 40.38 Natural gas (per Mcf) $ 2.37 $ 2.55 $ 3.00 $ 2.16 Natural gas liquids (per Bbl) $ 24.24 $ 22.69 $ 22.00 $ 15.00 Transportation and processing (per Boe) (1) $ (2.17) $ — $ — $ — Combined (per Boe) $ 32.39 $ 34.30 $ 37.04 $ 28.25 Average costs per Boe: Lease operating expenses $ 7.24 $ 10.92 $ 11.10 $ 10.14 Transportation and processing (1) $ — $ 1.44 $ 1.13 $ 0.99 Production taxes $ 1.76 $ 1.78 $ 1.35 $ 1.08 Depreciation, depletion, and amortization $ 11.74 $ 14.03 $ 13.87 $ 13.77 General and administrative $ 5.18 $ 6.00 $ 3.81 $ 2.35 _______________________________________________ (1) Transportation and processing costs are reclassified from expense to a revenue deduction beginning in 2018 pursuant to new accounting guidance. 18


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    The following table sets forth certain information specific to our STACK play: Successor Predecessor Period from Period from Period from Period from January 1, 2018 March 22, 2017 January 1, 2017 January 1, 2016 through through through through December 31, 2018 December 31, 2017 March 21, 2017 December 31, 2016 STACK Play Production: Oil (MBbls) 1,857 1,195 293 1,123 Natural gas (MMcf) 12,245 5,892 1,480 6,248 Natural gas liquids (MBbls) 1,381 631 116 559 Combined (MBoe) 5,279 2,808 656 2,723 Average daily production: Oil (Bbls) 5,088 4,193 3,663 3,068 Natural gas (Mcf) 33,548 20,674 18,500 17,071 Natural gas liquids (MBbls) 3,784 2,214 1,450 1,527 Combined (Boe) 14,463 9,853 8,196 7,440 Average prices (excluding derivative settlements): Oil (per Bbl) $ 64.12 $ 49.05 $ 49.67 $ 40.81 Natural gas (per Mcf) $ 2.38 $ 2.58 $ 2.99 $ 2.23 Natural gas liquids (per Bbl) $ 24.39 $ 23.52 $ 23.83 $ 15.77 Transportation and processing (per Boe) (1) $ (2.51) $ — $ — $ — Combined (per Boe) $ 31.95 $ 31.57 $ 33.16 $ 25.18 Average costs per Boe: Lease operating expenses $ 4.86 $ 4.52 $ 3.43 $ 3.82 Transportation and processing (1) $ — $ 2.46 $ 2.29 $ 1.80 Production taxes $ 1.49 $ 1.08 $ 0.78 $ 0.48 _______________________________________________ (1) Transportation and processing costs are reclassified from expense to a revenue deduction beginning in 2018 pursuant to new accounting guidance. Non-GAAP Financial Measures and Reconciliations PV-10 value is a non-GAAP measure that differs from the standardized measure of discounted future net cash flows in that PV- 10 value is a pre-tax number, while the standardized measure of discounted future net cash flows is an after-tax number. We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. The decline in PV-10 and standardized measure of discounted future net cash flows from 2016 to 2017 is primarily due to the loss of reserves due to the conveyance of our EOR assets sold in November 2017. The increase in PV-10 and standardized measure of discounted future net cash flows from 2017 to 2018 is primarily due to extension of and discoveries from our drilling activity and an increase in the SEC commodity price utilized to estimate reserves. 19


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    The following table provides a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows for the periods shown: As of December 31, (in thousands) 2018 2017 2016 Standardized measure of discounted future net cash flows $ 686,366 $ 497,873 $ 528,781 Present value of future income tax discounted at 10% (1) — — — PV-10 value $ 686,366 $ 497,873 $ 528,781 ________________________________________ (1) As a result of the magnitude of its loss carryforwards and its tax basis in oil and gas properties, the Company does not expect to incur income taxes on its current estimate of net revenues from future production. Management uses adjusted EBITDA (as defined below) as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the EBITDAX calculation that is used in the covenant ratio required under our Prior Credit Facility and our New Credit Facility, described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” We consider compliance with this covenant to be material. The calculation of EBITDAX includes pro forma adjustments for property acquisitions and dispositions, and as a result of these adjustments, our EBITDAX as calculated for covenant compliance purposes is lower than our adjusted EBITDA disclosed below for the year ended December 31, 2018. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies. 20


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    We define adjusted EBITDA as net income, adjusted to exclude (1) asset impairments, (2) interest and other financing costs, net of capitalized interest, (3) income taxes, (4) depreciation, depletion and amortization, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, (9) upfront premiums paid on settled derivative contracts, (10) impairment charges, (11) other significant, unusual non-cash charges, (12) proceeds from any early monetization of derivative contracts with a scheduled maturity date more than 12 months following the date of such monetization—this exclusion is consistent with our prior treatment, for EBITDA reporting, of any large monetization of derivative contracts and (13) certain expenses related to our restructuring, cost reduction initiatives, reorganization and fresh start accounting activities which our lenders have permitted us to exclude when calculating covenant compliance. The following table provides a reconciliation of net income to adjusted EBITDA for the specific periods: Successor Predecessor Period from Period from Period from Period from January 1, 2018 March 22, 2017 January 1, 2017 January 1, 2016 through through through through (in thousands) December 31, 2018 December 31, 2017 March 21, 2017 December 31, 2016 Net income (loss) $ 33,442 $ (118,902) $ 1,041,959 $ (415,720) Interest expense 11,383 14,147 5,862 64,242 Income tax (benefit) expense (77) (349) 37 (102) Depreciation, depletion, and amortization 87,888 92,599 24,915 122,928 Non-cash change in fair value of non- hedge derivative instruments (37,807) 46,478 (46,721) 176,607 Impact of derivative repricing (5,649) — — — Loss (gain) on settlement of liabilities subject to compromise 48 — (372,093) — Fresh start accounting adjustments — — (641,684) — Upfront premiums paid on settled derivative contracts — — — (20,608) Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date excluded from — — — (12,810) EBITDA Interest income (12) (21) (133) (188) Stock-based compensation expense 10,873 9,833 155 (5,238) Loss (gain) on sale of assets 2,582 25,996 (206) 117 Loss on extinguishment of debt — 635 — — Write-off of debt issuance costs, discount and premium — — 1,687 16,970 Loss on impairment of assets 20,065 42,325 — 282,472 Restructuring, reorganization and other 2,344 7,313 24,297 19,599 Adjusted EBITDA $ 125,080 $ 120,054 $ 38,075 $ 228,269 Competition The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural gas companies in acquiring properties, contracting for drilling equipment and securing trained personnel. There is also substantial competition for capital available for investment in the crude oil and natural gas industry. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. 21


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    As commodity prices strengthened from the lows of 2016, the demand for oilfield equipment, services and infrastructure began to rise, leading to cost inflation for the drilling, completion and operating of wells, and for the construction and access to necessary oil and gas infrastructure. As a result, during 2018 there was pressure on operating margins and capital efficiency in U.S. onshore regions, including those in which we operate. With the recent crude oil price decline from mid-2018 highs, the development and operating cost structure has begun to shift downward, and with stable prices, we expect the potential for lower costs will continue into 2019. Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition of producing properties. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions economically in a highly competitive environment. Stockholders Agreement On March 21, 2017, we entered into a Stockholders Agreement with the holders of our common stock named therein to provide for certain general rights and restrictions for holders of common stock. These included: • restrictions on the authority of the Board to take certain actions, including but not limited to entering into (i) a merger, consolidation, or sale of all or substantially all of the Company’s assets; (ii) an acquisition outside the ordinary course of business or exceeding $125 million; (iii) an amendment, waiver or modification of the charter documents of the Company; (iv) an incurrence of new indebtedness that would result in the aggregate indebtedness of the Company exceeding $650 million; and (v) with certain exceptions, an initial public offering on or prior to December 15, 2018; in each case without the approval of holders of at least two-thirds of the Company’s outstanding common stock; • restrictions on the authority of the Board to enter into or terminate affiliate transactions without the approval of a majority of disinterested members of the Board; • pre-emptive rights granted to holders of at least 0.5% of the Company’s outstanding common stock, allowing those holders to purchase their pro rata share of any issuances or distributions of new securities by the Company; • informational rights; • registration rights as described in the Registration Rights Agreement; and • drag along and tag along rights. On March 6, 2018, we held a special meeting of Stockholders where the Stockholders approved and adopted an amendment to the Stockholders Agreement which (i) removed the restriction on the Company’s ability to become subject to Section 13 of the Securities Exchange Act of 1934, as amended, on or prior to December 15, 2018 without the affirmative approval of the holders of two-thirds of the Company’s outstanding common stock and (ii) eliminated preemptive rights currently existing under the Stockholders Agreement which would be applicable to the issuance or sale of Company securities pursuant to a private placement or other transaction exempt from or not subject to the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"), to the extent such transaction does not result in the issuance of more than 100,000 shares of the Company’s common stock and does not result in more than 100 new holders of the Company’s common stock. On July 24, 2018, shares of Class A common stock, par value $0.01 per share, of the Company commenced trading on the New York Stock Exchange (the “Uplisting”). In connection with the Uplisting, the Stockholders Agreement terminated pursuant to its terms. Registration Rights Agreement On March 21, 2017, we entered into a Registration Rights Agreement with certain holders of our common stock. The Registration Rights Agreement provides resale registration rights for the holders’ Registrable Securities (as defined in the Registration Rights Agreement). 22


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    Pursuant to the Registration Rights Agreement, the holders have customary underwritten offering and piggyback registration rights, subject to the limitations set forth therein. Under their underwritten offering registration rights, one or more holders holding, collectively, at least 20% of the aggregate number of Registrable Securities have the right to demand that the Company file a registration statement with the SEC, and further have the right to demand that the Company effectuate the distribution of any or all of such holders’ Registrable Securities by means of an underwritten offering pursuant to an effective registration statement, subject to certain limitations described in the Registration Rights Agreement. The holders’ piggyback registration rights provide that, if at any time the Company proposes to undertake a registered offering of Common Stock, whether or not for its own account, the Company must give at least 20 business days’ notice to all holders of Registrable Securities to allow them to include a specified number of their shares in the offering. These registration rights are subject to certain conditions and limitations, including the Company’s right to delay or withdraw a registration statement under certain circumstances. The Company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether any Registrable Securities are sold pursuant to a registration statement. The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as blackout periods and, if an underwritten offering is contemplated, limitations on the number of shares to be included in the underwritten offering that may be imposed by the managing underwriter. Markets The marketing of oil and natural gas we produce will be affected by a number of factors that are beyond our control and whose exact effect cannot be accurately predicted. These factors include: • the amount of crude oil and natural gas imports; • the availability, proximity and cost of adequate pipeline and other transportation facilities; • the actions taken by OPEC and other foreign oil and gas producing nations; • the impact of the U.S. dollar exchange rates on oil and natural gas prices; • the success of efforts to market competitive fuels, such as coal and nuclear energy and the growth and/or success of alternative energy sources such as wind power; • the effect of Bureau of Indian Affairs and other federal and state regulation of production, refining, transportation and sales; • weather conditions and climate change; • the laws of foreign jurisdictions and the laws and regulations affecting foreign markets; • other matters affecting the availability of a ready market, such as fluctuating supply and demand; and • general economic conditions in the United States and around the world. The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated most trade and investment barriers between the United States, Canada and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before the Federal Energy Regulatory Commission (“FERC”), as well as nondiscriminatory access requirements, could further increase the availability of natural gas imports to certain United States markets. Such imports could have an adverse effect on both the price and volume of natural gas sales from our wells. Members of the OPEC establish prices and production quotas from time to time with the intent of managing the global supply and maintaining, lowering or increasing certain price levels. We are unable to predict what effect, if any, such actions will have on both the price and volume of crude oil sales from our wells. In several initiatives, FERC has required pipeline transportation companies to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi- national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated it will ultimately expand natural gas markets and improve their reliability. 23


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    Environmental Matters and Regulation We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities. General Our operations, like the operations of other companies in our industry, are subject to stringent federal, tribal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may: • require the acquisition of various permits before drilling commences; • require the installation of costly emission monitoring and/or pollution control equipment; • restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities; • require the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with our operations; • limit or prohibit drilling activities on lands lying within wilderness, wetlands, certain animal habitats and other protected areas; • restrict the construction and placement of wells and related facilities; • require remedial measures to address pollution from current or former operations, such as cleanup of releases, pit closure and plugging of abandoned wells; • impose substantial liabilities for pollution resulting from our operations; • with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement; and • impose safety and health standards for worker protection. These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible or economically desirable. The regulatory burden on the oil and natural gas industry increases the cost of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly permitting, pollution control, or waste handling, disposal and clean-up requirements for the oil and natural gas industry could significantly increase our operating costs. We routinely monitor our properties and operations in an effort to ensure that our properties and operations are, and remain, in substantial compliance with all current applicable environmental laws and regulations. If, at any time, we determine that our properties and/or operations do not substantially comply with all current applicable environmental laws and regulations, we take action to remedy such noncompliance on our own volition and do not delay taking action until ordered to do so by a regulatory authority. We cannot predict how future environmental laws and regulations may affect our properties or operations. For the years ended December 31, 2018, 2017 and 2016, we did not incur any material expenditures for the installation of remediation or pollution control equipment at any of our facilities or for the conduct of remedial or corrective actions. As of the date of this report, we are not aware of any other environmental issues or claims that will require material capital expenditures during 2019 or that will otherwise have a material impact on our financial position or results of operations. In March 2017, President Donald Trump issued an Executive Order titled “Promoting Energy Independence and Economic Growth” (the “March 2017 Executive Order”) which states it is in the national interest of the United States to promote clean and safe development of energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation. The March 2017 Executive Order requires, among other things, the executive department and agencies to review existing regulations that potentially burden the development or use of domestically produced energy resources (with particular attention to crude oil, natural gas, coal, and nuclear energy) and suspend, revise, or rescind those regulations that unduly burden the development of such resources beyond the degree necessary to protect the public interest or 24


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    otherwise comply with the law. In response to the March 2017 Executive Order, certain energy and climate-related regulations proposed or enacted under previous presidential administrations have been, or are in the process of being, reviewed, suspended, revised, or rescinded, some of which are described further below. Numerous regulations impacting the crude oil and natural gas industry are not expected to be impacted by the March 2017 Executive Order and will continue to be in effect. Additionally, undoing previously existing environmental regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further regulation of our industry may stall at the federal level under the March 2017 Executive Order, certain states and local governments have pursued additional regulation of our operations and other states and local governments may do so as well. Environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry include the following: Hazardous Substances and Wastes Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and non-hazardous wastes. Under the authorization and oversight of the federal Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. EPA also retains enforcement authority in any state-administered RCRA programs. Drilling fluids, produced waters, and many other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions. However, there is no guarantee that Congress, the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation under RCRA. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste, if they have hazardous characteristics. We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes as presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. Moreover, failure to comply with such waste handling requirements can result in the imposition of administrative, civil and criminal penalties. Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws, impose strict, and in certain circumstances joint and several liability, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Responsible parties include the current, as well as former, owner or operator of the site where the release occurred and persons that disposed or arranged for the disposal of the hazardous substance at the site, regardless of whether the disposal of hazardous substances was lawful at the time of the disposal. Under CERCLA, and analogous state laws, such persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and certain health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Crude oil and fractions of crude oil are excluded from regulation under CERCLA (often referred to as the “petroleum exclusion”). Nevertheless, many chemicals commonly used at oil and gas production facilities fall outside of the CERCLA petroleum exclusion. We currently own, lease, or operate numerous properties that have produced oil and natural gas for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under, or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA, analogous state laws or common law requirements. Under such laws, we could be required to investigate 25


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    the nature and extent of contamination, remove previously disposed substances and wastes, remediate contaminated soil or groundwater, or perform remedial plugging or pit closure operations to prevent future contamination. NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials, or NORM, associated with oil and gas deposits and, accordingly, may result in the generation of wastes and other materials containing NORM. NORM exhibiting levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work areas affected by NORM may be subject to remediation or restoration requirements. Water Discharges Clean Water Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. In May 2015, EPA and the U.S. Army Corps of Engineers jointly announced a final rule defining the “Waters of the United States” (“WOTUS”) which are protected under the Clean Water Act. The new rule which would have made additional waters expressly Waters of the United States and therefore subject to the jurisdiction of the Clean Water Act, rather than subject to a case-specific evaluation, was stayed by the U.S. Court of Appeals for the Sixth Circuit before it took effect. In February 2018, EPA officially delayed implementation of the 2015 rule until early 2020, and in July 2018, the EPA proposed repeal of the 2015 WOTUS rule. Later that year, EPA’s decision was challenged in court, which resulted in a decision by the U.S. District Court for the District of South Carolina to enjoin EPA’s February 2018 delay rule. Several states then acted to halt reinstatement of the 2015 WOTUS rule, the effect of all of which is that the 2015 WOTUS definition is currently in effect in 22 states. Then in December 2018, the EPA and the U.S. Army Corps of Engineers issued a proposed rule to revise the definition of “Waters of the United States.” The proposed rule would narrow the definition, excluding, for example, streams that do not flow year-round and wetlands without a direct surface connection to other jurisdictional waters. Litigation by parties opposing the rule quickly followed. Due to the administrative procedures required to establish the rule and pending litigation, the new definition of “Waters of the United States” may not be implemented, if at all, for several years. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. Issues pertaining to wastewater generated by oil and natural gas exploration and production activities are drawing increased scrutiny from state legislators and may lead to additional regulations. We believe we are in substantial compliance with the requirements of the Clean Water Act. Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) establishes strict, joint and several liability for owners and operators of facilities that release oil into waters of the United States. The OPA and its associated regulations impose a number of requirements on responsible parties related to the prevention of spills and liability for damages, including natural resource damages, resulting therefrom. A “responsible party” under OPA includes owners and operators of certain facilities from which a spill may affect Waters of the United States. For example, spill prevention, control, and countermeasure regulations promulgated under the Clean Water Act, and later amended by the Oil Pollution Act, impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines. Owners and operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach waters regulated under the Clean Water Act, must develop, implement, and maintain Spill Prevention, Control, and Countermeasure Plans. 26


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    Disposal Wells The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. EPA directly administers the UIC program in some states and in others administration is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. Because some states have become concerned that the disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding such disposal methods. For example, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division and the Oklahoma Geologic Survey continues to release well completion seismicity guidance, which most recently directs operators to adopt a seismicity response plan and take certain prescriptive actions, including mitigation, following anomalous seismic activity within 3.1 miles of hydraulic fracturing operations. In addition, since 2015, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has issued a number of directives restricting the future volume of wastewater disposed of via subsurface injection and directing the shut in of certain injection wells, including in areas where we operate. In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the Clean Water Act if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019, Those petitions are currently pending. EPA has also brought attention to the reach of the Clean Water Act’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the Clean Water Act permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. To date, no further action has been taken by EPA with respect to the issue, but should Clean Water Act permitting be required for saltwater injections wells, the costs of permitting and compliance for our operations could increase. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA, potentially the Clean Water Act, and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. Hydraulic Fracturing We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Congress has previously considered legislation to amend the federal SDWA to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of bills previously proposed before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Such proposed legislation, which has been introduced in various forms to each session of Congress since 2009, would require the reporting and public disclosure of chemicals used in the fracturing process, which is already required by some state agencies governing our operations, including the Oklahoma Corporation Commission and the Railroad Commission of Texas. Such disclosure requirements could make it easier for third parties opposing the use of hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could repeal the exemptions for hydraulic fracturing from the SDWA. These federal legislative efforts slowed while EPA studied the issue of hydraulic fracturing. In 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water, as well as review the application of other environmental statutes to hydraulic fracturing activities, including RCRA and the Clean Water Act. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing fluid and providing a comprehensive list of chemicals identified in fracturing fluid and flowback/produced water. EPA completed the study of the potential impacts of hydraulic fracturing activities on water resources and published its final 27


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    assessment in December 2016. In its assessment, the EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances. The results of the study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. A number of states and communities are currently considering legislation to ban or restrict hydraulic fracturing. On March 20, 2015, the United States Bureau of Land Management (“BLM”) released its new regulations governing hydraulic fracturing operations on federal and Indian lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule in June 2016, but the U.S. Court of Appeals for the Tenth Circuit (the "Tenth Circuit") later lifted the lower court’s stay on the basis that the BLM had proposed to rescind the rule in June 2017. In December of 2017, the BLM repealed the 2015 regulations, and environmental organizations and the State of California are suing the BLM and the Secretary of the U.S. Department of the Interior over the repeal. The regulations, if reinstated, may result in additional levels of regulation or complexity with respect to existing regulations that could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. The Clean Air Act. The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements, such as emission controls. In addition, EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. On August 16, 2012, EPA promulgated new CAA regulations addressing criteria pollutants, “Oil and Natural Gas Sector: New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”).” These new rules broadened the scope of EPA’s NSPS and NESHAP to include standards governing emissions from most operations associated with oil and natural gas production facilities and natural gas processing, transmission and storage facilities with a compliance deadline of January 1, 2015. EPA states that greenhouse gases will be controlled indirectly as a result of these new rules. EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In December 2014, EPA released final updates and clarifications to the Oil and Natural Gas Sector NSPS that, among other things, distinguishes between multiple flowback stages during completion of hydraulically fractured wells and clarified that storage tanks removed from service are not affected by any requirements. On May 12, 2016, EPA issued additional rules, known as “NSPS Subpart OOOOa,” for the oil and gas industry to reduce emissions of methane, volatile organic compounds (“VOCs”) and other compounds. These rules apply to certain sources of air emissions that were constructed, reconstructed, or modified after September 18, 2015. Among other things, the new rules impose reduced emission (“green”) completion requirements on new hydraulically fractured or re-fractured oil wells (in addition to gas wells, for which green completions were already required under a prior NSPS rule) and leak detection and repair requirements at well sites. NSPS Subpart OOOOa and EPA’s subsequent actions to reconsider and propose stays of the rules have been heavily litigated and, in October 2018, EPA released proposed revisions to some of the 2016 requirements, including reducing the required frequency of fugitive emissions monitoring at well sites and compressor stations. Accordingly, the ultimate scope of these regulations is uncertain, and any future changes to these regulations could require us to incur additional costs and to reduce emissions associated with our operations. Endangered Species The federal Endangered Species Act (“ESA”) and analogous state laws regulate a variety of activities that adversely affect species listed as threatened or endangered under the ESA or their habitats. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. For instance, the American Burying Beetle was listed as an endangered species by the U.S. Fish and Wildlife Service (“FWS”) in 1989. The FWS announced in November 2016 that it is considering listing the Lesser Prairie Chicken as threatened under the ESA. The FWS completed an assessment of the biological status of the species in August, 2017, but has not taken any further action on listing the species. Both the American Burying Beetle and the Lesser Prairie Chicken have habitat in some areas where we operate. Although we are participants in a conservation agreement overseen by the FWS which may mitigate our exposure if the Lesser Prairie Chicken is listed as threatened, the presence of these and other protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence 28


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    drilling operations, cause us to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations and financial position. Climate Change The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of greenhouse gases that are suspected of contributing to global warming. Although the United States was not a participant in the Kyoto Protocol, the United States was a signatory to the Paris Agreement, which became effective in November 2016. Following President Trump taking office, the United States informed the United Nations of its intent to withdraw from the Paris Agreement, although the earliest date of withdrawal under the terms of the Agreement is November 4, 2020. Historically, legislation has been proposed in Congress directed at reducing greenhouse gas (“GHG”) emissions, and such proposals would not be unexpected in the future. Regulation of GHGs has support in various regions of the country, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future federal or state restrictions on such emissions could impact our future operations. In 2010, the EPA enacted final rules on mandatory reporting of GHGs. The EPA has also subsequently issued amendments to the rules containing technical and clarifying changes to certain GHG reporting requirements. Under the GHG reporting rules, certain onshore oil and natural gas production, gathering and boosting, processing, transmission, storage and distribution facilities are required to report their GHG emissions on an annual basis. In June 2016, the EPA published final regulations (NSPS Subpart OOOOa) setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45% from 2012 levels by 2025. In November 2016, the BLM published a final version of its venting and flaring rule, which imposes stricter reporting obligations and limits venting and flaring of natural gas on public and Indian lands. Some provisions of the venting and flaring rule went into effect on January 17, 2017 and the BLM announced that it is postponing until January 17, 2019, the implementation of other aspects of the venting and flaring rule, which were originally scheduled to come into effect on January 17, 2018. In September 2018, however, the BLM announced a final rule that revises the 2016 rule. Not unexpectedly, this revised rule was immediately challenged and litigation is ongoing. Any rules regarding the reduction of GHGs that are applicable to our operations could require us to incur additional costs and to reduce emissions associated with our operations. In response to these regulations, or other future federal, state or regional legislation, our operating costs could increase due to requirements to (1) obtain permits; (2) operate and maintain equipment and facilities (e.g., through the reduction or elimination of venting and flaring of methane); (3) install new emission controls; (4) acquire allowances authorizing GHG emissions; (5) pay taxes related to our GHG emissions; and (6) administer and manage GHG emission programs. Although our operations are not adversely impacted by current state and local climate change initiatives, at this time it is not possible to accurately estimate how potential future laws or regulations limiting or otherwise addressing GHG emissions would impact our business. OSHA and Other Laws and Regulations We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the CAA, and similar state statutes require that we organize and/or disclose information about hazardous materials used, produced or otherwise managed in our operations. These laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants. Other Regulation of the Oil and Natural Gas Industry The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our 29


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    profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. It is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial. Drilling and Production Our operations are subject to various types of regulation at the federal, tribal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds, and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following: • the location of wells; • the method of drilling and casing wells; • the timing of construction or drilling activities; • the rates of production or “allowables”; • the use of surface or subsurface waters; • the surface use and restoration of properties upon which wells are drilled; • the plugging and abandoning of wells; • the transportation of production; and • notice to surface owners and other third parties. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction. National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands and some Indian lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Natural Gas Sales and Transportation Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. FERC also regulates interstate natural gas transportation rates and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rulemakings that significantly fostered competition in the business of transporting and marketing natural gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to 30


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    producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy natural gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. Under the NGA, the rates for service on interstate natural gas facilities must be just and reasonable and not unduly discriminatory. Generally, the maximum filed recourse rates for interstate pipelines are based on the pipeline’s cost of service including recovery of and a return on the pipeline’s actual prudent investment cost. Key determinants in the ratemaking process are costs of providing service, allowed rate of return, volume throughput and contractual capacity commitment assumptions. FERC also allows pipelines to charge market-based rates if the transportation market in question is sufficiently competitive. Section 1(b) of the NGA exempts natural gas gathering service, which occurs upstream of jurisdictional transmission services, from FERC jurisdiction. Gathering service is instead regulated by the states onshore and in state waters. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. In fact, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point-of-sale locations. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC. Natural Gas Pipeline Safety The Department of Transportation (“DOT”), and specifically the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), regulate transportation of natural and other gas by pipeline and impose minimum federal safety standards pursuant to the pipeline safety laws codified at 49 U.S.C. 60101, et seq., the hazardous material transportation laws codified at 49 U.S.C. 5101, et seq., regulations contained within 49 C.F.R. Parts 192 and 195, and similar state laws. Our natural gas and hazardous liquids pipelines are subject to this regulation. We believe we are in material compliance with all applicable regulations imposed by the DOT and PHMSA regarding our natural gas and hazardous liquids pipelines. However, significant expenses could be incurred in the future if additional safety measures are required, or if safety standards are raised and exceed the degree of our current natural gas pipeline operations. The DOT may also assess fines and penalties for violations of these and other requirements imposed by its regulations. Natural Gas Gathering Regulations State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements and complaint-based rate regulation. The regulations generally require gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. Such regulations can have the effect of imposing restrictions on a pipeline’s ability to decide with whom it contracts to gather natural gas. In addition, natural gas gathering is included in EPA’s greenhouse gas monitoring and reporting rule, is subject to air permitting requirements where applicable, and may receive greater regulatory scrutiny in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. State Regulation The various states regulate the drilling for, and the production, gathering, and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may 31


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    establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill. The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation, and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. Seasonality Seasonal weather conditions can limit our drilling and producing activities and other operations. These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may be impacted by ice and snow in the winter and by strong winds, tornadoes and high temperatures in the spring and summer. The demand for natural gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations. Legal Proceedings Please see Item 3. Legal Proceedings for a discussion of our material legal proceedings. In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows. Title to Properties We believe that we have satisfactory title to all of our owned assets. As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to undeveloped leasehold acreage rights acquired through oil and natural gas leases or farm-in agreements. Prior to the commencement of drilling operations on undeveloped leasehold, we conduct a title examination and perform curative work with respect to any significant title defects. Prior to completing an acquisition of an interest in significant producing oil and natural gas properties, we conduct due diligence as to title for the specific interest we are acquiring. Our interests in oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other similar burdens and minor easements, restrictions and encumbrances which we believe do not materially detract from the value of these interests either individually or in the aggregate and will not materially interfere with the operation of our business. We will take such steps as we deem necessary to ensure that our title to our properties is satisfactory. We are free, however, to exercise our judgment as to reasonable business risks in waiving title requirements. Employees As of December 31, 2018, we had 194 full-time employees. We also contract for the services of independent consultants involved in land, regulatory, accounting, finance and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory. During 2017 and 2016, we terminated 109 and 64 employees, respectively, as part of our workforce reduction or company restructuring. 32


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    Recent Developments On March 8, 2019, David Geenberg notified the Board of his intention to resign as a member of the Board effective March 11, 2019. On March 11, 2019, Graham Morris notified the Board of his intention to resign as a member of the Board effective March 11, 2019. Neither Mr. Geenberg’s nor Mr. Morris’s decision to resign is the result of any disagreement with the Company related to the Company’s operations, policies, or practices. Pursuant to the terms of the Company’s support agreement Strategic Value Partners, LLC (“SVP”) and certain funds and accounts managed by SVP, SVP has notified the Company that it will exercise its right to designate a replacement director to fill the vacancy resulting from Mr. Geenberg’s resignation, subject to approval by the Board. Available Information Our website is available at www.chaparralenergy.com. On our website, you can access, free of charge, electronic copies of our governance documents, including our Board’s Corporate Governance Guidelines and the charters of the committees of our Board, along with all of the documents that we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports. Information contained on or connected to our website is not incorporated by reference into this Annual Report and should not be considered part of this report or any other filing we make with the SEC. We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our reports filed with the SEC are made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov. ITEM 1A. RISK FACTORS The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation. Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Reorganization Plan and the transactions contemplated thereby and our adoption of fresh start accounting. In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Reorganization Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Reorganization Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. Although the financial projections disclosed in our disclosure statement filed with the Bankruptcy Court represented our view based on then current known facts and assumptions about the future operations of the Company there is no guarantee that the financial projections will be realized. We may not be able to meet the projected financial results or achieve projected revenues and cash flows assumed in projecting future business prospects. To the extent we do not meet the projected financial results or achieve projected revenues and cash flows, we may lack sufficient liquidity to continue operating as planned and may be unable to service our debt obligations as they come due or may not be able to meet our operational needs. Any one of these failures may preclude us from, among other things: (a) taking advantage of future opportunities; (b) growing our businesses; or (c) responding to future changes in the oil and gas industry. Further, our failure to meet the projected financial results or achieve projected revenues and cash flows could lead to cash flow and working capital constraints, which constraints may require us to seek additional working capital. We may not be able to obtain such working capital when it is required. In addition, upon our emergence from bankruptcy, we adopted fresh start accounting, as a consequence of which our assets and liabilities were adjusted to fair values and the opening balance of our accumulated deficit upon emergence from bankruptcy was restated 33


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    to zero. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in the Company’s historical financial statements. The ability to attract and retain key personnel is critical to the success of our business. Any difficulty we experience replacing or adding personnel could adversely affect our business. The success of our business depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity. Our ability to utilize our net operating loss carryforwards (“NOLs”) may be limited as a result of our emergence from bankruptcy and new limitations under the 2017 Tax Cuts and Jobs Act (the “2017 Tax Act”). In general, Section 382 of the Internal Revenue Code (“IRC”) of 1986, as amended, provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future taxable income in the event of a change in ownership. Our emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of the IRC Section 382. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the ownership change and cancellation of indebtedness income on its tax attributes. Upon filing its 2017 U.S. Federal income tax return, the Company elected an available alternative which would likely result in the Company experiencing a limitation that subjects existing tax attributes at emergence to an IRC Section 382 limitation that could result in some or all of the remaining net operating loss carryforwards expiring unused. Upon final determination of tax return amounts for the year ended December 31, 2017, including attribute reduction that occurred on January 1, 2018, the Company had total federal net operating loss carryforwards of $1.01 billion including $760.1 million which are subject to limitation due to the ownership change that occurred upon emergence from bankruptcy and $251.3 million of post-change net operating loss carryforwards not subject to this limitation. Because of the limitations that apply to these NOL amounts, it is possible that some portion of the Company’s NOLs could expire unused. In addition to the above, there are new limitations that apply to NOLs that arise in a taxable year ending after December 31, 2017. Unlike the law in effect prior to the 2017 Tax Act, the amendments to Section 172 disallow the carryback of NOLs but allow for the indefinite carryforward of those NOLs. In addition to the carryover and carryback changes, the 2017 Tax Act also introduces a limitation on the amount of post-2017 NOLs that a corporation may deduct in a single tax year under section 172(a) equal to the lesser of the available NOL carryover or 80 percent of a taxpayer’s pre-NOL deduction taxable income. Limitations imposed on our ability to use NOLs to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes. We may be subject to risks in connection with acquisitions and divestitures. In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. As a result, our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. In addition, we may sell non-core assets in order to increase capital resources available for other core assets and to create organizational and operational efficiencies. We may also occasionally sell interests in core assets for the purpose of accelerating the development and increasing efficiencies in such core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets with terms we deem acceptable. 34


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    Our producing properties are predominantly located in Oklahoma where our development opportunities, comprised of our inventory of drilling locations, are geographically concentrated in the STACK play in Oklahoma. We are therefore vulnerable to risks associated with operating in one major geographic area. At December 31, 2018, 78% of our proved reserves and 70% of our total equivalent production were attributable our properties located in the STACK, and we expect that concentration to increase as we have allocated substantially all of our oil and natural gas capital budget to this area in 2019. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, state and local political forces and governmental regulation, processing or transportation capacity constraints, market limitations, severe weather events, water shortages or other conditions or interruption of the processing or transportation of oil, natural gas or NGLs in the region. The market price of our common stock is volatile. The trading price of our common stock and the price at which we may sell common stock in the future are subject to fluctuations in response to various factors, many of which are beyond our control, including: • limited trading volume in our common stock; • the concentration of holdings of our common stock; • variations in operating results; • our involvement in litigation; • general U.S. or worldwide financial market conditions; • conditions impacting the prices of oil and gas; • announcements by us and our competitors; • our liquidity and access to capital; • our ability to raise additional funds; • events impacting the energy industry; • lack of trading market; • changes in government regulations; and • other events. Trading of our common stock in the public market has been limited. Therefore, the holders of our common stock may be unable to liquidate their investment in our common stock. Upon our emergence from bankruptcy, our old common stock was canceled and we issued new common stock. From May 18, 2017, through May 25, 2017, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP”. From May 26, 2017, through July 23, 2018, our Class A common stock was quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. On July 24, 2018, we transferred our stock exchange listing for our Class A common stock from the OTCQB market to the New York Stock Exchange and began trading under the new ticker symbol “CHAP.” On December 19, 2018, all outstanding shares of our Class B common stock, converted into the same number of shares of Class A common stock pursuant to the terms of our Third Amended and Restated Certificate of Incorporation (the "Certificate of Incorporation"). Although our common stock is listed on a U.S. national securities exchange, no assurance can be given that an active market will develop for our Class A common stock or as to the liquidity of the trading market for the common stock. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock. As a result, investors in our securities may not be able to resell their shares at or above the purchase price paid by them or may not be able to resell them at all. 35


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    There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders. Funds associated with Strategic Value Partners, LLC (“SVP”) and Contrarian Capital Management, L.L.C. (“Contrarian”), currently own approximately 16.8% and 8.2%, respectively, of our outstanding Class A common stock. Each of SVP and Contrarian currently has a right to nominate one of our directors under its respective support agreement. Our Board currently consists of seven members, six of whom serve as independent directors. In addition, our Board currently has two vacancies resulting from the resignations of Mr. Geenberg and Mr. Morris, each effective March 11, 2019. Pursuant to its respective support agreement, each of SVP and Contrarian currently has a right to nominate an individual to fill the vacancy resulting from the resignation of its respective designee. Pursuant to the terms of the Company’s support agreement with SVP, SVP has notified the Company that it will exercise its right to designate a replacement director to fill the vacancy resulting from Mr. Geenberg’s resignation, subject to approval by the Board. Circumstances may arise in which SVP and Contrarian may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our Class A common stock. Furthermore, the support agreements with SVP and Contrarian each provides for certain continuing nomination rights subject to conditions on share ownership. Our significant concentration of share ownership may adversely affect the trading price of our Class A common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders. We may not be able to achieve our projected financial results or service our debt. Although our financial projections represent our view based on current known facts and assumptions about the future operations of the Company, there is no guarantee that the financial projections will be realized. Our financial performance is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to meet the projected financial results or achieve projected revenues and cash flows assumed in projecting future business prospects. To the extent we do not meet the projected financial results or achieve projected revenues and cash flows, we may lack sufficient liquidity to continue operating as planned or may be unable to service our debt obligations as they come due or may not be able to meet our operational needs. Any one of these failures may preclude us from, among other things: (a) taking advantage of future opportunities; (b) growing our businesses; or (c) responding to future changes in the oil and gas industry. Further, our failure to meet the projected financial results or achieve projected revenues and cash flows could lead to cash flow and working capital constraints, which constraints may require us to seek additional working capital. We may not be able to obtain such working capital when it is required. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or seek to restructure or refinance our indebtedness. If we cannot make scheduled payments on our long-term indebtedness, we will be in default and, as a result: • debt holders, including the holders of our Senior Notes, could declare all outstanding principal and interest to be due and payable; • we may be in default under our master derivative contracts and counter-parties could demand early termination; • the lenders under our New Credit Facility could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and • we could be forced into bankruptcy or liquidation. Any inability to maintain our current derivative positions in the future specifically could result in financial losses or could reduce our income and cash flows. Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. While the use of derivative contracts may limit or reduce the downside risk of adverse price movements, their use also may limit future benefits from favorable price movements and expose us to the risk of financial loss in certain circumstances. Those circumstances 36


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    include instances where our production is less than the volume subject to derivative contracts, there is a widening of price basis differentials between delivery points for our production and the delivery points assumed in the derivative transactions or there are issues with regard to the legal enforceability of such instruments. A decline in oil and gas prices may adversely affect our financial condition, financial results, liquidity, cash flows, access to capital and ability to grow. Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the cash flow we will have available for capital expenditures as well as our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to, the following: • the level of consumer demand for oil and natural gas; • the domestic and foreign supply of oil and natural gas; • commodity processing, gathering and transportation availability, and the availability of refining capacity; • the price and level of foreign imports of oil and natural gas; • the ability of the members of OPEC to agree to and maintain oil price and production controls; • domestic and foreign governmental regulations and taxes; • the supply of other inputs necessary to our production; • the price and availability of alternative fuel sources; • weather conditions; • financial and commercial market uncertainty; • political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America; and • worldwide economic conditions. These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and gas price movements with any certainty. From mid-2014 through 2016, oil and natural gas prices declined significantly, due in large part to increasing supplies and weakening demand growth. Although oil prices increased from 2017 into the 2018, they have since declined sharply towards the end of 2018 into 2019. Extended periods of lower oil and natural gas prices will reduce our revenue but also will reduce the amount of oil and natural gas we can produce economically, and as a result, would have a material adverse effect on our financial condition, results of operations, and reserves. During periods of low commodity prices we may shut in or curtail production from additional wells and defer drilling new wells, challenging our ability to produce at commercially paying quantities required to hold our leases. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth. A decline in prices from current levels may lead to additional write-downs of the carrying values of our oil and natural gas properties in the future which could negatively impact results of operations. We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the units-of- production method. However, these capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of estimated future net revenues attributable to proved oil and natural gas reserves discounted at 10% net of tax considerations, plus the market value of unproved properties not being amortized. The full cost ceiling is evaluated at the end of each quarter using the SEC prices for oil and natural gas in effect at that date. A write-down of oil and natural gas properties does not impact cash flow from operating activities, but does reduce net income. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date. We recorded ceiling test write-downs of $20 million, $42 million and $281 million in 2018, 2017 and 2016, respectively. The volatility of oil and natural gas prices and other factors, without mitigating circumstances, could require us to 37


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    further write down capitalized costs and incur corresponding noncash charges to earnings. Since the prices used in the cost ceiling are based on a trailing twelve-month period, the full impact of a sudden price decline is not recognized immediately. A significant portion of total proved reserves as of December 31, 2018 are undeveloped, and those reserves may not ultimately be developed. As of December 31, 2018, approximately 41% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves at a total estimated undiscounted cost of $406.0 million. You should be aware that actual development costs may exceed estimates, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. The actual quantities and present value of our proved reserves may be lower than we have estimated. Estimating quantities of proved oil and natural gas reserves is a complex process. The quantities and values of our proved reserves in the projections are only estimates and subject to numerous uncertainties. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. If the variances in these assumptions are significant, many of which are based upon extrinsic events we cannot control, they could significantly affect these estimates. Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserves reports. In addition, results of drilling, testing, production, and changes in prices after the date of the estimates of our reserves may result in substantial downward revisions. These estimates may not accurately predict the present value of future net cash flows from our oil and natural gas reserves. You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses associated with the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the SEC, the estimates of present values are based on a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. Our December 31, 2018, reserve report used SEC pricing of $3.10 per Mcf for natural gas and $65.56 per Bbl for oil. Our level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our New Credit Facility and Senior Notes. As of December 31, 2018, we had total indebtedness of $320.6 million. Our current and future indebtedness could have important consequences, including the following: • our high level of indebtedness could make it more difficult for us to satisfy our obligations; • the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business; • the restrictions imposed on the operation of our business by the terms of our debt agreements may limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; • our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets; 38


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    • we must use a material portion of our cash flow from operations to pay interest on our Senior Notes, borrowings under our New Credit Facility and our other indebtedness, which will reduce the funds available to us for operations and other purposes; • our high level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt; • our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited; • our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business; • we may be vulnerable to interest rate increases, as our borrowings under our New Credit Facility are at variable rates; and • our substantial level of indebtedness may limit our ability to obtain additional debt or equity financing due to applicable financial and restrictive covenants in our debt arrangements. Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, prospects and ability to satisfy our obligations under our debt agreement. Restrictive covenants in our New Credit Facility and Senior Notes could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests. Our New Credit Facility and Senior Notes imposes operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things: • incur additional indebtedness; • make investments or loans; • create liens; • consummate mergers and similar fundamental changes; • make restricted payments; • make investments in unrestricted subsidiaries; and • enter into transactions with affiliates. These restrictions could: • limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and • adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest. Our New Credit Facility includes provisions that require mandatory prepayment of outstanding borrowings and/or a borrowing base redetermination when we make asset dispositions over a certain threshold, which could limit our ability to generate liquidity from asset sales. Also, our New Credit Facility and Senior Notes require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general, or otherwise conduct necessary corporate activities. Our potential inability to meet financial covenants could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us. A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our New Credit Facility or Senior Notes. A default under our New Credit Facility or Senior Notes , if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder, which in turn would trigger cross-acceleration and cross-default rights under our other debt. 39


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    If our debt is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us, or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies that are not subject to such restrictions. Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. Borrowings under our New Credit Facility are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash flows, including cash available for servicing our indebtedness, would correspondingly decrease. Assuming a constant debt level under our New Credit Facility of $325.0 million, equal to our borrowing base at December 31, 2018, the cash flow impact for a 12-month period resulting from a 100 basis point change in the variable component of our interest rate would be $3.3 million. Future legislative changes may increase the gross production tax charged on our oil and natural gas production. Due to significant budget shortfalls in Oklahoma in recent years, legislation has been introduced which increased the Gross Production Tax (“GPT”) applicable to the oil and natural gas we produce. In May and November 2017, the Oklahoma legislature passed bills that effectively increased production taxes on certain producing wells and units in the state. The legislative change in May 2017, which took effect in July 2017, increased the rate on certain horizontal wells spudded on or prior to July 1, 2015 from 1% to 4%. This was followed by a legislative change in November 2017, which took effect in December 2017, which further increased the rate on the aforementioned horizontal wells from 4% to 7%. In March 2018, the Oklahoma legislature approved a production tax increase from 2% to 5% during the first three years of production on horizontal wells spudded after July 1, 2015. Subsequent to these legislative changes, production from new Oklahoma wells are now taxed at a 5% rate for the first 36 months of production and at 7% thereafter. The passage of any further legislation or ballot initiatives that would increase the tax burden on all of our oil and gas production occurring in the State of Oklahoma would negatively affect our net revenues, our financial condition, and results of operations. Competition in the oil and natural gas industry is intense and many of our competitors have greater financial and other resources than we do. We operate in the highly competitive areas of oil and natural gas production, acquisition, development, and exploration and face intense competition from both major and other independent oil and natural gas companies: • seeking to acquire desirable producing properties or new leases for future development or exploration; and • seeking to acquire similar equipment and expertise that we deem necessary to operate and develop our properties. Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment. We can also be affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed developmental drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program. 40

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