Chaparral Energy, Inc. (Form: 10-K, Received: 03/29/2018 06:13:37)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 333-134748

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)


Delaware		73-1590941
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer 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:

None .

Securities registered pursuant to Section 12(g) of the Act:

None .

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes ☒ No ☐

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. ☒

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	☐	Accelerated filer	☐	Non-accelerated filer	☒

Smaller reporting company	☐	Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of June 30, 2017, 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 $812.7 million. As of June 30, 2017, 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 ☒ No ☐

Number of shares outstanding of each of the issuer’s classes of common stock as of March 26, 2018:


Class	Number of shares
Class A Common Stock, $0.01 par value	38,892,231
Class B Common Stock, $0.01 par value	7,871,512

Documents incorporated by reference:

Certain information called for in Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference to the registrant’s definitive proxy statement or will be included in an amendment to this Annual Report on Form 10-K.

CHAPARRAL ENERGY, INC.

Index to Form 10-K

Part I

Items 1. and 2.	Business and Properties	7

Item 1A.	Risk Factors	29

Item 1B.	Unresolved Staff Comments	43

Item 2.	Properties	43

Item 3.	Legal Proceedings	43

Item 4.	Mine Safety Disclosures	45

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46

Item 6.	Selected Financial Data	48

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	74

Item 8.	Financial Statements and Supplementary Data	77

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	126

Item 9A.	Controls and Procedures	126

Item 9B.	Other Information	126

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	127

Item 11.	Executive Compensation	127

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	127

Item 13.	Certain Relationships and Related Transactions and Director Independence	127

Item 14.	Principal Accounting Fee Services	127

Part IV

Item 15.	Exhibits and Financial Statement Schedules	128

Signatures		131

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:

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fluctuations in demand or the prices received for oil and natural gas;

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the amount, nature and timing of capital expenditures;

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drilling, completion and performance of wells;

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competition and government regulations;

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timing and amount of future production of oil and natural gas;

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costs of exploiting and developing properties and conducting other operations, in the aggregate and on a per-unit equivalent basis;

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changes in proved reserves;

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operating costs and other expenses;

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our future financial condition, results of operations, revenue, cash flows and expenses;

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estimates of proved reserves;

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exploitation of property acquisitions; and

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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:

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the ability to operate our business following emergence from bankruptcy;

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worldwide supply of and demand for oil and natural gas;

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volatility and declines in oil and natural gas prices;

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drilling plans (including scheduled and budgeted wells);

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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;

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the number, timing or results of any wells;

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changes in wells operated and in reserve estimates;

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future growth and expansion;

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future exploration;

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integration of existing and new technologies into operations;

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future capital expenditures (or funding thereof) and working capital;

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risks related to the concentration of our operations in the mid-continent geographic area;

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borrowings and capital resources and liquidity;

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changes in strategy and business discipline, including our post-emergence business strategy;

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future tax matters;

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any loss of key personnel;

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geopolitical events affecting oil and natural gas prices;

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outcome, effects or timing of legal proceedings;

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the effect of litigation and contingencies;

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the ability to generate additional prospects; and

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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. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. 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.

GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this section are used throughout this annual report on Form 10-K:

Active EOR Areas	Areas where we previously injected, planned to inject and/or recycled CO ₂ as a means of oil recovery.

Bankruptcy Court	United States Bankruptcy Court for the District of Delaware

Basin	A low region or natural depression in the earth’s crust where sedimentary deposits 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.

CO ₂	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.

Enhanced oil recovery (EOR)	The use of any improved recovery method, including injection of CO ₂ 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.

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, dated as of December 21, 2017, 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.

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.

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.

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.

Sandstone	A clastic sedimentary rock composed mainly of cemented sand-sized minerals or rock grains. Most sandstone is composed of quartz or feldspar. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It is usually a more resistant rock than limestone and generally has less lateral variability in porosity.

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	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.

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.

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

Chaparral Energy, Inc. is a Delaware corporation headquartered in Oklahoma City which has been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production business in the United States since 1988. We have transitioned from operating a diversified asset base in the Mid-Continent, which previously included CO ₂ enhanced oil recovery assets, to a dedicated focus on the development and acquisition of unconventional oil and natural gas reserves in the STACK. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids-rich STACK play, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage and Woodford formations.

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.

We consider our operations in the STACK to be in the early phase of a systematic, long-term development program. Our initial focus has been to delineate the Osage, Meramec, Woodford and Oswego formations through the drilling of single section horizontal wells in Kingfisher, Canadian and Garfield Counties. Based on the results of these wells, we have commenced the evaluation of full section infill development multi-well patterns, given that we expect full development of our leasehold to require multiple wells per drilling unit to maximize economic recovery of oil and natural gas from each formation.

As of December 31, 2017, we have assembled a highly contiguous position of approximately 110,000 net acres in the STACK. Our STACK acreage includes the normal pressured black-oil window in Kingfisher and Garfield Counties, Oklahoma and the MERGE in Canadian County, Oklahoma with an extensive inventory of drilling opportunities. We continue to acquire acreage within and adjacent to our acreage footprint with the goal of operating the drilling, completion and production activities in such locations. This included our acquisition in January 2018 of an additional 7,000 contiguous net acres in the core of the black-oil window of the STACK play in Kingfisher County for approximately $60.6 million in cash, increasing our total STACK play acreage to approximately 117,000 net acres.

We intend to grow our reserves and production through the development of our multi-year inventory of identified drilling locations within the STACK. From 2015 to 2017, we increased our STACK production at a compound annual growth rate of approximately 31%. At present, we are operating three horizontal drilling rigs in the STACK, of which one rig is deployed to drilling under our joint development agreement (discussed below), with plans to remain at that pace through the year. We have allocated our entire drilling and completions budget for 2018 to our STACK play.

Our average daily net production in the fourth quarter of 2017 was approximately 21.1 MBoe of which approximately 10.4 MBoe was attributable to our STACK assets. Our December 2017 average daily net production was approximately 18.3 MBoe of which approximately 10.9 MBoe was attributable to our STACK assets.

As of December 31, 2017, we had estimated proved reserves of 76.3 MMBoe with a PV-10 value of approximately $498 million. Upon adjusting for and excluding production from our Active EOR Areas, which we sold in 2017, our estimated reserve life is approximately 11.5 years. These estimated proved reserves included 49.4 MMBoe of reserves in our STACK play which represents a 58% increase from the prior year. Our total reserves were 67% proved developed, 39% crude oil, and 24% natural gas liquids.

Chapter 11 Reorganization

On May 9, 2016, the Company and ten of its subsidiaries filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. On March 10, 2017, the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017, the Reorganization Plan became effective and we emerged from bankruptcy. Upon our emergence, all existing equity was cancelled and we issued new common stock to the previous holders of our Senior Notes and certain general unsecured creditors whose claims were impaired as a result of our bankruptcy, as well as to certain other parties as set forth in the Reorganization Plan, including to parties participating in a rights offering. To facilitate our discussion in this report, we refer to the post-emergence reorganized company as the “Successor” and the pre-emergence company as the “Predecessor.” See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation for a discussion of our bankruptcy and resulting reorganization.

Business Strategy

Our business strategy is to create economic and shareholder 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 have no near term debt maturities.

Volatility of commodity pricing can significantly impact the amount of revenue received for oil and natural gas production and the level of economic returns we receive on capital invested in our exploration and development activities. Our goal will be to continue to preserve financial flexibility through a conservative balance sheet and ample liquidity as we seek to manage the current price environment. We deal with volatility in commodity prices by hedging a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price fluctuations. We also deal with volatility in commodity prices by maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to price changes. Our 2018 capital expenditure budget for acquisition, exploration and development activities will be a range of $250 million to $275 million.

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. In this regard, our development goals have been further facilitated by a joint development agreement with BCE Roadrunner, LLC, which we entered into in September 2017. The joint development agreement allows us to exploit our large inventory of drilling locations and delineate opportunities in our Canadian and Garfield STACK acreage, thereby accelerating our development of these locations.

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 strive to reduce the number of days that it takes to drill wells, and we have significantly improved completion techniques and designs over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well. High intensity multi-stage completion techniques have been particularly effective at increasing production rates and recoverable hydrocarbons as compared to prior completion techniques. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. This continued evolution may 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 robust returns on capital employed and creating shareholder value. Our focus areas in the STACK are characterized by large, contiguous acreage positions and multiple stacked geologic horizons. Building on progress made in 2016, we continued to preserve or improve on efficiency gains in various aspects of our business in 2017, with a focus on reducing spud-total depth drilling times and the average number of days to drill horizontal laterals, with a continuing goal of reducing drilling costs in our STACK area. In addition to lowering our drilling costs, we also work to optimize cash flows through the use of enhanced completion technologies that help improve recoveries and rates of returns. While we continued to realize the positive impact of continued reduced service costs through the early part of 2017, we began to see pricing pressures during the latter part of the year as a result of increased activity. We expect to be challenged in 2018 to control costs as the uptick in drilling and development activity continues from the recent oil price recovery has increased the demand for oilfield services which in turn is expected to result in higher prices for these services. We also have multiple initiatives underway to manage our base production, improve operational efficiencies and enhance future margins.

Selective monetization of assets. We are continuing to evaluate options to monetize certain assets in our portfolio, which could result in increased liquidity and lower leverage. The proceeds from monetization of assets may be utilized for debt reduction and/or capital expenditure.

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 longer term development plans and lock in rates of return on our capital projects.

2017 Highlights

The following are material events in 2017 with respect to our operations that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods.

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Public trading of securities. Subsequent to our emergence from bankruptcy, our Class A common stock began trading on the OTC Pink marketplace and subsequently on the OTCQB tier of the OTC Markets Group, Inc. public market, marking our transition from a private to a public company.

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Joint development agreement. On September 25, 2017, we entered into a joint development agreement (“JDA”) with BCE Roadrunner, LLC, a wholly-owned subsidiary of Bayou City Energy (“BCE”), pursuant to which BCE will fund 100 percent of our drilling, completion and equipping costs associated with 30 STACK wells subject to well cost caps that vary by well-type across location and targeted formations, ranging from $3.4 million to $4.0 million per gross well. The cost caps may be increased up to 20% by mutual agreement. The JDA wells, which will be drilled and operated by us, include 17 initially identified locations in Canadian County (in the Meramec and Woodford formations) and 13 locations in Garfield County (in the Osage and Meramec formations), with the option to expand the JDA to drill additional wells in the future. The JDA provides us with a means to accelerate the delineation of our position within our promising Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and potentially adding reserves. In exchange for funding, BCE will receive wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retain 15%) until the program reaches a 14% internal rate of return (“the hurdle rate”). Once achieved, ownership interest in all wells will revert such that we will own a 75% working interest and BCE will retain a 25% working interest. We will retain all acreage and reserves outside of the wellbore, with both parties paying their respective share of lease operating expenses. As of December 31, 2017, we had drilled and completed three wells and had drilled a fourth well to be completed in 2018. We expect the remaining 26 wells will be drilled in 2018.

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EOR asset sale. On October 13, 2017, we entered into a purchase and sale agreement with Perdure Petroleum, LLC, for the sale of our EOR assets for total consideration of approximately $170 million in cash plus certain contingent payments and subject to normal and customary post-closing adjustments. The sale closed on November 17, 2017, for total proceeds of $163.6 million based on preliminary estimates of closing adjustments. In conjunction with this divestiture, we incurred $3.5 million of restructuring costs primarily related to severance benefits provided to the employees affected by the divestiture.

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Debt repayment. In November 2017, we utilized proceeds from the EOR asset sale to repay in full the outstanding balance on our Exit Term Loan of $149.2 million.

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New credit agreement. In December 2017, we amended and restated our credit facility. As a result, the New Credit Facility is comprised of a $400 million reserve-based revolving facility with an initial borrowing base of $285 million (an increase of $60 million from the Exit Revolver) and we extended the maturity date of the facility from March 21, 2021, to December 21, 2022.

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Other divestitures. We also closed on various other asset divestitures during the year which included sales of oil and natural gas properties of $23.3 million, excess inventory of $2.1 million, drilling rigs of $1.8 million and an equity interest in an ethanol producing business of $1.9 million. Our divestiture of oil and natural gas properties was primarily comprised of producing properties in Osage and Ofuskee counties and drilling rights for the Oswego formation in Kingfisher County, Oklahoma. These divestitures, along with the EOR asset sale represent a critical milestone in positioning us as a pure-play STACK operator.

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Acreage acquisition. On December 22, 2017, we entered into a purchase and sale agreement to acquire acreage located in the core of our STACK Kingfisher County acreage, in an area directly adjacent to producing properties we own. This area is highly prospective for drilling in the Osage and Meramec formations of the STACK play. We closed on this purchase of approximately 7,000 acres in early January 2018 for a total purchase price of $60.6 million.

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Reserve growth. We increased year-end 2017 proved reserves to 76.3 MMBoe, an increase of 36% compared to year-end 2016 proved reserves after adjusting for and excluding reserves associated with our 2017 divestitures. Our STACK proved reserves increased by 18.2 MMBoe or approximately 58% compared to year-end 2016 proved reserves.

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Capital expenditure. Our oil and natural gas capital expenditures of $212.5 million, which were comprised of $37.3 million during the Predecessor period and $175.2 million during the Successor period, were higher than the $149.4 million we incurred in 2016. The increase in capital expenditure was driven by i) our emergence from bankruptcy, ii) a modest commodity price recovery in 2017 compared to the historic lows in 2016, iii) attractive opportunities for selective leasehold acquisitions to strengthen our position in the STACK, and iv) increased activity from other STACK operators resulting in an increase in our investment on outside operated wells. In addition, cost inflationary pressures driven by the modest industry recovery have also led to an increase in capital expenditure. Our 2017 capital activity included expenditures to drill and complete 22 wells, complete three wells which were drilled in 2016, drill three wells which will be completed in 2018, and to participate in outside operated wells, all within our STACK play. Capital was also utilized for

continuing development of our Active EOR properties up to the time the assets were sold and on selective leasehold acquisitions. We began 2017 with one rig, added a second rig in March and ran both rigs through the end of the year. In addition to the activity herein, we also conducted development under our JDA, which we discuss above.

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 although we previously also operated Active EOR Areas prior to their divestiture in November 2017. Please see Item 8. Financial Statements and Supplementary Data of this report for the results of our operations and financial position.

	Successor				Predecessor
			Period from		Period from
	Quarter		March 22, 2017		January 1, 2017
	ended		through		through
Net production (Mboe)	December 31, 2017		December 31, 2017		March 21, 2017
STACK:
STACK - Kingfisher		540		1,676		423
STACK - Canadian		225		680		142
STACK - Garfield		143		339		57
STACK - Other		46		113		34
Total STACK		954		2,808		656
Active EOR Areas		247		1,317		445
Other		739		2,478		695
Total		1,940		6,603		1,796

	Proved reserves as of December 31, 2017
	Oil (MBbls)		Natural gas (MMcf)		Natural gas liquids (MBbls)		Total (MBoe)		Percent of total MBoe			PV-10 value ($MM)
STACK
STACK - Kingfisher		15,308		50,031		6,536		30,182		39.6	%	$	219
STACK - Canadian		1,794		30,421		3,669		10,533		13.8	%		59
STACK - Garfield		1,499		24,310		2,354		7,905		10.4	%		29
STACK - Other		143		2,639		212		795		1.0	%		3
Total STACK		18,744		107,401		12,771		49,415		64.8	%		310
Other		10,860		62,765		5,551		26,872		35.2	%		188
Total		29,604		170,166		18,322		76,287		100.0	%	$	498

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, 2017, we owned approximately 110,000 net surface acres in this play, with an additional 7,000 acres purchased in January 2018. As of December 31, 2017, we have 83 gross operated producing horizontal wells and ownership interests in an additional 131 gross horizontal producing wells operated by others.

Primarily as a result of our drilling activity, our production from this area increased to 3,464 MBoe in 2017 compared to 2,723 MBoe in 2016 and 2,021 MBoe in 2015. During 2017, we spent $122.3 million on drilling activities in our STACK play, compared to

a budget of $115.5 million, where we drilled and/or participated in the drilling of 128 (28 net) horizontal wells. For 2018, our capital budget includes drilling 35 wells, completing wells drilled in the prior year and participating in non-operated wells for a total budget of $147.7 million. Included in the preceding amount is $5.0 million allocated for salt water disposal infrastructure.

Activity under our JDA with BCE in 2017 included drilling and completing three wells and drilling a fourth to be completed in 2018. For 2018, we expect to drill the remaining 26 wells under the JDA of which 13 wells will be drilled each in Canadian County and in Garfield County, Oklahoma.

Our drilling opportunities across the counties included within the STACK are described below:

STACK – Kingfisher. As of December 31, 2017, we owned approximately 25,000 net acres in the STACK play located in Kingfisher County, Oklahoma of which substantially all were held by production. As discussed above, an additional 7,000 acres were purchased in January 2018. 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 where we operated 55 gross horizontal wells as of December 31, 2017. For 2018, we plan to drill 8 gross wells in this area with a total development budget of $33.3 million.

STACK – Canadian. At December 31, 2017, 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 11 gross horizontal wells as of December 31, 2017. For 2018, we plan to drill 12 gross wells in this area with a total development budget of $57.4 million.

STACK – Garfield. At December 31, 2017, we owned approximately 40,000 net acres in the STACK play located in Garfield County, Oklahoma of which approximately one quarter is held by production. The productive reservoirs in this area are the Meramec, and Osage. Our STACK operations within this county include operating 13 gross horizontal wells as of December 31, 2017. For 2018, we plan to drill 15 gross wells in this area with a total development budget of $52.2 million.

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 2017, we incurred $37.5 million in capital expenditures on acquisitions which included leasing approximately 17,000 net acres in Garfield and Kingfisher counties, Oklahoma, which are prospective for drilling in our STACK play. In addition, in January 2018 we closed on an acquisition of approximately 7,000 acres located in the core of our STACK Kingfisher County acreage which is highly prospective for drilling in the Osage and Meramec formations of the play for $60.6 million.

Active EOR Areas

Prior to our recent divestiture of these assets, our EOR activities encompassed the North Burbank Unit located in northeastern Oklahoma (Osage County, Oklahoma) and several other units located in the Panhandle. The CO ₂ required to operate these units were sourced from supply agreements with nearby ethanol and fertilizer plants and delivered to our field locations via CO ₂ pipelines built by us. Our capital expenditure within our Active EOR Areas during 2017 was $37.3 million which was deployed for continuing CO ₂ purchases, developing our North Burbank Unit and managing production from our other units.

As discussed previously, in November 2017 we closed on a purchase and sale agreement with Perdure Petroleum, LLC, for the sale of our EOR assets along with some minor assets within geographic proximity for total proceeds of $163.6 million based on preliminary estimates of closing adjustments. Prior to their sale, these assets contributed approximately 5,700 Boe/day of net production. They also comprised 55% of our proved oil and natural gas reserves based on Securities and Exchange Commission (“SEC”) criteria as of December 31, 2017.

Other Areas

We also have additional oil and gas properties throughout Oklahoma and the Texas Panhandle which includes the Mississippi Lime formation, the Western Anadarko Basin in Western Oklahoma, and Southern Oklahoma. 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 2018. As

we have not focused our capital spending in these areas in recent years, production has declined from 6,043 MBoe in 2015 to 4,135 MBoe in 2016 and 3,173 MBoe in 2017. We are currently evaluating potential strategic alternatives for these assets.

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 Director of Resource Development is the technical person primarily accountable for overseeing the preparation of our reserve estimates. He has Bachelors and Masters degrees in Chemical Engineering and 15 years of industry experience that includes diverse petroleum engineering roles and reserves management. In addition, he is a member of the Society of Petroleum Engineers.

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.

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.

•

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 20 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 us and each of our independent petroleum consultants for the years shown.

	December 31,
	2017			2016			2015
Cawley, Gillespie & Associates, Inc.		100	%		51	%		42	%
Ryder Scott Company, L.P.		0	%		49	%		48	%
Internally prepared		0	%		0	%		10	%

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,
	2017			2016			2015
Estimated proved reserve volumes:
Oil (MBbls)		29,604			96,621			113,766
Natural gas (MMcf)		170,166			135,449			178,218
Natural gas liquids (MBbls)		18,322			12,105			12,071
Oil equivalent (MBoe)		76,287			131,301			155,541
Proved developed reserve percentage		67	%		43	%		46	%
Estimated proved reserve values (in thousands):
Future net revenue	$	1,095,732		$	1,490,090		$	2,120,608
PV-10 value	$	497,873		$	528,781		$	731,426
Standardized measure of discounted future net cash flows	$	497,873		$	528,781		$	684,689
Oil and natural gas prices: (1)
Oil (per Bbl)	$	51.34		$	42.75		$	50.28
Natural gas (per Mcf)	$	2.98		$	2.49		$	2.58
Natural gas liquids (per Bbl)	$	24.17		$	13.47		$	15.84
Estimated reserve life in years (2)		11.5			14.7			15.2

_____________________________________

(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 Active 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, 2017
	Oil (MBbls)		Natural gas (MMcf)		Natural gas liquids (MBbls)		Total (MBoe)		PV-10 value (in thousands)
Developed—producing		18,103		119,366		11,685		49,682	$	415,893
Developed—non-producing		198		4,085		173		1,052		4,634
Undeveloped		11,303		46,715		6,464		25,553		77,346
Total proved		29,604		170,166		18,322		76,287	$	497,873

Proved Undeveloped Reserves

The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2017. We have segregated the rollforward to separately disclose proved undeveloped reserves related to the EOR assets recently divested.

(in MBoe)	E&P (2)			Active EOR			Total
Proved undeveloped reserves as of January 1, 2017		13,857			61,368			75,225
Undeveloped reserves transferred to developed (1)		(57	)		—			(57	)
Sales of minerals in place		(170	)		(61,368	)		(61,538	)
Extensions and discoveries		13,320			—			13,320
Revisions and other		(1,397	)		—			(1,397	)
Proved undeveloped reserves as of December 31, 2017		25,553			—			25,553

(1)	Approximately $0.6 million of developmental costs incurred during 2017 related to undeveloped reserves that were transferred to developed.

(2)	Reserves related to the Company’s assets other than Active EOR.

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, 2017, 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)		147		113		146		109		293		222
Other		740		635		199		143		939		778
Total		887		748		345		252		1,232		1,000
Non-Operated Wells:
STACK		115		12		267		24		382		36
Other		1,294		115		770		62		2,064		176
Total		1,409		127		1,037		86		2,446		212
Total Wells:
STACK		262		125		413		133		675		258
Other		2,034		750		969		205		3,003		955
Total		2,296		875		1,382		338		3,678		1,213

(1)	Within the STACK, we have 79 gross (59 net) operated horizontal oil wells and 4 gross (1 net) operated horizontal natural gas wells.

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.

	2017						2016						2015
	Gross			Net			Gross			Net			Gross			Net
Development wells
Productive		127			27			20			12			46			22
Dry	—			—			—			—				1			1
Exploratory wells
Productive		5			1			32			4			16			6
Dry	—			—			—			—				1			1
Total wells
Productive		132			28			52			16			62			28
Dry	—			—			—			—				2			2
Total		132			28			52			16			64			30
Percent productive		100	%		100	%		100	%		100	%		97	%		93	%

As of December 31, 2017, we had four gross operated wells drilled awaiting completion in 2018. Included in these wells was one well 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, 2017, 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		43,282		24,064		4,108		1,243		47,390		25,307
Canadian County		53,189		22,214		3,240		122		56,429		22,336
Garfield County		21,780		13,510		41,150		30,872		62,930		44,382
Other		335,935		157,477		2,920		1,065		338,855		158,542
Texas		75,737		47,434		200		200		75,937		47,634
Other		10,404		8,235	—		—			10,404		8,235
Total		540,327		272,934		51,618		33,502		591,945		306,436

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, 2017 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	2018		2019		2020		2021	2022		Total
Oklahoma:
Kingfisher County - gross		1,640		908		1,320	—		240		4,108
Kingfisher County - net		688		183		370	—		2		1,243

Canadian County - gross		830		960		1,450	—	—			3,240
Canadian County - net		17		82		23	—	—			122

Garfield County - gross		3,561		18,168		12,373	—		7,048		41,150
Garfield County - net		2,912		14,504		9,056	—		4,400		30,872

Other - gross		1,282		221		1,417	—	—			2,920
Other - net		796		100		169	—	—			1,065

Texas - gross		80	—			120	—	—			200
Texas - net		80	—			120	—	—			200

Property Acquisition, Development and Exploration Costs

The following tables summarize our costs incurred for oil and natural gas properties and our reserve replacement ratio for each of the last three years:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
Property acquisition costs
Proved properties	$	179	$	527	$	390	$	1,192
Unproved properties		33,901		2,904		15,497		24,735
Total acquisition costs		34,080		3,431		15,887		25,927
Development costs		140,180		32,657		114,472		150,261
Exploration costs		916		1,241		19,055		33,091
Total	$	175,176	$	37,329	$	149,414	$	209,279

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 18—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.

The reserve replacement ratio is comprised of the following:

	Year ended December 31,
	2017 (1)						2016						2015
	Reserves replaced			Percent of total			Reserves replaced			Percent of total			Reserves replaced			Percent of total
Purchases of minerals in place		0	%		0.0	%		0	%		0.0	%		3	%		0.6	%
Extensions and discoveries		251	%		100.0	%		96	%		100.0	%		69	%		16.1	%
Improved recoveries		0	%		0.0	%		0	%		0.0	%		357	%		83.3	%
Total reserve replacement ratio		251	%		100.0	%		96	%		100.0	%		429	%		100.0	%

_________________________________________________

(1)	The denominator in calculating the 2017 ratio includes production from our Active EOR Areas, which has since been divested. Excluding production from our Active EOR Areas, the reserve replacement ratio would have been 317%.

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
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
Production:
Oil (MBbls)		3,535		1,036		4,870		5,519
Natural gas (MMcf)		11,552		3,046		15,889		18,788
Natural gas liquids (MBbls)		1,143		252		1,408		1,550
Combined (MBoe)		6,603		1,796		8,926		10,200
Average daily production:
Oil (Bbls)		12,404		12,950		13,306		15,121
Natural gas (Mcf)		40,533		38,075		43,413		51,474
Natural gas liquids (MBbls)		4,011		3,150		3,847		4,247
Combined (Boe)		23,171		22,446		24,388		27,947
Average prices (excluding derivative settlements):
Oil (per Bbl)	$	48.40	$	50.05	$	40.38	$	46.27
Natural gas (per Mcf)	$	2.55	$	3.00	$	2.16	$	2.42
Natural gas liquids (per Bbl)	$	22.69	$	22.00	$	15.00	$	15.07
Combined (per Boe)	$	34.30	$	37.04	$	28.25	$	31.80
Average costs per Boe:
Lease operating expenses	$	10.92	$	11.10	$	10.14	$	10.85
Transportation and processing	$	1.44	$	1.13	$	0.99	$	0.84
Production taxes	$	1.78	$	1.35	$	1.08	$	0.98
Depreciation, depletion, and amortization	$	14.03	$	13.87	$	13.77	$	21.23
General and administrative	$	6.00	$	3.81	$	2.35	$	3.83

The following table sets forth certain information specific to our STACK play:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
STACK Play
Production:
Oil (MBbls)		1,195		293		1,123		765
Natural gas (MMcf)		5,892		1,480		6,248		4,946
Natural gas liquids (MBbls)		631		116		559		432
Combined (MBoe)		2,808		656		2,723		2,021
Average daily production:
Oil (Bbls)		4,193		3,663		3,068		2,096
Natural gas (Mcf)		20,674		18,500		17,071		13,551
Natural gas liquids (MBbls)		2,214		1,450		1,527		1,184
Combined (Boe)		9,853		8,196		7,440		5,539
Average prices (excluding derivative settlements):
Oil (per Bbl)	$	49.05	$	49.67	$	40.81	$	45.85
Natural gas (per Mcf)	$	2.58	$	2.99	$	2.23	$	2.46
Natural gas liquids (per Bbl)	$	23.52	$	23.83	$	15.77	$	15.21
Combined (per Boe)	$	31.57	$	33.16	$	25.18	$	26.62
Average costs per Boe:
Lease operating expenses	$	4.52	$	3.43	$	3.82	$	4.67
Transportation and processing	$	2.46	$	2.29	$	1.80	$	1.68
Production taxes	$	1.08	$	0.78	$	0.48	$	0.44

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 2015 to 2016 is primarily a result of the decline in commodity prices, which resulted in a reduction in proved reserves as certain previously recorded reserves became uneconomic, and a reduction in the profit margins on remaining reserves. The decline 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 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)	2017		2016		2015
Standardized measure of discounted future net cash flows	$	497,873	$	528,781	$	684,689
Present value of future income tax discounted at 10%		—		—		46,737
PV-10 value	$	497,873	$	528,781	$	731,426

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, 2017.

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.

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 for 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
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
(in thousands)	December 31, 2017			March 21, 2017			2016			2015
Net (loss) income	$	(118,902	)	$	1,041,959		$	(415,720	)	$	(1,333,844	)
Interest expense		14,147			5,862			64,242			112,400
Income tax (benefit) expense		(349	)		37			(102	)		(177,219	)
Depreciation, depletion, and amortization		92,599			24,915			122,928			216,574
Non-cash change in fair value of non-hedge derivative instruments		46,478			(46,721	)		176,607			88,317
Gain on settlement of liabilities subject to compromise		—			(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 EBITDA		—			—			(12,810	)		—
Interest income		(21	)		(133	)		(188	)		(192	)
Stock-based compensation expense		9,833			155			(5,238	)		(1,477	)
Loss (gain) on sale of assets		25,996			(206	)		117			(1,584	)
Loss (gain) on extinguishment of debt		635			—			—			(31,590	)
Write-off of debt issuance costs, discount and premium		—			1,687			16,970			—
Loss on impairment of assets		42,325			—			282,472			1,507,336
Restructuring, reorganization and other		7,313			24,297			19,599			10,028
Adjusted EBITDA	$	120,054		$	38,075		$	228,269		$	388,749

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.

We are also 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. During 2015 and 2016, the number of providers of

materials and services decreased in the region in which we operate as a result of the significant decrease in commodity prices and activity. However, we are currently experiencing an increase in drilling activity that began in late 2016. This has resulted in an increase in the number of active drilling rigs and stimulated demand for crews and associated supplies, oilfield equipment and services, and personnel, especially in highly lucrative oil fields such as the Permian Basin and the STACK. As a result of the competitive demand for available equipment and labor in the marketplace, we expect to encounter increased prices from our vendors and service providers.

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 include:

•

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;

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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;

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informational rights;

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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, 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.

The rights and preferences of each stockholder under the Stockholders Agreement will generally terminate on the earliest of (i) the termination of the Stockholders Agreement by the unanimous written consent of all stockholders of the Company; (ii) the dissolution, liquidation or winding up of the Company; or (iii) the listing of the Company’s common stock on a U.S. national securities exchange registered with the SEC.

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).

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 Organization of Petroleum Exporting Countries 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.

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; and

•

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.

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, 2017, 2016 and 2015, we did not incur any material expenditures for the installation of remediation or pollution control equipment at any of our facilities or 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 2018 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 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 have pursued additional regulation of our operations and other states 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 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” 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. On February 1, 2018, EPA officially delayed implementation of the 2015 rule until early 2020. Meanwhile, the U.S. Army Corps of Engineers and EPA could initiate rulemaking to revise the definition of “Waters of the United States.”

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.

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 recently released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including mitigation, following anomalous seismic activity within 1.25 miles of hydraulic fracturing operations.

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 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 Safe Drinking Water Act 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. The proposed legislation, which was reintroduced to Congress on April 6, 2017, 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 Safe Drinking Water Act.

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 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 and a final decision is

pending. 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, the 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. The 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, the 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, the EPA issued additional rules 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. These regulations, 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 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. The United States is not currently a participant in the Protocol. Legislation has been proposed in Congress directed at reducing greenhouse gas emissions, and which has support in various regions of the country. 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 greenhouse gasses (“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 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 Bureau of Land Management 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. The

Bureau of Land Management has 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. These rules 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 greenhouse gas emissions; (5) pay taxes related to our greenhouse gas emissions; and (6) administer and manage greenhouse gas 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 greenhouse gas emissions would impact our business.

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 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:

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the location of wells;

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the method of drilling and casing wells;

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the timing of construction or drilling activities;

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the rates of production or “allowables”;

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the use of surface or subsurface waters;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells;

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the transportation of production; and

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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.

All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands and Indian lands in Osage County, Oklahoma require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects, or may result in cancellation of leases or other adverse action in the event of noncompliance. See Item 1A. Risk Factors of this report for further discussion.

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 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 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 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. For instance, in April 2016, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated gas transmission pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and other requirements. 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 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, 2017, we had 216 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, 2016 and 2015, we terminated 109, 64 and 213 employees, respectively, as part of our workforce reduction or company restructuring.

ITEM 1A. RI SK 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.

We emerged from bankruptcy in March 2017, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our emergence from the Chapter 11 bankruptcy proceedings in March 2017 could adversely affect our business and relationships with customers, vendors, royalty or working interest owners, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

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key suppliers could terminate their relationship or require financial assurances or enhanced performance;

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the ability to renew existing contracts and compete for new business may be adversely affected;

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the ability to attract, motivate and/or retain key executives and employees may be adversely affected;

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employees may be distracted from performance of their duties or more easily attracted to other employment opportunities;

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landowners may not be willing to lease acreage to us; and

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competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

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 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.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Pursuant to the Reorganization Plan, the composition of the Board changed significantly. The new directors have different backgrounds, experiences and perspectives from those individuals who served on the Board prior to bankruptcy and, thus, may have different views on the issues that will determine the future of the Company. There is no guarantee that the new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and plans of the Company may differ materially from those prior to bankruptcy.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the

organizational structure to adjust to changing circumstances. 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. 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 plans to elect 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. However, the Company will continue to evaluate the remaining available alternative which would not subject existing tax attributes to an IRC Section 382 limitation.

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.

Our producing properties are located in Oklahoma and the Texas Panhandle. Within these areas, 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, 2017, 65% of our proved reserves and 56% 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 2018. The remainder of our proved reserves and production are from properties in Oklahoma and the Texas Panhandle. 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:

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consequences of our reorganization under Chapter 11 of the U.S. Bankruptcy Code, from which we emerged on March 21, 2017;

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limited trading volume in our common stock;

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the concentration of holdings of our common stock

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variations in operating results;

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our involvement in litigation;

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general U.S. or worldwide financial market conditions;

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conditions impacting the prices of oil and gas;

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announcements by us and our competitors;

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our liquidity and access to capital;

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our ability to raise additional funds;

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events impacting the energy industry;

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lack of trading market;

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changes in government regulations; and

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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 cancelled and we issued new common stock. Our common stock is not currently listed on any U.S. national securities exchange registered with the SEC. Our Class A common stock is quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. Although our Class A common stock is quoted on the OTCQB, trading has been limited and with low volumes and therefore the market price of our Class A common stock may be difficult to ascertain. The common stock may be traded only infrequently in transactions arranged through brokers or otherwise, and reliable market quotations may not be available. To address these concerns and in an effort to develop an active trading market for shares of our Class A common stock, on March 6, 2018, at a special meeting of Stockholders, the Stockholders of the Company approved an amendment to the Stockholders Agreement which will allow the Company to list the Class A common stock on a national securities exchange without obtaining the approval of Stockholders. However, there is no guarantee that we will be successful in listing our Class A common stock on a U.S. national securities exchange. Further, even if the Class A 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.

Our Class B common stock is not listed or quoted on the OTCQB or any other stock exchange or quotation system, and we have not applied for such listing. Further, in the event we were to seek such listing, there is no guarantee that any established securities exchange or quotation system would accept any of our Class B common stock for listing.

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.

We may not be able to achieve our projected financial results or service our debt.

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 after emergence from bankruptcy 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.

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 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:

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the level of consumer demand for oil and natural gas;

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the domestic and foreign supply of oil and natural gas;

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commodity processing, gathering and transportation availability, and the availability of refining capacity;

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the price and level of foreign imports of oil and natural gas;

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the ability of the members of OPEC to agree to and maintain oil price and production controls;

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domestic and foreign governmental regulations and taxes;

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the supply of other inputs necessary to our production;

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the price and availability of alternative fuel sources;

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weather conditions;

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financial and commercial market uncertainty;

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political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America; and

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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 have increased, they remain below the prices that existed immediately before the market adjustment in 2014.

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 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 $42 million, $281 million and $1.5 billion in 2017, 2016 and 2015, respectively. Crude oil prices have staged a moderate recovery from previous historic lows in early 2016. However, oil and natural gas prices are volatile and this and other factors, without mitigating circumstances, could require us to 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, 2017, are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2017, approximately 33% 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 $282 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, 2017, reserve report used SEC pricing of $2.98 per Mcf for natural gas and $51.34 per Bbl for oil.

Restrictive covenants in our New Credit Facility 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 imposes operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:

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incur additional indebtedness;

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make investments or loans;

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create liens;

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consummate mergers and similar fundamental changes;

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make restricted payments;

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make investments in unrestricted subsidiaries; and

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enter into transactions with affiliates.

The restrictions contained in the New Credit Facility could:

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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

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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 requires 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. A default under our New Credit Facility, 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.

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, if enacted, would increase the Gross Production Tax (“GPT”) applicable to the oil and natural gas we produce. Generally, Oklahoma imposes a 7% tax on the gross value of oil and gas produced and sold in Oklahoma. However, production is taxed at a 2% rate for the first 36 months of production from a new well. Legislation has been introduced which would reduce or eliminate the new well GPT incentive, and increase the rate to as much as 7%. In addition, a ballot initiative has been proposed which would increase GPT by 5%, and may be on the state general election ballot in November 2018. The passage of such legislation or ballot initiatives would increase the tax burden on all of our oil and gas production, negatively affecting our net revenues, our financial condition and results of operations.

Provisions in the Stockholders Agreement may delay or prevent certain transactions that would be beneficial to our stockholders and our business, which could adversely affect our ability to conduct business.

The Stockholders Agreement contains certain provisions requiring the approval of 66 2/3% of our stockholders, thereby restricting the ability of our Board to effect certain transactions or other advantageous actions. Such provisions requiring the approval of holders of at least 66 2/3% of our outstand common stock could make it more difficult or impossible for us to enter into transactions or agreements that are important to our business, even if the transaction or agreement would be beneficial to our stockholders, including:

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a merger, consolidation, or sale of all or substantially all of the Company’s assets;

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an acquisition outside the ordinary course of business or exceeding $125,000,000;

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an amendment, waiver or modification of the charter documents of the Company;

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an incurrence of new indebtedness that would result in the aggregate indebtedness of the Company exceeding $650,000,000; and

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with certain exceptions, an initial public offering on or prior to December 15, 2018.

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:

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seeking to acquire desirable producing properties or new leases for future development or exploration; and

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seeking to acquire the equipment and expertise 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.

Energy conservation measures or initiatives that stimulate demand for alternative forms of energy could reduce the demand for the crude oil and natural gas we produce.

Fuel conservation measures, climate change initiatives, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices could reduce demand for the crude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products could have an adverse impact on our financial condition, results of operations, and growth prospects.

Drilling wells is speculative and capital intensive.

Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on commercially reasonable terms to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves, which may have an adverse effect on our results of operations and financial condition. In addition, drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or natural gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop, or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Recovery of such reserves will require significant capital expenditures and successful drilling. Our December 31, 2017, reserve estimates reflect that our production rate on current proved developed reserve properties will decline at annual rates of approximately 22%, 15%, and 12% for the next three years. Thus, our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations, and cash flows are highly dependent on our success in efficiently developing our current reserves and economically discovering or acquiring additional recoverable reserves.

Development and exploration drilling may not result in commercially productive reserves.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells we drill will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be economically recovered and/or produced. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit at then-realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. These risks are magnified when operating in an environment of low crude oil prices. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

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unexpected drilling conditions;

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title problems;

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surface access restrictions;

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pressure or lost circulation in formations;

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equipment failures or accidents;

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decline in commodity prices;

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limited availability of financing on acceptable terms;

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political events, public protests, civil disturbances, terrorist acts or cyber-attacks;

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adverse weather conditions;

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compliance with environmental and other governmental requirements; and

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increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.

If, for any reason, we are unable to economically recover reserves through our exploration and drilling activities, our results of operations, cash flows, growth, and reserve replenishment may be materially affected.

Oil and natural gas drilling and production operations can be hazardous and may expose us to uninsurable losses or other liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, hydraulic fracturing fluids, toxic gas or other

pollutants and other environmental and safety hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these events occur, we could sustain substantial losses as a result of:

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injury or loss of life;

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severe damage to or destruction of property, natural resources and equipment;

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pollution or other environmental damage;

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remediation and cleanup responsibilities;

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regulatory investigations and administrative, civil and criminal penalties; and

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injunctions or other proceedings that suspend, limit or prohibit operations.

Our liability for environmental hazards sometimes includes those created on properties prior to the date we acquired or leased them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover any or all resulting losses or liabilities. Moreover, if we experience more insurable events, our annual premiums may increase further or we may not be able to obtain any such insurance on commercially reasonable terms. The occurrence of, or failure by us to obtain or maintain adequate insurance coverage for, any of the events listed above could have a material adverse effect on our financial condition and results of operations, as well as our growth, exploration, and employee recruitment activities.

We may not have sufficient funds to repay bank borrowings if required as a result of a borrowing base redetermination.

Availability under our New Credit Facility is subject to a borrowing base, initially set at $285.0 million as of December 2017, and which is redetermined by the banks semi-annually on May 1 and November 1 of each year, commencing in May 1, 2018. In addition, the banks may request a borrowing base redetermination once between each scheduled redetermination. Dispositions of our oil and natural gas assets, early terminations of our derivative contracts, or incurrence of permitted senior additional debt may also trigger automatic reductions in our borrowing base. If the outstanding borrowings under our New Credit Facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days or (2) commencing within 30 days to repay the deficiency in equal monthly installments over a six -month period or (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency or (4) any combination of repayment as provided in the preceding three elections. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Asset sales may also reduce available collateral and availability under the New Credit Facility and could have a material adverse effect on our business and financial results. In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations.

Resolution of litigation could materially affect our financial position and results of operations.

We have been named as a defendant in certain lawsuits. See Item 3. Legal Proceedings. In some of these suits, our liability for potential loss upon resolution may be mitigated by insurance coverage. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we could incur losses that could be material to our financial position or results of operations in future periods. We may also become involved in litigation over certain issues related to the Reorganization Plan, including the proposed treatment of certain claims thereunder. The outcome of such litigation could have a material impact on our financial position or results of operations in future periods.

We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside of our control, including the operator’s:

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timing and amount of capital expenditures;

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expertise and diligence in adequately performing operations and complying with applicable agreements;

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financial resources;

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inclusion of other participants in drilling wells; and

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use of technology.

As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.

If the third parties we rely on for gathering and distributing our oil and natural gas are unable to meet our needs for such services and facilities, our future exploration and production activities could be adversely affected.

The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and third-party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and refineries or processing facilities. The lack of available capacity on such third-party systems and facilities could reduce the price offered for our production. Further, such third parties are subject to federal and state regulation of the production and transportation of oil and natural gas. If such third parties are unable to comply with such regulations and we are unable to replace such service and facilities providers, we may be required to shut-in producing wells or delay or discontinue development plans for our properties. A shut-in, delay or discontinuance could adversely affect our financial conditions.

Limitations or restrictions on our ability to obtain water may have an adverse effect on our operating results.

Our operations require significant amounts of water for drilling and hydraulic fracturing. Limitations or restrictions on our ability to obtain water from local sources may require us to find remote sources. In addition, treatment and disposal of such water after use is becoming more highly regulated and restricted. Thus, costs for obtaining and disposing of water could increase significantly, potentially limiting our ability to engage in hydraulic fracturing. This could have a material adverse effect on our operations.

We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner, and feasibility of doing business.

Our exploration, production, and marketing operations are subject to complex and stringent federal, tribal, state, and local laws and regulations governing, among other things: land use restrictions, drilling bonds and other financial responsibility requirements, reporting and other requirements with respect to emissions of greenhouse gases and air pollutants, utilization and pooling of properties, habitat and endangered species protection, reclamation and remediation, well stimulation processes, produced water disposal, safety precautions, operational reporting, and tax requirements. These laws, regulations and related public policy considerations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in order to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances on, under or from our properties and facilities, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operators. Changes in, or additions to, environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or other environmental protection requirements could have an adverse impact on our financial condition, results of operations, and growth prospects.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development. Additionally, future federal and state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal and state income tax laws, including the elimination of certain U.S. federal income tax benefits and deductions currently available to oil and gas companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the increase of the amortization period of geological and geophysical expenses, (iii) the elimination of current deductions for intangible drilling and development costs; and (iv) the elimination of the deduction for certain U.S. production activities. Moreover, other generally applicable features of the 2017 Tax Cut Act, such as changes to the deductibility of interest expense, the carryback, carryforward and limitation on the use of post 2017 net operating losses and the cost recovery rules could impact our income taxes and resulting operating cash flow. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced consumer demand for petroleum products and thereby affect the prices we receive for our commodity products.

Potential legislative and regulatory actions could negatively affect our business.

In addition to the Safe Drinking Water Act and other potential regulations on hydraulic fracturing practices, numerous other legislative and regulatory proposals affecting the oil and gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by Congress, state legislatures and various federal and state agencies. Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress, and EPA regulations to reduce greenhouse gas emissions; and (2) legislation introduced in Congress to impose new taxes on, or repeal various tax deductions available to, oil and gas producers, such as the current tax deductions for intangible drilling and development costs, which deductions, if eliminated, could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities. Any of the foregoing described proposals could affect our operations, and the costs thereof. The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any future laws and regulations, could result in increased costs or additional operating restrictions which could have an effect on demand for oil and natural gas or prices at which it can be sold. However, until such legislation or regulations are enacted or adopted into law and thereafter implemented, it is not possible to gauge their impact on our future operations or their results of operations and financial condition.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing and waste water injector wells could result in increased costs and additional operating restrictions or delays.

Our hydraulic fracturing operations are a significant component of our business, and it is an important and common practice that is used to stimulate production of hydrocarbons, particularly oil and natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, although no rule was ever finalized, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Beginning in August 2012, the EPA issued a series of rules under the CAA that establish new emission control requirements for emissions of volatile organic compounds and methane from certain oil and natural gas production and natural gas processing operations and equipment. And in March 2015, the Bureau of Land Management finalized a rule governing hydraulic fracturing and venting and flaring on federal lands. Several of the EPA’s and the BLM’s recently promulgated rules concerning regulation of hydraulic fracturing are in various stages of suspension, implementation delay, and court challenges and, thus, the future of these rules is uncertain. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells (and to a lesser extent, hydraulic fracturing) has caused increased seismic activity in certain areas. In response, some states, including states in which we operate, have imposed additional requirements on the construction and operation of underground disposal wells. For example, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division and the Oklahoma Geologic Survey recently released well completion seismicity guidance, discussed in more detail below, which requires operators to take certain prescriptive actions, including mitigation, following anomalous seismic activity within 1.25 miles of hydraulic fracturing operations.

These developments, as well as increased scrutiny of hydraulic fracturing and underground injection activities by state and municipal authorities may result in additional levels of regulation or complexity with respect to existing regulations that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our cost of compliance and doing business.

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 recent years, Oklahoma has experienced a significant increase in earthquakes and other seismic activity. On April 21, 2015, the Oklahoma Geologic Survey (“OGS”) issued a document entitled “Statement of Oklahoma Seismicity,” in which the agency states “[t]he OGS considers it very likely that the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells.” The Oklahoma Corporation Commission (“OCC”) has issued directives restricting injection of high volumes of water into the Arbuckle formation and into the crystalline basement below within a specified area of interest (“AOI”) in Central and Western Oklahoma. The AOI now includes more than 10,000 square miles and more than 600 Arbuckle disposal wells, resulting in a reduction of more than 800,000 barrels per day from the 2015 average injection volumes. The OCC has adopted a “traffic light” system for disposal operators to review disposal well permits for proximity to faults

seismicity in the area and other factors, and adopted rules requiring well pressure recording and reporting, and mechanical integrity tests on certain wells. In addition, the OCC has issued directives aimed at limiting the future growth of disposal rates into the Arbuckle by capping disposal volumes in the AOI, even those not operating under currently permitted volumes, to the thirty day disposal average. We operate 16 wells in the AOI and are fully compliant with all regulations relating to the disposal of produced water, and at this time our operations have not been affected.

In February 2018, the Commission introduced new guidelines related to seismicity, requiring operators in the defined area to have access to a seismic array which will provide real-time seismicity readings, and to develop plans to address seismic activity. The guidelines reduce the earthquake magnitude at which action is required from 2.5 to 2.0 within a 3.1 mile radius of hydraulic fracturing operations, and changes the level at which operators are required to pause hydraulic fracturing operations from 3.0 to 2.5.

We cannot predict whether future regulatory actions will result in further expansion of AOI or new or additional regulations by the OCC or other agencies with jurisdiction over our operations. Any such new or expanded regulation could result in increased operating costs, cause operational delays, and result in additional regulatory burdens that could make it more difficult to inject produced water into disposal wells. Increased complexity and reporting requirements arising from expanded regulations may increase our costs of compliance and doing business. In addition, even though we have conducted our operations in compliance with applicable laws, the increase in media and regulatory attention to the possible connection between seismic activity and produced water injection has led to litigation filed against us and other oil and gas producers requesting compensation for damages, including demands for damages caused by earthquakes and earthquake insurance premiums on a going forward basis. We cannot predict the outcome of this litigation or provide assurances that other similar claims will not be filed against us in the future.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. Although we make estimates of such costs and record the associated liability on our balance sheet, there is no assurance that our cost estimates will coincide with actual costs when the remediation work takes place. The timing and amount of costs is difficult to predict with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.

Costs of environmental liabilities could exceed our estimates and adversely affect our operating results.

Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:

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the uncertainties in estimating cleanup costs;

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the discovery of additional contamination or contamination more widespread than previously thought;

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the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;

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changes in interpretation and enforcement of existing environmental laws and regulations; and

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future changes to environmental laws and regulations and their enforcement.

Although we believe we have established appropriate reserves for known liabilities, including cleanup costs, we could be required to set aside additional reserves in the future due to these uncertainties, incur material cleanup costs, other liabilities, and/or expend significant sums to defend ourselves against litigation related to legacy environmental issues, which could have an adverse impact on our financial condition, results of operations, and growth prospects.

Our use of derivative instruments could result in financial losses or reduce our income.

To reduce our exposure to the volatility in the price of oil and gas and provide stability to cash flows, we enter into derivative positions. Our commodity hedges are currently comprised of fixed price swaps and collars with financial institutions. The volumes and average notional prices of these hedges are disclosed in in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this report.

Derivative instruments expose us to risk of financial loss in some circumstances, including when:

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our production is less than expected;

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the counterparty to the derivative instruments defaults on its contractual obligations; or

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there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative instruments.

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, none of our derivatives are classified as hedges for accounting purposes and therefore must be adjusted to fair value through income each reporting period.

While the primary purpose of our derivative transactions is to protect ourselves against the volatility in oil and natural gas prices, under certain circumstances, or if hedges are discontinued, or terminated for any reason, we may incur substantial losses in closing out our positions, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

We are subject to financing and interest rate exposure risks.

Our future success depends on our ability to access capital markets and obtain financing on reasonable terms. Our ability to access financial markets and obtain financing on commercially reasonable terms in the future is dependent on a number of factors, many of which we cannot control, including changes in:

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our credit ratings;

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interest rates;

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the structured and commercial financial markets;

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market perceptions of us or the oil and natural gas exploration and production industry; and

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tax burden due to new tax laws.

Assuming a constant debt level of $285.0 million, equal to our borrowing base as of March 23, 2018 under our New Credit Facility, the cash flow impact for a 12-month period resulting from a 100 basis point movement in interest rates, regardless of whether the spread widens or tightens, would be $2.9 million. As a result, any increases in our interest rates, or our inability to access the equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations, and growth prospects.

We are exposed to counterparty credit risk as a result of our receivables .

We are exposed to risk of financial loss in connection with our receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. However, there is a possibility that some of our purchasers may experience credit downgrades or liquidity problems and may not be able to meet their financial obligations to us. Nonperformance by an oil or natural gas purchaser could result in financial losses.

Unusual weather patterns or natural disasters, whether due to climate change or otherwise, could negatively impact our financial condition.

Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Oklahoma and Texas, our operations are constantly at risk of extreme adverse weather conditions such as freezing rain, tornadoes, draught, and hurricanes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as freezing rain, hurricanes or floods, whether due to climate change or otherwise.

Changes in, or challenges to, our rates and other terms and conditions of service could have a material adverse effect on our financial condition and results of operations.

The rates charged by certain of our pipeline systems are regulated by the Federal Energy Regulatory Commission (“ FERC”), state regulatory agencies, or both. These regulatory agencies also regulate other terms and conditions of the services these pipeline systems provide, including the types of services we may offer. If one of these regulatory agencies, on its own initiative or due to

challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose, the profitability of our pipeline businesses would suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which if delayed could further reduce our cash flow. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial condition, results of operations and cash flows.

A change in the jurisdictional characterization of our assets, or a change in policy, could result in increased regulation of our assets which could materially affect our financial condition, results of operations and cash flows .

Certain of our pipeline assets are natural gas gathering facilities. Unlike interstate natural gas transportation facilities, natural gas gathering facilities are exempt from the jurisdiction of FERC under the Natural Gas Act of 1938 (“NGA”). Although FERC has not made a formal determination with respect to all of our facilities we believe to be gathering facilities, we believe that these pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and 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. 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 Natural Gas Policy Act of 1978 (“NGPA”). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, 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 services in excess of the rate established by FERC.

Increased regulatory requirements regarding pipeline safety and integrity management may require us to incur significant capital and operating expenses to comply.

The ultimate costs of compliance with pipeline safety and integrity management regulations are difficult to predict. The majority of the compliance costs are for pipeline safety and integrity testing and the repairs found to be necessary. We plan to continue our efforts to assess and maintain the safety and integrity of our existing and future pipelines as required by the DOT and PHMSA rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. In addition, new laws and regulations that may be enacted in the future, or a revised interpretation of existing laws and regulations, could significantly increase the amount of these costs. We cannot be assured about the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs, or additional operating restrictions, could have a material adverse effect on our business, financial position, results of operations and prospects.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on us and our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market including swap clearing and trade execution requirements. New or modified rules, regulations or requirements may increase the cost and availability to the counterparties of our hedging and swap positions which they can make available to us, as applicable, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities which may not be as creditworthy as the current counterparties. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

While many rules and regulations have been promulgated and are already in effect, other rules and regulations remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could (i) significantly increase the cost, or decrease the liquidity, of energy-related derivatives that we use to hedge against commodity price fluctuations (including through requirements to post collateral), (ii) materially alter the terms of derivative contracts, (iii) reduce the availability of derivatives to protect against risks we encounter, and (iv) increase our exposure to less creditworthy counterparties.

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations .

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages in such personnel. The severe industry decline that began in mid-2014 resulted in a large displacement of experienced personnel through layoffs and many of the affected personnel moved on to careers in other industries. This structural shift in available workforce may be impactful in future periods. The moderate price recovery that began in late 2016 has resulted in an increase in the number of active drilling rigs and stimulated demand for crews and associated supplies, oilfield equipment and services, and personnel. As such we may encounter shortages of these resources as well as increased prices. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of their exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to their business. Our technologies, systems and networks may become the target of cyber-attacks or information security breaches that could result in the disruption of our business operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations. To date we have not experienced any material losses relating to cyber-attacks, however there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance their protective measures or to investigate and remediate any cyber vulnerabilities.

The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for natural gas.

The EPA has determined that GHGs present an endangerment to public health and the environment because such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented, and continues to adopt and implement, regulations that restrict emissions of greenhouse gases (“GHGs”) under existing provisions of the Clean Air Act (“CAA”). The EPA also requires the annual reporting of GHG emissions from certain large sources of GHG emissions in the United States, including certain oil and gas production facilities and oil and natural gas gathering and boosting operations. The EPA has also taken steps to limit methane emissions from oil and gas production facilities. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. And in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement entered into force in November 2016. However, President Trump has since announced that the United States will withdraw from the Agreement; notably, the earliest date of withdrawal under the terms of the Agreement is November 4, 2020. Restrictions on emissions of GHGs that may be imposed could adversely affect the natural gas industry by reducing demand for hydrocarbons and by making it more expensive to develop and produce hydrocarbons, either of which could have a material adverse effect on future demand for our services. Moreover, climate change may cause more extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured. For a more detailed discussion of climate change, please see Environmental Matters and Regulation – Climate Change .

We may face risks associated with the increased activism against oil and gas exploration and development activities.

Opposition toward oil and gas drilling and development activity has been growing in recent years. Companies in the oil and gas industry are often the target of activist efforts regarding safety, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil or gas shale plays. Future activist efforts could result in the following:

•

delay or denial of drilling permits;

•

shortening of lease terms or reduction in lease size;

•

restrictions on installation or operation of production, gathering or processing facilities;

•

restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposal of related waste materials, such as hydraulic fracturing fluids and produced water;

•

increased severance and/or other taxes;

•

cyber-attacks;

•

legal challenges or lawsuits;

•

negative publicity about our business or the industry in general;

•

increased costs of doing business; and

•

reduction in demand for our products.

We may need to incur significant costs associated with responding to these initiatives. Complying with any resulting additional legal or regulatory requirements could have a material adverse effect on our business, financial position, results of operations and prospects.

We may incur losses as a result of title defects in the properties in which we invest.

Although we take the steps customary in the oil and natural gas industry to review title and perform any curative work with respect to any title defects, the existence of a material title deficiency could render a lease worthless and have an adverse impact on our financial condition, results of operations, and growth prospects.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, or if we are unable to use the most advanced commercially available technology, it could have an adverse impact on our financial condition, results of operations, and growth prospects.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See Item 1. Business and Properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See our additional disclosures in “Liquidity and Capital Resources—Contractual Obligations” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as “Note 16—Commitments and contingencies” in Item 8. Financial Statements and Supplementary Data. Such information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

Chapter 11 Proceedings. Commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016, and the claims remain subject to bankruptcy court jurisdiction. In connection with the proofs of claim asserted during bankruptcy from the proceedings or actions below, we are unable to estimate the amounts that will be allowed through the Bankruptcy proceedings due to the complexity and number of legal and factual issues presented by the matters and uncertainties with respect to, amongst other things, the nature of the claims and defenses, the potential size of the classes, the scope and types of the properties and agreements involved, and the ultimate potential outcomes of the matters. As a result, no reserves were established within our liabilities in connection with the proceedings and actions described below. To the extent that any of these legal proceedings result in a claim being allowed against us, pursuant to the terms of the Reorganization Plan, such claims will be satisfied through the issuance of new stock in the Company or, if the amount is such claim is below the convenience class threshold, through cash settlement.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Trial Court”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. Plaintiffs

indicated they seek damages in excess of $5.0 million, the majority of which would be comprised of interest and may increase with the passage of time. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court.

On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the plaintiffs originally sought to certify. After additional briefing on the subject, on April 18, 2017, the Naylor Trial Court issued an order certifying the class to include only claims relating back to June 1, 2006. On May 1, 2017, we filed a Petition for Permission to Appeal Class Certification Order with the Tenth Circuit Court of Appeals (the “Tenth Circuit”), which was granted . The appeal has been fully briefed, and oral arguments were held on March 20, 2018.

In addition to filing claims on behalf of the named and putative plaintiffs, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of $150.0 million in our Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90.0 million inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims, to which we will also object. On June 7, 2017 we appealed the Bankruptcy Court order to the United States District Court for the District of Delaware. Under the Reorganization Plan, the plaintiffs are identified as a separate class of creditors, Class 8. Class 8 claims are entitled to receive their pro rata share of new stock issued to the holders of general unsecured claims (including claims of the Noteholders). Although the members of Class 8 voted to reject the Plan, the Bankruptcy Court confirmed the Plan on March 10, 2017, without objection by the plaintiffs.

If the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgment or settlement of the unsecured claims would be satisfied through the issuance of new stock in the Company. We continue to dispute the plaintiffs’ allegations, dispute the case meets the requirements for class certification, and are objecting to the claims both individually and on a class-wide basis.

Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs challenged leases and drilling permits approved by the Bureau of Indian Affairs without the environmental studies allegedly required under the National Environmental Policy Act (NEPA). The plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio , removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. On March 31, 2016, the Court dismissed the case against all defendants as an improper challenge under NEPA and the Administrative Procedures Act. On April 29, 2016, the plaintiffs filed motions to alter or amend the court’s opinion and vacate the judgment, and to file an amended complaint to cure the deficiencies which the court found in the dismissed complaint. On May 20, 2016, the Company filed a Notice of Suggestion of Bankruptcy, and as a result has not responded to the plaintiffs’ motions. After plaintiff’s motion for reconsideration was denied, plaintiffs filed a Notice of Appeal on December 6, 2016. Oral argument regarding the appeal was held on November 14, 2017. The Court has not ruled on the appeal.

We anticipate any monetary liability related to this claim will be discharged. We dispute plaintiffs’ allegations and dispute that the case meets the requirements for a class action .

Lisa West and Stormy Hopson, individually and as class representatives on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On February 18, 2016, an alleged class action was filed against us, as well as several other operators in the District Court of Pottawatomie County, State of Oklahoma, alleging claims on behalf of named plaintiffs and all similarly situated persons having an insurable real property interest in eight counties in central Oklahoma (the “Class Area”). The plaintiffs allege the oil and gas operations conducted by us and the other defendants have induced earthquakes in the Class Area. The plaintiffs did not seek damages for property damage, instead asked the court to require the defendants to reimburse plaintiffs and class members for earthquake insurance premiums from 2011 through the time at which the court determines there is no longer a risk of induced earthquakes, as well as attorney fees and costs and other relief. We responded to the petition, denied the allegations and raised a number of affirmative defenses. On March 18, 2016, the case was removed to the United States District Court for the Western District of Oklahoma under the Class Action Fairness Act. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. On October 14, 2016, the plaintiffs filed an

Amended Complaint adding additional defendants and increasing the Class Area to 25 Central Oklahoma counties. Other defendants filed motions to dismiss the action which was granted on May 12, 2017. On July 18, 2017, plaintiffs filed a Second Amended Complaint adding additional named plaintiffs as putative class representatives and adding three additional counties to the putative class area. In the Second Amended Complaint, plaintiffs seek damages for nuisance, negligence, abnormally dangerous activities, and trespass. Due to Chaparral’s bankruptcy, plaintiffs specifically limit alleged damages related to Chaparral’s disposal activities occurring after our emergence from bankruptcy on March 21, 2017. We moved to dismiss the Second Amended Complaint on September 15, 2017.

Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75.0 million in our Chapter 11 Cases. W e filed an objection to class treatment of the proof of claim filed by the West plaintiffs in our Bankruptcy proceeding. The Bankruptcy Court had a hearing on our objection and on February 9, 2018, the Court granted our objection to class treatment of the proof of claim. We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case .

Lisa Griggs and April Marler, on behalf of themselves and other Oklahoma citizens similarly situated v. New Dominion, L.L.C. et al. On July 21, 2017, an alleged class action was filed against us and other operators, in the District Court of Logan County, State of Oklahoma. The named plaintiffs assert claims on behalf of themselves and Oklahoma citizens owning a home or business between March 30, 2014, and the present in a Class Area which encompasses nine counties in central Oklahoma. The plaintiffs allege disposal of saltwater produced during oil and gas operations induced earthquakes in the Class Area, and each defendant has liability under theories of ultra-hazardous activities, negligence, nuisance, and trespass. On October 24, 2017, plaintiffs filed a First Amended Class Petition in Logan County, Oklahoma, adding Creek County, Oklahoma to the Class Area, and adding an additional earthquake to the list of seismic events allegedly caused by the defendants. The plaintiffs asked the court to award unspecified damages for damage to real and personal property and loss of market value, loss of use and enjoyment of the properties, and emotional harm, as well as punitive damages and pre-judgment and post-judgment interest. The case was removed to the Western District of Oklahoma on December 15, 2017, and on December 18, 2017, plaintiffs voluntarily dismissed us from the suit without prejudice. Due to subsequent remand to state court, we filed notice of the dismissal in the state court action on January 31, 2018.

James Butler et al. v. Berexco, L.L.C., Chaparral Energy, L.L.C, et al . On October 13, 2017, a group of fifty-two individual plaintiffs filed a lawsuit in the District Court of Payne County, State of Oklahoma against twenty-six named defendants, including us, and twenty-five unnamed defendants. Plaintiffs are all property owners and residents of Payne County, Oklahoma, and allege salt water disposal activities by the defendants, owners or operators of salt water disposal wells, induced earthquakes which have caused damage to real and personal property, and emotional damages. Plaintiffs claim absolute liability for ultra-hazardous activities, negligence, gross negligence, public and private nuisance, trespass, and ask for compensatory and punitive damages. On December 18, 2017, we moved the court to dismiss the claims against us. Prior to plaintiffs responding to our motion, a hearing on a motion to stay the Butler case was held on January 4, 2018. The judge granted the motion to stay proceedings, ruling from the bench that the Butler case was stayed pending final judgment or denial of class certification in the Lisa West et al. v. ABC Oil Company, Inc. case. Our motion to dismiss will not be considered until the stay is lifted, at which time, if necessary, we will dispute plaintiffs’ claims, dispute that the remedies requested are available under Oklahoma law, and vigorously defend the case .

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, disputes with taxing authorities, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. In addition, other proofs of claim have been filed in our bankruptcy case which we anticipate repudiating. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows .

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Prior to our emergence from bankruptcy on March 21, 2017, there were 1,382,288 outstanding shares of common stock, none of which were publicly traded. Upon emergence from bankruptcy, on March 21, 2017 (the “Effective Date”), these shares were cancelled, extinguished and discharged and we issued, or reserved for issuance, a total of 44,982,142 shares of Successor common stock consisting of 37,110,630 shares of Class A common stock and 7,871,512 shares Class B common stock pursuant to our Reorganization Plan and our new organizational documents. The new Class A shares and Class B shares have identical economic and voting rights. However, Class B shares are subject to certain redemption provisions upon demand to the Company by certain stockholders undertaking an initial public offering, as described in our Third Amended and Restated Certificate of Organization. Further, shares of Class B Common Stock are subject to automatic conversion to Class A Common Stock upon the earlier of an initial public offering meeting certain conditions, whether or not the redemption provisions were exercised, or December 15, 2018.

As of March 26, 2018, there were 205 and 3 record holders of 38,892,231 and 7,871,512 outstanding shares of Class A and Class B common stock of the Successor, respectively. In addition, as of March 26, 2018, we had outstanding warrants for the purchase of 140,023 shares of Class A common stock with an exercise price of $36.78 which are immediately exercisable and will expire on June 30, 2018.

Price range of common stock

Our Class A common stock is quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. Our Class A common stock began quoting on the OTCQB on May 26, 2017. From May 18, 2017 through May 25, 2017, our Class A common stock was quoted on the OTC Pink market place under the symbol “CHHP”. No established public trading market existed for our Class A common stock prior to that date. Our Class B common stock is not listed or quoted on the OTCQB or any other stock exchange or quotation system, and we have not applied for such listing. Further, in the event we were to seek such listing, there is no guarantee that any established securities exchange or quotation system would accept any of our Class B common stock for listing. Although our Class A common stock is quoted on the OTCQB, trading and quotations of our Class A common stock have been limited and sporadic. Over-the-counter market quotations reflect interdealer prices, without retailer markup, markdown, or commission and may not necessarily represent actual transactions. The following table sets forth the high and low last reported sales prices per share of our Class A common stock, as reported on the OTCQB or OTC Pink, of which we are aware for the period indicated. Based on information available to us, we believe transactions in our Class A common stock can be fairly summarized as follows for the period indicated:

	High		Low
2017
Fourth Quarter	$	25.50	$	23.00
Third Quarter	$	23.25	$	19.50
Second Quarter (1)	$	26.00	$	12.00

________________________________

(1)	Represents the period from May 18, 2017, the date on which our Class A common stock began quoting on the OTC Pink, through June 30, 2017.

We have not paid any dividends on our common stock in either of the last two years and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also restricted from paying any cash dividends under our New Credit Facility.

Securities authorized for issuance under equity compensation plans

Our Reorganization Plan authorized the issuance of 7% of outstanding Successor common shares on a fully diluted basis toward a new management incentive plan (“MIP”). The aggregate number of shares of Class A common stock, par value $0.01 per share, reserved for issuance pursuant to our MIP was initially set at 3,388,832 subject to changes in the event additional shares of common stock are issued under our Reorganization Plan. Out of the amount reserved, the remaining shares available for issuance as of December 31, 2017 are disclosed below:

Plan category

Number of securities

to be issued upon

exercise of

outstanding

options, warrants

and rights

Weighted-average

exercise price of

outstanding options,

warrants and rights

Number of securities

remaining available

for future issuance

under equity

compensation plans

(1)

Equity compensation plans approved by stockholders

—

1,543,212

Equity compensation plans not approved by stockholders

—

________________________________

(1)	Available for issuance under the MIP. In addition, shares that are terminated, canceled, expire unexercised, or settled in such manner that all or some of the shares are not issued to a participant or are surrendered unvested shall immediately become available for future issuance.

Sales of Unregistered Securities

None.

Repurchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

You should read the following historical financial data in connection with the financial statements and related notes and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this report. The financial data as of and for each of the five years ended December 31, 2017 was derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through		Year ended December 31,
(in thousands)	December 31, 2017			March 21, 2017		2016			2015			2014		2013
Statements of Operations Data:
Revenues	$	227,079		$	66,531	$	252,152		$	324,315		$	681,557	$	628,808
Operating (loss) income (1)		(45,266	)		9,752		(295,464	)		(1,577,865	)		204,027		205,972
Net (loss) income (2)		(118,902	)		1,041,959		(415,720	)		(1,333,844	)		209,293		55,687
Earnings per share:
Basic for Class A and Class B	$	(2.64	)	*		*			*			*		*
Diluted for Class A and Class B	$	(2.64	)	*		*			*			*		*
Statements of Cash Flows Data:
Net cash provided by operating activities	$	84,969		$	14,385	$	47,167		$	19,608		$	323,911	$	264,053
Expenditures for property, plant, and equipment and oil and natural gas properties		157,718			31,179		146,296			313,481			685,459		491,022
Other Data:
Production (MBoe)		6,603			1,796		8,926			10,200			10,982		9,742

________________________________

(1)	Operating (loss) income for the Successor period of 2017 and the Predecessor periods of 2016, 2015, and 2013 included impairment charges of $42.3 million, $282.5 million, $1.5 billion, and $3.5 million, respectively.

(2)	Net (loss) income for the Successor period of 2017 and the Predecessor periods of 2017 and 2016 included reorganization items (expense) income attributable to our bankruptcy proceedings of $(3.1) million, $988.7 million, and $(16.7) million, respectively.

* We have not historically presented earnings per share because our common stock did not previously trade on a public market, either on a stock exchange or in the over-the-counter market. Accordingly, we were permitted under accounting guidance to omit such disclosure.

	Successor		Predecessor
	December 31,		December 31,
(in thousands)	2017		2016			2015			2014		2013
Balance Sheet Data:
Total oil and natural gas properties	$	992,353	$	555,184		$	798,837		$	2,322,391	$	2,110,048
Total assets		1,139,306		845,987			1,181,313			2,831,816		2,397,882
Total debt (1)		144,659		469,112			1,583,701			1,633,802		1,562,862
Total stockholders’ equity (deficit)		842,766		(1,042,153	)		(620,357	)		711,858		497,264
Other Data:
Proved reserves as of December 31, (MBoe)		76,287		131,301			155,541			159,393		158,475

________________________________

(1)	In 2016 the $1.2 billion balance outstanding under our Senior Notes was reclassified from debt to liabilities subject to compromise.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report. References to “Successor” relate to the financial position and results of operations of the reorganized company subsequent to its emergence from bankruptcy on March 21, 2017. References to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, March 21, 2017. In addition to historical financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Executive Overview

Chaparral Energy, Inc. is a Delaware corporation headquartered in Oklahoma City which has been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production business in the United States since 1988. We have transitioned from operating a diversified asset base in the Mid-Continent, which previously included CO ₂ enhanced oil recovery assets, to a dedicated focus on the development and acquisition of unconventional oil and natural gas reserves in the STACK. Our STACK play is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage and Woodford formations.

As of December 31, 2017, we had estimated proved reserves of 76.3 MMBoe with a PV-10 value of approximately $498 million. Upon adjusting for and excluding production from our Active EOR Areas, which we sold in 2017, our estimated reserve life is approximately 11.5 years. These estimated proved reserves included 49.4 MMBoe of reserves in our STACK play. Our reserves were 67% proved developed, 39% crude oil, 24% natural gas liquids and 37% natural gas.

Our December 31, 2017 reserve estimates reflect that our production rate on current proved developed properties will decline at annual rates of approximately 22%, 15%, and 12% for the next three years. To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

2017 Financial and Operating Highlights

Financial highlights . With a net loss of $118.9 million and net income of $1,042.0 million during the Successor and Predecessor periods of 2017, our financial statements for 2017 were significantly impacted by certain company-related transformative events and trends in the industry.

Our bankruptcy and subsequent emergence resulted in material gains from the forgiveness of debt of $372.1 million and from the increase in book value of our assets as a result of fresh start accounting of $641.7 million, partially offset by the significant administrative costs of navigating through the bankruptcy of $21.9 million, all of which are reflected as reorganization costs on our statement of operations.

In our transformation toward becoming a pure play STACK operator, we underwent a restructuring of our business via the sale of our EOR assets, which resulted in a $25.2 million loss on sale and $3.5 million of restructuring expense. The loss of EOR-related oil and gas reserves subsequent to the sale also resulted in a ceiling test write-down of $42.1 million.

The modest improvement in commodity pricing, which rebounded from historical lows in 2016, resulted in an increase in revenues of $40.9 million but also led to an increase in production taxes, which are based on revenues. In addition, due to budgetary shortfalls, the Oklahoma legislature raised production tax rates on certain wells in 2017, which led to an approximately $1.8 million increase in production taxes, with further rate increases still being considered.

Subsequent to emergence from bankruptcy, we implemented a new management incentive plan which resulted in $10.0 million of general and administrative expenses. This is in contrast to 2016 where forfeitures and adjustments to reflect the likelihood that requisite performance would not be met for awards under a previous incentive plan resulted in a credit to general and administrative expenses of $5.2 million. The fluctuations in stock based compensation and certain bankruptcy provisions which required us to recognize our 2016 bonus in 2017 are the primary drivers of a $25.5 million increase in general and administrative expenses in 2017 compared to 2016.

Operating highlights. The following are material events in 2017 with respect to our operations that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods.

•

Emergence from bankruptcy . On March 10, 2017, the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017, the Reorganization Plan became effective and we emerged from bankruptcy. See below for a discussion of our bankruptcy and resulting reorganization.

•

EOR asset sale. On October 13, 2017, we entered into a purchase and sale agreement with Perdure Petroleum, LLC., for the sale of our EOR assets for total consideration of approximately $170 million in cash plus certain contingent payments and subject to normal and customary post-closing adjustments. The sale closed on November 17, 2017, for total proceeds of $163.6 million based on preliminary estimates of closing adjustments. In conjunction with this divestiture, we recorded a loss on sale of $25.2 million and $3.5 million of restructuring costs.

•

Debt repayment. In November 2017, we utilized proceeds from the EOR asset sale to repay in full the outstanding balance on our Exit Term Loan of $149.2 million.

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Other divestitures. We also closed on various other asset divestitures during the year which included sales of oil and natural gas properties of $23.3 million, excess inventory of $2.1 million, drilling rigs of $1.8 million and an equity interest in an ethanol producing business of $1.9 million. Our divestiture of oil and natural gas properties was primarily comprised of producing properties in Osage and Okfuskee counties and drilling rights for the Oswego formation in Kingfisher County, all in Oklahoma. These divestitures, along with the EOR asset sale represent a critical milestone in positioning us as a pure-play STACK operator.

•

Acreage acquisition. On December 22, 2017, we entered into a purchase and sale agreement to acquire acreage located in the core of our STACK Kingfisher County leasehold, in an area directly adjacent to producing properties we own. This area is highly prospective for drilling in the Osage and Meramec formations of the STACK play. We closed on this purchase of approximately 7,000 acres in early January 2018 for a total purchase price of $60.6 million.

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Production. Our total net production of 1,940 MBoe during the fourth quarter of 2017 decreased approximately 9% from the prior year quarter primarily due to our EOR asset divestiture, which occurred in November 2017, and natural well decline partially offset by increases in production from our STACK play. Our total net production in 2017 comprised of 6,603 MBoe and 1,796 MBoe in the Successor and Predecessor periods, respectively, and was 6% lower than the prior year as a result of our EOR asset sale and well decline, which was partially offset by production increases in the STACK from additional development.

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STACK production. Driven by our continued focus on developing the STACK, our STACK net production grew to 954 MBoe in the fourth quarter of 2017, an increase of 39% from the prior year quarter. Our STACK net production for 2017 comprised of 2,808 MBoe and 656 MBoe during the Successor and Predecessor periods respectively, was 27% higher than the prior year.

•

Reserve growth. We increased year-end 2017 proved reserves to 76.3 MMBoe, an increase of 36% compared to year-end 2016 proved reserves after adjusting for and excluding reserves associated with 2017 divestitures. Our STACK proved reserves increased 18.2 MMBoe or approximately 58% compared to year-end 2016 proved reserves.

Chapter 11 Reorganization

Bankruptcy petition and emergence. On May 9, 2016 (the “Petition Date”), Chaparral Energy, Inc. and its subsidiaries including Chaparral Energy, L.L.C., Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2 , L.L.C., CEI Pipeline, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C. (collectively, the “Chapter 11 Subsidiaries” and, together with Chaparral Energy, Inc., the “Debtors”) filed voluntary petitions seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) commencing cases for relief under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”).

On March 10, 2017, (the “Confirmation Date”), the Bankruptcy Court confirmed our Reorganization Plan and on the Effective Date, the Reorganization Plan became effective and we emerged from bankruptcy.

Debtor-In-Possession. During the pendency of the Chapter 11 Cases, we operated our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by us which were designed primarily to minimize the impact of the Chapter 11 Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business required the approval of the Bankruptcy Court.

Automatic Stay. Subject to certain exceptions, under the Bankruptcy Code, the filing of the bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or the filing of other actions against us or our property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order from the Bankruptcy Court, substantially all of our pre-petition liabilities were subject to settlement under the Bankruptcy Code.

Plan of Reorganization. Pursuant to the terms of the Reorganization Plan, which was supported by us, certain lenders under our Prior Credit Facility (collectively, the “Lenders”) and certain holders of the Company’s Senior Notes (collectively, the “Noteholders”), the following transactions occurred on or around the Effective Date:

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We issued or reserved for issuance 44,982,142 shares of common stock of the Successor (“New Common Stock”), in accordance with the transactions described below. We also entered into a stockholders agreement and a Registration Rights Agreement and amended our certificate of incorporation and bylaws for the authorization of the New Common Stock and to provide registration rights thereunder, among other corporate governance actions;

•

Our Predecessor common stock was cancelled, extinguished and discharged and the Predecessor equity holders did not receive any consideration in respect of their equity interests;

•

The $1.3 billion of indebtedness, including accrued interest, attributable to our Senior Notes were exchanged for New Common Stock. In addition, we reserved shares of New Common Stock to be exchanged in settlement of $2.4 million of certain general unsecured claims. In aggregate, the shares of New Common Stock issued or to be issued in settlement of the Senior Note and these general unsecured claims represented approximately 90% of outstanding Successor common shares;

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We completed a rights offering backstopped by certain holders of our Senior Notes (the “Backstop Parties”) which generated $50.0 million of gross proceeds. The rights offering resulted in the issuance of New Common Stock, representing approximately nine percent of outstanding Successor common shares, to holders of claims arising under the Senior Notes and to the Backstop Parties;

•

In connection with the rights offering described above, the Backstop Parties received approximately one percent of outstanding Successor common shares as a backstop fee;

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Additional shares, representing seven percent of outstanding Successor common shares on a fully diluted basis, were authorized for issuance under a new management incentive plan;

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Warrants to purchase 140,023 shares of New Common Stock were issued to Mr. Mark Fischer, our founder and former Chief Executive Officer, with an exercise price of $36.78 per share and expiring on June 30, 2018. The warrants were issued in exchange for consulting services provided by Mr. Fischer;

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Our Prior Credit Facility, previously consisting of a senior secured revolving credit facility with an outstanding balance of $444 million prior to emergence, was restructured into the Exit Credit Facility consisting of the Exit Revolver and the Exit Term Loan. On the Effective Date, the entire balance on the Prior Credit Facility was repaid while we received gross proceeds representing the opening balances on our Exit Revolver of $120 million and an Exit Term Loan of $150 million;

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We paid $7.0 million for creditor-related professional fees and also funded an $11.0 million segregated account for debtor-related professional fees in connection with the reorganization related transactions described above. Funds in the segregated account have been fully disbursed;

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Certain other priority or convenience class claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claimholders;

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Plaintiffs to one of our royalty owner litigation cases, which were identified as a separate class of creditors (Class 8) in our bankruptcy case, rejected the Reorganization Plan. If the claimants under Class 8 are permitted to file a class of proof claim on behalf of the putative class, certified on a class basis, and the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgement or settlement of the claims would be satisfied through issuance of Successor common shares. See “Note 16—Commitments and contingencies” in Item 1. Financial Statements of this report for a discussion of the litigation.

In support of the Reorganization Plan, the Company estimated the enterprise value of the Successor to be in the range of $1.05 billion to $1.35 billion, which was subsequently approved by the Bankruptcy Court.

Fresh Start Accounting. Our emergence from bankruptcy and the resulting adoption of fresh start accounting had a material impact on our consolidated statement of operations mainly due to a gain of $642 million resulting from an increase in carrying value of our net assets to their fair value combined with the a $372 million gain on settlement of liabilities subject to compromise, both of which were recognized during the Predecessor period in 2017. Significant increases in carrying value of our assets in connection with fresh-start accounting included the following:

• $560 million increase in our unevaluated oil and gas properties primarily to capture the value of our acreage in our STACK resource play;

• $60 million increase in our proved oil and gas properties; and

• $19 million increase in other property and equipment.

Joint development agreement

On September 25, 2017, we entered into a joint development agreement (“JDA”) with BCE Roadrunner, LLC, a wholly-owned subsidiary of Bayou City Energy (“BCE”), pursuant to which BCE will fund 100 percent of our drilling, completion and equipping costs associated with 30 STACK wells subject to well cost caps that vary by well-type across location and targeted formations, ranging from $3.4 million to $4.0 million per gross well. The cost caps may be increased up to 20% by mutual agreement. The JDA wells, which will be drilled and operated by us, include 17 initially identified locations in Canadian County (in the Meramec and Woodford formations) and 13 locations in Garfield County (in the Osage and Meramec formations), with the option to expand the JDA to drill additional wells in the future. The JDA provides us with a means to accelerate the delineation of our position within our promising Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and potentially adding reserves. In exchange for funding, BCE will receive wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retain 15%) until the program reaches a 14% internal rate of return (“the hurdle rate”). Once achieved, ownership interest in all wells will revert such that we will own a 75% working interest and BCE will retain a 25% working interest. We will retain all acreage and reserves outside of the wellbore, with both parties paying their respective share of lease operating expenses. As of December 31, 2017, we had drilled and completed three wells and had drilled a fourth well to be completed in 2018. We expect the remaining 26 wells will be drilled in 2018

2018 Outlook

Crude oil. The global oil and gas industry is cyclical, and crude oil prices are volatile, driven by crude oil supply, which includes OPEC and non-OPEC producers, and global crude oil demand. In 2014, our industry entered a downturn due to an oversupply of crude oil production from non-OPEC producers, primarily driven by US unconventional oil production growth from tight formations and the de-bottlenecking of transportation infrastructure. Coupled with OPEC’s decision not to reduce production quotas and muted global crude oil demand growth, crude oil prices began falling rapidly in late 2014.The rapid decline in crude oil prices impacted US and other non-OPEC producers’ capital budgets, which resulted in lower crude oil production. Further, in late 2016, OPEC announced voluntary production curtailments in an effort to stabilize excess crude oil supply and crude oil prices and to rebalance crude oil inventories. The decline in supply from these producers has aided in stabilizing the crude oil market. As a result, crude oil prices have recently recovered to three-year record highs, while production from the US has increased, allowing US producers to absorb global market share. Global crude oil products demand has increased, supported by lower crude oil prices and a synchronized global economic recovery, leading to increased refinery utilization and crude oil demand. Increased demand has further contributed to stabilizing crude oil prices. The outlook for 2018 crude oil prices will continue to depend on supply and demand dynamics, as well as global geopolitical and security factors in crude oil-producing nations. Reductions in industry investment, particularly for conventional crude oil development, will, over time, contribute to production declines, helping to balance supply and demand in the crude oil market.

Natural gas. The US domestic natural gas market remains oversupplied as domestic production has continued to grow due to drilling efficiencies, completion of DUC well inventory and de-bottlenecking of transportation infrastructure. In contrast to crude oil supply curtailments, there has been little to offset natural gas supply growth, which continues to outpace demand domestically. As a result, natural gas prices remained range-bound in 2017. We expect this situation to continue into 2018, with natural gas prices at or near current or recent trading levels.

Third party oilfield service and supply costs are also subject to supply and demand dynamics. During 2017, increases in US onshore drilling and completion activity resulted in higher demand for oilfield services. As a result, the costs of drilling, equipping and operating wells and infrastructure experienced some inflation, which, along with commodity prices, impacted industry operating margins.

Price Uncertainty and the Full-Cost Ceiling Impairment

The current oil price environment is characterized by a high degree of volatility and uncertainty. Modest commodity price improvement has increased our per barrel equivalent price by approximately 24% in 2017 as compared to 2016. In an environment of continued price volatility, the current modest price improvement trend could stall, or the industry could enter another downturn causing additional material negative impacts on our revenues, profitability, cash flows, liquidity, and reserves, and we could consider further reductions in our capital program or dividends, asset sales or additional organizational changes.

We deal with volatility in commodity prices primarily by working to make our overall cost structure competitive and supportive in a $50/bbl to $60/bbl oil price environment. In addition, we maintain flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility. We also deal with price volatility by hedging a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. We currently have derivative contracts in place for a portion of oil and natural gas production from 2018 through 2021(see Item 7A. Quantitative and Qualitative Disclosures About Market Risk).

Price volatility also impacts our business through the full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. Since the prices used in the cost ceiling are based on a trailing 12-month period, the full impact of price changes on our financial statements is not recognized immediately but will be spread over several reporting periods. The year-end trailing 12-month price over the past 3 years is as follows:

	2017		2016		2015
Oil (per Bbl)	$	51.34	$	42.75	$	50.28
Natural gas (per Mcf)	$	2.98	$	2.49	$	2.58
Natural gas liquids (per Bbl)	$	24.17	$	13.47	$	15.84

Due to decreasing average prices, we recorded ceiling test write-downs of $1.5 billion and $281.1 million in 2015 and 2016, respectively. During 2017, we recorded a ceiling test impairment of $42.1 million primarily due to the loss of reserves from our EOR asset sale.

In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Capital Program

Our 2017 oil and natural gas capital expenditures of $212.5 million, was comprised of $37.3 million and $175.2 million during the Predecessor and Successor periods, respectively, compared to our 2017 budget of $191.0 million and to our 2016 expenditure of $149.4 million. The increase in capital expenditure was driven by (i) our emergence from bankruptcy, (ii) a modest commodity price recovery in 2017 compared to the historic lows in 2016, (iii) attractive opportunities for selective leasehold acquisitions to strengthen our position in the STACK, and (iv) increased activity from other STACK operators resulting in an increase of our outside operated drilling. In addition, cost inflationary pressures driven by the modest industry recovery have also led to an increase in capital expenditure. Our 2017 capital expenditure included costs to drill and complete 22 wells, complete three wells which were drilled in 2016, drill three wells which will be completed in 2018, and to participate in outside operated wells, all within our STACK play. Capital was also utilized for continuing development of our Active EOR properties up to the time the assets were sold and on selective leasehold acquisitions. In addition to these activities, we also conducted development under our JDA which included drilling and completing three wells and drilling a fourth to be completed in 2018. We began 2017 with one rig, added a second rig in March and ran both rigs through the end of the year. We added a third rig at the beginning of 2018 and plan to run all three throughout 2018, with one rig deployed toward drilling JDA wells.

Our capital budget for 2018 is $255 million consisting of $252 million budgeted for acquisition and development of oil and natural gas properties and $3 million budgeted for plant and equipment. The goal of our 2018 capital program is to delineate and increase our understanding of and therefore demonstrate the value of our extensive STACK acreage position in Canadian and Garfield counties, while growing production. Approximately two thirds of our capital budget will be allocated to drilling and completions in our STACK play where we intend to drill and/or complete 35 gross operated wells and participate in outside operated drilling. Of the 35 wells, we plan to drill 15 in Garfield County, 12 in Canadian County and at least eight in Kingfisher County, all in Oklahoma. We also expect to drill the remaining 26 gross wells under our JDA (13 wells each in Canadian and Garfield Counties, Oklahoma). The remaining one third of our capital budget is allocated toward acquisitions, which includes the 7,000 acre acquisition in Kingfisher County discussed earlier.

Results of Operations

Overview

Total commodity sales increased in 2017 from historic lows in 2016 due to a modest recovery in commodity prices which more than offset a year over year decrease in production. Production has declined each year from 2015 to 2017 as our capital development has not been sufficient enough to offset natural decline during that time period. In addition, our decrease in 2017 production was also attributable to the sale of our EOR assets in November 2017. Our net loss of $118.9 million during the Successor period of 2017 was primarily a result of our ceiling test impairment of $42.1 million, the loss on the sale of our EOR assets of $25.2 million and losses on our derivative contracts of $30.8 million. Net income of $1.0 billion during the Predecessor period in 2017 was primarily due to our bankruptcy and subsequent emergence which resulted in material gains from the forgiveness of debt of $372.1 million and from the increase in book value of our assets as a result of fresh start accounting of $641.7 million.

We recorded ceiling test impairments of $281.1 million and $1.5 billion in 2016 and 2015, respectively, which along with lower commodity sales and interest expense from a larger debt burden, primarily caused our net losses of $415.7 million and $1.3 billion during those periods. In addition, our operating results benefited from a hedging program that yielded $153.8 million and $233.6 million in settlement gains during 2016 and 2015, respectively.

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through		Year ended December 31,
(dollars in thousands)	December 31, 2017			March 21, 2017		2016			2015
Production (MBoe)		6,603			1,796		8,926			10,200
Commodity sales	$	226,493		$	66,531	$	252,152		$	324,315
Net (loss) income	$	(118,902	)	$	1,041,959	$	(415,720	)	$	(1,333,844	)
Cash flow from operations	$	84,969		$	14,385	$	47,167		$	19,608

Production

Production volumes by area were as follows (MBoe):

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
STACK Areas
STACK - Kingfisher County		1,676		423		1,515		916
STACK - Canadian County		680		142		661		672
STACK - Garfield County		339		57		407		284
STACK - Other		113		34		140		149
Total STACK Areas		2,808		656		2,723		2,021
EOR Areas		1,317		445		2,068		2,136
Other		2,478		695		4,135		6,043
Total		6,603		1,796		8,926		10,200

Production decreased in 2017 compared to 2016 due to production declines in all our areas outside the STACK driven by well decline and divestitures. Production in our STACK play increased as a result of 28 new operated wells coming online during the year, which included three JDA wells, and our participation in new outside-operated wells. With $37.3 million of capital directed to our Active EOR Areas in 2017, production remained relatively flat until the assets was sold in November 2017, which resulted in a decline in production on a year over year basis. Production declines were most pronounced in our Other Areas due to a lack of capital spending as our capital activity in 2017 was focused on developing wells in our higher-return STACK area.

Production decreased in 2016 compared to 2015 due to production declines in all our areas outside the STACK. Areas outside the STACK experienced declining production due to a decrease in development activity. Production in our STACK play increased as a result of the 16 additional wells that we completed in 2016 and our participation in new outside-operated wells in that play. We did not direct any significant capital to areas outside the STACK other than to expand a limited number of new patterns at our North Burbank Unit and for the purchase of CO ₂ and maintenance within our Active EOR Areas. Increases in production at our North Burbank Unit as a result of ongoing investment partially mitigated the decreases experienced at our Booker, Camrick and Farnsworth units.

Revenues

The following table presents information about our commodity sales before the effects of commodity derivative settlements:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
Commodity sales (in thousands)
Oil	$	171,088	$	51,847	$	196,660	$	255,389
Natural gas		29,471		9,140		34,369		45,560
Natural gas liquids		25,934		5,544		21,123		23,366
Total	$	226,493	$	66,531	$	252,152	$	324,315
Production
Oil (MBbls)		3,535		1,036		4,870		5,519
Natural gas (MMcf)		11,552		3,046		15,889		18,788
Natural gas liquids (MBbls)		1,143		252		1,408		1,550
MBoe		6,603		1,796		8,926		10,200
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	48.40	$	50.05	$	40.38	$	46.27
Natural gas per Mcf	$	2.55	$	3.00	$	2.16	$	2.42
Natural gas liquids per Bbl	$	22.69	$	22.00	$	15.00	$	15.07
Average sales price per Boe	$	34.30	$	37.04	$	28.25	$	31.80

The relative impact of changes in commodity prices and sales volumes on our commodity sales before the effects of hedging is shown in the following table:

	Year ended December 31,
	2017 vs. 2016						2016 vs. 2015
(dollars in thousands)	Sales change			Percentage change in sales			Sales change			Percentage change in sales
Change in oil sales due to:
Prices	$	38,349			19.5	%	$	(28,697	)		(11.2	)%
Production		(12,074	)		(6.1	)%		(30,032	)		(11.8	)%
Total change in oil sales	$	26,275			13.4	%	$	(58,729	)		(23.0	)%
Change in natural gas sales due to:
Prices	$	7,035			20.5	%	$	(4,161	)		(9.1	)%
Production		(2,793	)		(8.1	)%		(7,030	)		(15.4	)%
Total change in natural gas sales	$	4,242			12.4	%	$	(11,191	)		(24.5	)%
Change in natural gas liquids sales due to:
Prices	$	10,550			49.9	%	$	(102	)		(0.4	)%
Production		(195	)		(0.9	)%		(2,141	)		(9.2	)%
Total change in natural gas liquid sales	$	10,355			49.0	%	$	(2,243	)		(9.6	)%

Commodity sales increased from 2016 to 2017 as prices increased significantly for all three commodities which offset a decline in volumes produced. As discussed above, production declined within our Active EOR Areas due to its divestiture prior to the end of the year while production declined in our Other Areas due to a lack of capital spending as our capital activity in 2017 was focused on developing wells in our higher-return STACK area.

Commodity sales decreased from 2015 to 2016 due to both price and production declines on all three commodities. Production declines had a slightly larger role in causing the revenue decrease. Production declines in oil and natural gas were most pronounced in our Other Areas. As discussed above, these decreases were due to a lack of capital spending in these plays as our capital activity in 2016 was focused on developing wells in our higher-return STACK area.

Derivative Activities

We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements on realized prices:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
	December 31, 2017			March 21, 2017			2016 (1)			2015
Oil (per Bbl): (2)
Before derivative settlements	$	48.40		$	50.05		$	34.69		$	39.43
After derivative settlements	$	52.24		$	51.20		$	52.63		$	68.13
Post-settlement to pre-settlement price		107.9	%		102.3	%		151.7	%		172.8	%
Natural gas (per Mcf):
Before derivative settlements	$	2.55		$	3.00		$	2.16		$	2.42
After derivative settlements	$	2.73		$	3.03		$	3.75		$	4.05
Post-settlement to pre-settlement price		107.1	%		101.0	%		173.6	%		167.6	%

(1)	For 2016, “after derivative settlements” excludes early termination settlement proceeds from contracts maturing after 2016.

(2)	The 2015 and 2016 periods include natural gas liquids.

The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

	Successor			Predecessor
	As of December 31,			As of December 31,
(in thousands)	2017			2016
Derivative (liabilities) assets:
Crude oil derivatives	$	(13,404	)	$	(9,895	)
Natural gas derivatives		278			(3,474	)
Net derivative (liabilities) assets	$	(13,126	)	$	(13,369	)

We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Non-hedge derivative (losses) gains” in the consolidated statements of operations. The fluctuation in non-hedge derivative (losses) gains from period to period is due primarily to the significant volatility of oil and natural gas prices and basis differentials and to changes in our outstanding derivative contracts during these periods. The effects of derivative activities on our results of operations and cash flows were as follows:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through		Year ended December 31,
(in thousands)	December 31, 2017			March 21, 2017		2016			2015
Non-hedge derivative (losses) gains	$	(30,802	)	$	48,006	$	(22,837	)	$	145,288

	Successor					Predecessor
	Period from March 22, 2017					Period from January 1, 2017
	through December 31, 2017					through March 21, 2017
(in thousands)	Non-cash fair value adjustment			Settlement gains		Non-cash fair value adjustment		Settlement gains
Non-hedge derivative (losses) gains:
Crude oil derivatives	$	(46,327	)	$	13,593	$	42,819	$	1,192
Natural gas derivatives		(151	)		2,083		3,902		93
Non-hedge derivative (losses) gains	$	(46,478	)	$	15,676	$	46,721	$	1,285

	Predecessor
	Year ended December 31,
	2016					2015
(in thousands)	Non-cash fair value adjustment			Settlement gains		Non-cash fair value adjustment			Settlement gains
Non-hedge derivative (losses) gains:
Crude oil derivatives	$	(132,963	)	$	113,852	$	(95,565	)	$	202,889
Natural gas derivatives		(43,644	)		39,918		7,248			30,716
Non-hedge derivative (losses) gains	$	(176,607	)	$	153,770	$	(88,317	)	$	233,605

In February 2018, we renegotiated the fixed pricing of certain crude oil swaps scheduled to settle during 2018 in exchange for entering crude oil swaps, scheduled to settle from 2020 through 2021, at lower-than-market pricing. The renegotiated swaps cover 1,086 MBbls and have a new fixed price of $60.00 per barrel, replacing the original weighted average fixed price of $54.80 per barrel. The new crude oil swaps scheduled to settle in 2020 and 2021 have weighted average fixed prices of $46.26 and $44.34 per barrel, respectively, and cover 543 MBbls each year. On February 7, 2018, the date we entered into the 2020 and 2021 swaps, the average 2020 and 2021 NYMEX strip price for crude oil was $52.68 and $50.83 per barrel, respectively.

In March 2015, we entered into early terminations of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 and 2017 and covering 495 MBbls of oil and 12,280 BBtu of natural gas for net proceeds of $15.4 million in order to maintain compliance with the hedging limits imposed by covenants under our Prior Credit Facility.

In May 2016 all of our outstanding derivative contracts were terminated early as a result of our defaults under the master agreements governing our derivative contracts. The derivative defaults were triggered by defaults on our debt. The early-terminated contracts, originally scheduled to settle from 2016 through 2018, covered 3,400 MBbls of oil and 28,800 BBtu of natural gas. Proceeds from the early terminations, inclusive of amounts receivable at the time of termination for previous settlements, totaled $119.3 million. Of this amount, in the third quarter of 2016, $103.6 million was utilized to offset outstanding borrowings under our Prior Credit Facility and the remainder was remitted to the Company. Realized gains (losses) from early terminations are reflected in “Settlement gains” in the table above.

Lease Operating Expenses

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
(in thousands, except per Boe data)	December 31, 2017		March 21, 2017		2016		2015
Lease operating expenses:
STACK Areas	$	12,694	$	2,247	$	10,414	$	9,441
EOR Areas		25,196		8,488		35,548		37,829
Other		34,242		9,206		44,571		63,389
Total lease operating expenses	$	72,132	$	19,941	$	90,533	$	110,659
Lease operating expenses per Boe:
STACK Areas	$	4.52	$	3.43	$	3.82	$	4.67
EOR Areas	$	19.13	$	19.07	$	17.19	$	17.71
Other	$	13.82	$	13.25	$	10.78	$	10.49
Lease operating expenses per Boe	$	10.92	$	11.10	$	10.14	$	10.85

Lease operating costs (“LOE”) are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices. Our EOR projects were more expensive to operate than traditional industry operations due to the nature of operations along with the costs of recovery and recycling of CO ₂ .

LOE is not comparable across the time periods presented above in part due to our recognition of bonus expense. Provisions set by the Bankruptcy Court during the pendency of our bankruptcy prevented us from paying bonuses in the ordinary course of business. Pursuant to these provisions, we did not accrue bonuses during 2016 and during the entire pendency of our bankruptcy. Upon emergence, we recognized expense for the entire amount of our 2016 fiscal year bonus (paid in March 2017) and have since accrued an estimate of our 2017 fiscal year bonus. The bonus expense component of lease operating expense is disclosed in the table below:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
(in thousands)	December 31, 2017		March 21, 2017		2016		2015
Bonus expense	$	2,484	$	—	$	—	$	1,157

LOE for 2017, which were comprised of $72.1 million and $19.9 million for the Successor and Predecessor periods, respectively, increased from the prior year period primarily due to the bonuses accrued and paid this year. Absent the accrual for bonuses, our overall LOE on a dollar basis would have been relatively flat. Increases in our STACK play were due to new operated and outside-operated wells that came online, and were partially offset by decreases in the Active EOR and Other areas, largely due to the shut in of higher cost underperforming wells and lower production. Our LOE on a Boe basis was higher in both Successor and Predecessor periods of 2017 compared to 2016 largely due to inflation in field service costs, especially in water hauling costs, which have been rising as the industry stages a modest recovery.

LOE decreased from 2015 to 2016 primarily due to lower expense for our Other and Active EOR Areas partially offset by higher expense in our STACK Area. The decrease at our Other Areas was primarily due to decreases in production combined with a slight decrease attributable to divestiture of certain non-core assets. However, LOE for our Other Areas increased on a Boe basis from 2015 to 2016 primarily as the reduction in expense from lower production was proportionately smaller than the decrease in production. LOE for our STACK Areas increased from 2015 to 2016 primarily due increased production in this area from new wells coming online in 2016 which led to additional costs of oil field goods and services. However, our LOE in the STACK decreased significantly on a Boe basis from 2015 to 2016 as economies of scale and improved efficiencies resulted in a smaller proportionate increase in lease operating expenses compared to the increase in production volume.

Transportation and Processing Expenses

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
(in thousands, except per Boe data)	December 31, 2017		March 21, 2017		2016		2015
Transportation and processing expenses	$	9,503	$	2,034	$	8,845	$	8,541
Transportation and processing expenses per BOE	$	1.44	$	1.13	$	0.99	$	0.84

Transportation and processing expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and processing costs of gas into natural gas liquids. Transportation and processing expenses of $9.5 million and $2.0 million for the Successor and Predecessor periods in 2017, respectively, were in total higher compared to 2016 as a result of increased gas volumes in our STACK area where we have experienced higher transportation and processing costs compared to our Other operating areas. Transportation and processing costs are higher in the STACK in part due to new infrastructure being built in the area. In addition, we are also experiencing higher per unit costs associated with our non-operated wells and a larger proportion of gas production subject to fee based processing arrangements as opposed to percentage of proceeds (“POP”) arrangements. Our transportation and processing expenses were approximately flat from 2015 to 2016.

As discussed in “Note 1—Nature of operations and summary of significant accounting policies” in Item 1. Financial Statements of this report, we anticipate that our adoption in 2018 of new accounting guidance on revenue recognition will result in substantially all of our transportation and handling expenses being recorded as revenue deductions rather than as expenses in our statement of operations.

Production Taxes (which include ad valorem taxes)

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
(in thousands, except per Boe data)	December 31, 2017		March 21, 2017		2016		2015
Production taxes	$	11,750	$	2,417	$	9,610	$	9,953
Production taxes per Boe	$	1.78	$	1.35	$	1.08	$	0.98

Production taxes generally change in proportion to commodity sales. Some states offer exemptions or reduced production tax rates for horizontal drilling, enhanced recovery projects and high cost gas wells. In Oklahoma, the production tax rate on wells that spudded after July 1, 2015, is currently 2% of commodity revenues for the first 36 months and 7% thereafter.

In May and November 2017, the Oklahoma legislature passed bills that would effectively increase production taxes on certain producing wells and units in the state. The legislative change in May 2017 ended all production tax rebates for EOR operations and 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 further increased the rate on the aforementioned horizontal wells from 4% to 7%. These legislative changes resulted in an additional $1.8 million increase in production taxes during the current year and are the primary cause of the increase in production taxes from 2016 to 2017, aside from increases due to higher revenues.

Production taxes on a dollar and per Boe basis for the Successor and Predecessor periods in 2017, and in aggregate for the year, were higher than 2016 due to the same factors discussed above. Production taxes from 2015 to 2016 were relatively flat as increases in production taxes due to fewer production tax credits realized were more than offset by lower ad valorem taxes attributable to lower valuation of our oil and gas properties.

As the Oklahoma state government continues to face budgetary shortfalls, it is possible that additional production tax increases may be enacted although we are unable to predict what such increases might entail. See “Future Legislative Changes May Increase the Gross Production Tax Charged on Our Oil and Natural Gas Production” in Item 1A. Risk Factors of this report.

Depreciation, Depletion and Amortization (“DD&A”)

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
(in thousands, except per Boe data)	December 31, 2017		March 21, 2017		2016		2015
DD&A:
Oil and natural gas properties	$	82,034	$	22,193	$	111,793	$	204,692
Property and equipment		7,700		1,473		7,163		8,222
Accretion of asset retirement obligations		2,865		1,249		3,972		3,660
Total DD&A	$	92,599	$	24,915	$	122,928	$	216,574
DD&A per Boe:
Oil and natural gas properties	$	12.86	$	13.05	$	12.97	$	20.42
Other fixed assets		1.17		0.82		0.80		0.81
Total DD&A per Boe	$	14.03	$	13.87	$	13.77	$	21.23

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and future costs, and thus our DD&A rate could change significantly in the future.

The implementation of fresh start accounting upon emergence from bankruptcy whereupon the carrying value of our oil and gas properties and tangible property on our balance sheet was restated to fair value impacts the comparability of DD&A between Successor and Predecessor periods. The adjustment to reflect fair value resulted in an increase in the full cost amortization base which impacted the DD&A rate per equivalent unit of production for the period subsequent to March 21, 2017. Comparability of DD&A is also impacted by our EOR asset sale in November 2017, which resulted in the divestiture of more than half of our proved reserve volumes at the time. Notwithstanding transactions affecting comparability, overall oil and natural gas DD&A was impacted by production differences. Total production from the Successor and Predecessor periods of 2017 decreased compared to the prior year quarter which contributed to a decrease in DD&A compared to 2016.

DD&A on oil and natural gas properties decreased from 2015 to 2016 of which $25.6 million was due to lower production and $67.3 million was due to a lower rate per equivalent unit of production. Our DD&A rate per equivalent unit of production decreased

from 2015 to 2016 primarily as a result of the ceiling test write-offs that occurred during those years, which subsequently lowered the carrying value of our amortization base. Although the ceiling test impairment was larger in 2015 compared to 2016, its impact on DD&A via a lower DD&A rate was more pronounced in 2016 compared to 2015. This result arises because impairments are recorded after DD&A is assessed and therefore the full impact of our ceiling impairments in 2015 did not manifest in lower DD&A until the following year.

We record the estimated future value of a liability for an asset retirement obligation in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.

Asset Impairments

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
(in thousands)	December 31, 2017		March 21, 2017		2016		2015
Asset impairments:
Loss on impairment of oil and natural gas assets	$	42,146	$	—	$	281,079	$	1,491,129
Loss on impairment of other assets		179		—		1,393		16,207

Property impairments. We record ceiling test write-downs, as needed, when the cost center ceiling exceeds the net capitalized cost of our oil and natural gas properties at the end of a fiscal quarter. Our ceiling test write-down of $42.1 million during the Successor period of 2017 was due to our EOR asset sale and our decision to exit any future pursuit of CO ₂ enhanced oil recovery. Our ceiling test write-downs of $281.1 million and $1.5 billion recorded in 2016 and 2015, respectively, were due to the substantial decline of commodity prices that began in late 2014. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date as disclosed below:

	2017		2016		2015
Oil (per Bbl)	$	51.34	$	42.75	$	50.28
Natural gas (per Mcf)	$	2.98	$	2.49	$	2.58
Natural gas liquids (per Bbl)	$	24.17	$	13.47	$	15.84

The magnitude of our ceiling test write-down was impacted by two additional factors. The first were impairments of unevaluated non-producing leasehold. We have previously and may in the future impair and/or relinquish certain undeveloped leases prior to expiration based upon changes in exploration plans, timing and extent of development activity, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors. Such impairments result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base. Impairments of non-producing leasehold of $122.3 million, $55.1 million and $151.3 million were recorded during the Successor period of 2017, in 2016 and in 2015, respectively. The impairment during the Successor period of 2017 was primarily a result of value that was recognized on our acreage during implementation of fresh start accounting attributable to future CO ₂ enhanced oil recovery which no longer yields any future economic value subsequent to our EOR asset sale and thus written-off. The impairments in 2016 and 2015 were recorded as a result of changes in our drilling plans due to the low pricing environment and lower than expected results for certain exploratory activities which resulted in certain undeveloped properties not expected to be developed before lease expiration.

The second factor, as it relates to our impairment in 2015, was a reclassification of $70.4 million for the construction of CO ₂ delivery pipelines and facilities from unevaluated oil and natural gas properties to the full cost amortization base in 2015 in conjunction with our recognition of proved reserves from the future development of all remaining phases at our North Burbank Unit. These assets have since been divested as part of our EOR asset sale. Both factors combined to increase the carrying value of our full cost amortization base which in turn contributed to the ceiling test write-downs.

Impairment of other assets. Our impairment losses of $0.2 million and $1.4 million for the Successor period of 2017 and for 2016, respectively, were due to market adjustments on our equipment inventory. Our impairment losses for 2015 consists of write-downs of $6.0 million related to impairments of previously owned stacked drilling rigs and $10.2 million related to a market adjustment on our equipment inventory. As a result of the deterioration in commodity prices and reduced drilling activity, the value of our drilling rigs had declined while utilizing third party equipment has become more cost effective, resulting in us impairing the value of the rigs to their estimated fair value. These rigs were sold in January 2017. The industry conditions described above also caused the

demand for equipment utilized in drilling to decrease, resulting in lower market prices for such equipment. The market adjustments on our equipment inventory reflect the decrease in market prices as well as adjustments for excess and obsolescence.

General and Administrative expenses (“G&A”)

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
(in thousands, except per Boe data)	December 31, 2017			March 21, 2017			2016			2015
G&A, cost reduction initiatives and liability management expense:
Gross G&A expenses	$	49,425		$	8,117		$	26,275		$	49,734
Capitalized exploration and development costs		(9,808	)		(1,274	)		(5,322	)		(10,645	)
Net G&A expenses	$	39,617		$	6,843		$	20,953		$	39,089
Cost reduction initiatives		691			629			2,879			10,028
Liability management expenses		—			—			9,396			—
Net G&A, cost reduction initiatives and liability management expense	$	40,308		$	7,472		$	33,228		$	49,117
Net G&A expenses per Boe	$	6.00		$	3.81		$	2.35		$	3.83
Net G&A expenses, cost reduction initiatives and liability management expense per Boe	$	6.10		$	4.16		$	3.72		$	4.82

The comparability of gross G&A expenses between 2017 and 2016 is materially impacted by stock compensation and the timing of our recognition of bonus expense. Stock compensation expense during the Successor period in 2017 was due to requisite service costs under our new Management Incentive Plan which was adopted in August 2017. In contrast, we recorded a credit for stock compensation expense in 2016 primarily due to a cumulative catch up adjustment in order to reflect a decrease in the probability that requisite service would be achieved for performance shares under a previous stock incentive plan, which was subsequently cancelled upon our emergence from bankruptcy. Provisions set by the Bankruptcy Court during the pendency of our bankruptcy prevented us from paying bonuses in the ordinary course of business. Pursuant to these provisions, we did not accrue bonuses during 2016 and during the entire pendency of our bankruptcy. Upon emergence, we recognized expense for the entire amount of our 2016 fiscal year bonus (paid in March 2017) as well as accrued an estimate of our 2017 fiscal year bonus. These material adjustments affecting comparability are disclosed in the table below:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
(in thousands)	December 31, 2017		March 21, 2017		2016			2015
Bonus expense, gross	$	10,043	$	—	$	—		$	6,034
Stock compensation, gross		12,401		194		(6,196	)		(2,102	)
	$	22,444	$	194	$	(6,196	)	$	3,932

Notwithstanding the adjustments described above, gross G&A expenses were marginally higher in 2017 compared to 2016 as a result of cost increases for professional fees and for our long term cash incentive plan partially offset by decreases in salary expense due to lower headcount. Expense for our long term cash incentive plan increased as a result of additional award grants made in 2017.

Gross G&A expenses decreased from 2015 to 2016, primarily due to lower compensation and benefits costs and lower costs for equity based compensation awards. Compensation and benefits were lower due to lower headcount subsequent to our workforce reductions, which in 2016 included 48 corporate employees. Compensation was also lower in 2016 compared to the prior year as we were not able to accrue annual bonuses for 2016 due to the Bankruptcy Court provisions described previously. Expense for equity based awards decreased from 2015 to 2016 primarily due to the cumulative catch up adjustment on performance shares discussed previously. Other than compensation and benefits, we had reductions across several other G&A categories in 2015 and 2016 in line with our initiatives to reduce costs in the current environment.

Capitalized exploration and development costs decreased from 2015 to 2016 and increased from 2016 to 2017 due to the overall fluctuation in gross G&A over that time.

Cost Reduction Initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the industry downturn. These expenses include one-time severance and termination benefits in connection with our reductions in force as well as third party legal and professional services we have engaged to assist in these initiatives as follows (in thousands):

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
One-time severance and termination benefits	$	678	$	608	$	2,772	$	7,757
Professional fees		13		21		107		2,271
Total cost reduction initiatives expense	$	691	$	629	$	2,879	$	10,028

Liability management expense

Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 petition, such expenses, to the extent that they are incremental and directly related to our bankruptcy reorganization, are reflected in “Reorganization items” in our consolidated statements of operations.

Loss (gain) on asset sales

During the Successor period of 2017, we recognized a $26.0 million loss on sale of assets which was comprised primarily of a $25.2 million loss on our EOR asset sale which we closed in November 2017 for cash proceeds, net of preliminary post-closing adjustments, of $163.6 million. As these properties comprised a material portion of our oil and natural gas reserves and our assessment indicated that our depletion rate would be significantly altered subsequent to the sale, in accordance with the full cost method of accounting for conveyances, we recognized the aforementioned loss on the sale. Other than our recent EOR asset sale, our divestitures of oil and natural gas assets are generally below the threshold of reserve volumes sold that would trigger a requirement to recognize a gain or loss under full cost accounting rules, and hence gains or losses are generally not recorded. The remaining amounts reflected on our statement of operations are related to gains or losses from the sale of plant, property and equipment.

Restructuring expense

In conjunction with our EOR asset divestiture, we terminated 86 employees. We consider this exit activity to be a restructuring in that it has materially changed the scope and manner in which our business is conducted. We recorded $3.5 million in restructuring expense related to the divestiture which was predominantly comprised of one-time severance and termination benefits for the affected employees.

Subleases

Prior to the sale of our EOR assets in November 2017, we utilized CO ₂ compressors that were considered integral to our EOR operations and were leased under six lease agreements from U.S. Bank. In conjunction with the sale, we continued to lease the compressors, but executed sublease agreements with the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and hence we did not record any losses upon initiation of the subleases. Of the original lease agreements, three are classified as capital leases while the remaining three are classified as operating leases. Prior to the asset sale, the capital leases were included in our full cost amortization base and hence subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating expense” in our statement of operations. Based on the facts and circumstances relating to our original leases and the current subleases, we have determined that all the subleases are to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases, all payments received from the Sublessee are reflected as revenues on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as operating expenses on our statement of operations. With respect to the capital leases, we have reclassified the amount associated with these leases from the full cost amortization base to plant, property and equipment on our balance sheet and will amortize the asset on a straight line basis prospectively. We will continue incurring interest expense on the capital leases.

Reorganization Items

Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the Chapter 11 reorganization of the business. Subsequent to our emergence from bankruptcy, we have incurred professional fees for the ongoing resolution of outstanding claims. While we expect these fees to decrease in the future, we will continue incurring them until our outstanding claims are resolved. Reorganization costs are as follows (in thousands):

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through			Year ended
	December 31, 2017		March 21, 2017			December 31, 2016
Gains on the settlement of liabilities subject to compromise	$	—	$	(372,093	)	$	—
Fresh start accounting adjustments		—		(641,684	)		—
Professional fees		3,091		18,790			15,484
Claims for non-performance of executory contract		—		—			1,236
Rejection of employment contracts		—		4,573			—
Write off unamortized issuance costs on Prior Credit Facility		—		1,687			—
Total reorganization items	$	3,091	$	(988,727	)	$	16,720

Other Income and Expenses

Interest expense . The following table presents interest expense for the periods indicated:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
(in thousands)	December 31, 2017			March 21, 2017			2016			2015
New Credit Facility and Exit Revolver	$	5,232		$	—		$	—		$	—
Exit Term Loan including amortization of discount		9,179			—			—			—
Senior Notes		—			—			37,048			107,373
Prior Credit Facility		—			5,193			24,228			9,608
Bank fees, other interest and amortization of issuance costs		1,878			917			5,105			5,089
Capitalized interest		(2,142	)		(248	)		(2,139	)		(9,670	)
Total interest expense	$	14,147		$	5,862		$	64,242		$	112,400
Average long-term borrowings (including amounts subject to compromise)	$	281,624		$	1,678,870		$	1,717,369		$	1,688,859

The comparability of interest expense across time periods in 2017 and 2016 is impacted by our bankruptcy and subsequent emergence. During the Successor period of 2017, we incurred interest related to our Exit Revolver, Exit Term Loan and New Credit Facility whereas these facilities had not been established prior to our emergence from bankruptcy. During the Predecessor period of 2017, 2016 and 2015, we incurred interest related to our Prior Credit Facility. We ceased recorded interest on our Senior Notes in May 2016 upon the filing of our bankruptcy petition.

Interest expense in total for the Successor and Predecessor periods of 2017 was lower than 2016 due to the absence of expense on the Senior Notes as the accrual of interest was suspended while in bankruptcy (May 2016 – March 2017) and the debt was subsequently discharged upon emergence (March 2017).

Total interest expense decreased from 2015 to 2016 as a result of lower interest expense on our Senior Notes, discussed above, partially offset by an increase in interest on our Prior Credit Facility due to increased levels of borrowing and higher interest rates as well as a reduction in capitalized interest.

Capitalized interest for the Successor and Predecessor periods of 2017 were marginally higher in total than 2016 as a result of a larger average balance in unevaluated non-producing leasehold. The reduction in capitalized interest from 2015 to 2016 was a result of a lower average balance of unevaluated non-producing leasehold subsequent to the leasehold impairments recorded in 2015 and 2016. As a result of applying fresh start accounting upon our emergence from bankruptcy, the carrying value of our unevaluated non-producing leasehold was significantly increased to reflect the fair value of our acreage in the STACK. For the Successor period and in future periods subsequent to the adoption of fresh start accounting, we will not be capitalizing interest related to the fresh start gross

up of the carrying value of unevaluated acreage as capitalized interest will only be calculated based on the carrying value of actual purchased leasehold.

Gain on extinguishment of debt . In conjunction with the payment in full of our Exit Term Loan in November 2017, we wrote off the remaining $0.6 million balance of unamortized discount associated with the loan. During December 2015, we repurchased approximately $42.0 million of principal value of our outstanding Senior Notes on the open market for $10.0 million in cash. As a result, we recorded a $31.6 million gain on extinguishment of debt, which included retirement of unamortized issuance costs, discounts and premiums associated with the repurchased debt.

Senior Note issuance costs, discount and premium. In March 2016, we wrote off the remaining unamortized issuance costs, premium and discount related to our Senior Notes for a net charge of approximately $17.0 million. These deferred items are typically amortized over the life of the corresponding bond. However, as a result of not paying the interest due on our 2021 Senior Notes by the end of our 30-day grace period on March 31, 2016, we triggered an Event of Default on our Senior Notes. While uncured, the Event of Default effectively allowed the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount.

Income Taxes

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through		Year ended December 31,
(dollars in thousands)	December 31, 2017			March 21, 2017		2016			2015
Current income tax (benefit) expense	$	(349	)	$	37	$	(102	)	$	174
Deferred income tax (benefit) expense		—			—		—			(177,393	)
Total income tax (benefit) expense	$	(349	)	$	37	$	(102	)	$	(177,219	)
Effective tax rate		—			—		—			11.7	%
Total net deferred tax liability	$	—		$	—	$	—		$	—

Our income tax benefit recognized for the year ended December 31, 2017, is a result of a Texas margin tax refund for 2016 and federal refundable alternative minimum credits for the 2016 tax year.

On December 22, 2017, the Tax Cuts and Jobs Act (the “2017 Tax Act”) was enacted. The 2017 Tax Act represents major tax reform legislation that, among other provisions, reduces the U.S. federal corporate tax rate. The reduction in the U.S. federal corporate tax rate will likely reduce our effective tax rate in future periods. As a result of the 2017 Tax Act, we remeasured our December 31, 2017, deferred tax assets and liabilities, resulting in a $111.2 million decrease in net deferred tax assets for the year ended December 31, 2017. A corresponding change was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense. For further information on the financial statement impact of the 2017 Tax Act and Staff Accounting Bulletin No. 118, see “Note 12—Income taxes” in Item 8. Financial Statements and Supplementary Data in this report.

Our effective tax rate is affected by changes in valuation allowances, recurring permanent differences and discrete items that may occur in any given year but are not consistent from year to year. At December 31, 2017 and 2016, we have a full valuation allowance for the amounts by which our deferred tax assets exceed our deferred tax liabilities due to uncertainty regarding their realization. We intend to maintain a valuation allowance on our net deferred tax assets until there is sufficient evidence to support the reversal of these allowances. As long as we conclude that the valuation allowance against our net deferred tax assets is necessary, we likely will not have any additional deferred income tax expense or benefit. For further discussion of our valuation allowance, see “Note 12—Income taxes” in Item 8. Financial Statements and Supplementary Data in this report.

Our federal net operating loss carryforwards were approximately $919.1 million as of December 31, 2017, which will expire between 2028 and 2037 if not utilized in earlier periods. As of December 31, 2017, our state net operating loss carryforwards were approximately $1.12 billion, which will expire between 2018 and 2037 if not utilized in earlier periods.

Our ability to utilize our loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “IRC”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, and Section 382 of the IRC imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards after an ownership change. We did not have a Section 382 limitation on our ability to utilize our loss carryforwards as of December 31, 2016. In 2017, however, upon emergence from bankruptcy, as described in “Note 3—Chapter 11 reorganization,” we experienced an ownership change that may limit the availability of our loss carryforwards to fully offset taxable income in future years. For further discussion of the impact of our emergence from bankruptcy on the amount and availability of our loss carryforwards, see “Note 12—Income taxes” in Item 8. Financial Statements and Supplementary Data in this report. Future equity

transactions involving us or our stockholders (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes, further limiting the availability of our loss carryforwards to reduce future taxable income.

Liquidity and Capital Resources

Our internal sources of liquidity in 2017 included cash flows from operations, receipts from commodity derivatives and asset divestitures. In 2017, asset divestitures were a significant source of liquidity generating approximately $191.6 million in proceeds, most of which was comprised of proceeds from the sale of our EOR assets in November 2017. Our external sources of liquidity are comprised of outstanding debt and occasional issuances of equity. Our Reorganization Plan, which was effective March 21, 2017, included an equity offering of $50 million which we utilized for repayment of pre-emergence debt.

We rely on cash flows from operations to fund our capital program which includes exploration and development, leasehold and property acquisitions. Our industry requires that we continuously commit substantial investment to drill and develop our oil and natural gas properties such that production from new wells can offset the natural production decline from existing wells. During the past three years, cash flows from operations have been insufficient to fully fund our capital programs and instead were augmented by derivative receipts, asset sales and debt.

Our cash balance as of December 31, 2017, was $27.7 million and we had borrowing availability under our New Credit Facility of $157.1 million. As of March 22, 2018, our cash balance was approximately $21.8 million with $206.1 million outstanding on our New Credit Facility and borrowing availability of $78.1 million. We continuously monitor our liquidity needs, coordinate our capital expenditure program with our expected cash flows, and evaluate our available alternative sources of liquidity. We believe that we have sufficient liquidity to fund our capital expenditures and day to day operations at a minimum for the next 12 months.

Our cash flows and liquidity are highly dependent on the prices we receive for oil, natural gas and NGLs. Prices we receive are determined by prevailing market conditions, regional and worldwide economic and geopolitical activity, supply versus demand, weather, seasonality and other factors that influence market conditions and often result in significant volatility in commodity prices. In addition to reducing revenue from commodity sales, low prices can adversely affect our liquidity through the impact on the borrowing base under our credit facilities. When commodity prices decline, the price deck approved by our lenders to determine our borrowing base decreases which leads to a reduction in our borrowing base and hence the available amount we can borrow.

We mitigate the impact of volatility in commodity prices, in part through the use of derivative instruments which help stabilize our cash flow. We currently have derivative contracts in place for oil and natural gas production from 2018 through 2021(see Item 7A. Quantitative and Qualitative Disclosures About Market Risk).

Sources and Uses of Cash

Our net (decrease) increase in cash is summarized as follows:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
(dollars in thousands)	December 31, 2017			March 21, 2017			2016			2015
Cash flows provided by operating activities	$	84,969		$	14,385		$	47,167		$	19,608
Cash flows provided by (used in) investing activities		47,735			(28,010	)		(54,309	)		(37,258	)
Cash flows (used in) provided by financing activities		(150,095	)		(127,732	)		176,557			3,223
Net (decrease) increase in cash during the period	$	(17,391	)	$	(141,357	)	$	169,415		$	(14,427	)

Our operating cash flow is derived substantially from the production and sale of oil and natural gas and therefore influenced by the prices we receive and the quantity we produce. Our cash flows from operating activities are also impacted by changes in working capital.

Our cash flows from operating activities for 2017, which included inflows of $85.0 million for Successor period and $14.4 million for the Predecessor period, increased over the prior year as a result of an increase in revenues, a reduction in cash interest paid, and working capital changes. These increases were partially offset by higher operating and bankruptcy related expenses in the current year.

Our cash flows from operations were higher in 2016 compared to 2015 primarily due to a reduction in cash interest paid. During 2016, we elected not to make interest payments on our Senior Notes that were due on March 1 and April 1, 2016, resulting in defaults on the Senior Notes. Upon filing the Chapter 11 Cases, we suspended interest payments on the Senior Notes for the remainder of the bankruptcy. As a result, we did not pay any cash interest related to our Senior Notes in 2016 which led to a year over year decrease in cash interest paid of $90.6 million. The increase in operating cash flows due to our nonpayment of interest was offset by a decline in

revenues due to lower prices and production. In addition, although we were able to generate cash savings by reducing recurring expenses such as lease operating and general and administrative expenses, these savings were more than offset by costs we incurred to restructure our debt and in connection with our bankruptcy.

Net cash provided by investing activities during the Successor period of 2017 was comprised of cash inflows from derivative settlement receipts of $15.7 million and from asset sales of $189.7 million (primarily our EOR asset sale) partially offset by cash outflows for capital expenditure of $157.7 million. Net cash used in investing activities during the Predecessor period from January 1 to March 21, 2017, was comprised of cash outflows for capital expenditure of $31.2 million partially offset by cash inflows from derivative settlement receipts of $1.3 million and from asset sales of $1.9 million. During 2016, cash used in investing activities was comprised of cash outflows for capital expenditure of $146.3 million, which included paydown of accounts payable, partially offset by cash inflows from derivative settlements of $90.6 million and asset dispositions of $1.3 million. During 2015, cash used in investing activities was comprised of cash outflows for capital expenditure of $313.5 million, which included paydown of accounts payable, partially offset by cash inflows from derivative settlements of $233.6 million and asset dispositions of $42.6 million. Our significant receipts from derivative settlements in 2015 were the result of a robust hedging program in response to the low prices that prevailed during 2015.

Cash flows used in financing activities during the Successor period of 2017, is comprised primarily of cash outflows of $178.4 million for repayments on debt and capital leases and outflows of $4.7 million for debt issuance costs partially offset by cash inflows of $33.0 million from borrowings. The debt repayment includes $149.2 million for the repayment in full of our Exit Term Loan utilizing proceeds of our EOR asset sale while the debt issuance costs were incurred in connection with the amendment of our credit facility in December 2017. Cash flows used in financing activities during the Predecessor period of 2017 is comprised primarily of cash outflows for repayments of debt and capital leases of $445.4 million and payment of $2.4 million in debt issuance costs for our Exit Credit Facility partially offset by cash inflows of $270.0 million from new borrowings and $50.0 million from the issuance of equity. The large repayments and borrowings of debt during the Predecessor period in 2017 reflect the extinguishment of our Prior Credit Facility and establishment of our Exit Credit Facility pursuant to our Reorganization Plan.

Cash flows from financing activities in 2016 included borrowing and repayments on our long-term debt of $181.0 million and $1.9 million, respectively, and payment of $2.5 million on our capital leases. During 2016, the outstanding balance on our Prior Credit Facility was reduced by $103.6 million by directly offsetting proceeds payable to us from the termination of our derivative contracts against outstanding borrowings under the Prior Credit Facility. The ability to offset was possible as the previous counterparties to our derivative contracts were also lenders under our Prior Credit Facility. Since cash was not exchanged in this transaction, it is not reflected in the statement of cash flows. Cash flows from financing activities in 2015 included borrowing and repayments on our long-term debt of $120.0 million and $103.0 million, respectively, and payment of $2.4 million on our capital leases. We also paid $1.4 million in bank fees in connection with the amendment to our Prior Credit Facility as well as $10.0 million to repurchase our Senior Notes on the open market.

As market conditions warrant and subject to our contractual restrictions in our revolving credit facility or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure. We may accomplish this through open market or privately negotiated transactions, which may include, among other things, private or public equity raises, rights offerings, repurchases of our common stock and refinancings. Many of these alternatives may require the consent of current lenders or, stockholders, and there is no assurance that we will be able to execute any of these alternatives on acceptable terms, or at all. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Asset sales. As noted previously , we have relied on asset divestitures as a significant source of liquidity. Our divestitures in 2017 generated $191.6 million of proceeds, while divestitures in 2015 generated $42.6 million of proceeds. Our 2018 budget contemplates additional divestitures of our non-core assets in the Oklahoma/Texas Panhandle and non-core STACK acreage, which we expect could yield between $50 million to $60 million in proceeds. Proceeds from our property sales provide us with funds to pay down our borrowings, fund capital expenditures and for general corporate purposes.

Capital Expenditures

Our actual costs incurred, including costs that we have accrued, for 2017 and our budgeted 2018 capital expenditures for oil and natural gas properties are summarized in the following table:

	Successor		Predecessor
(in thousands)	Period from March 22, 2017 through December 31, 2017		Period from January 2, 2017 through March 21, 2017		2018 Capital Expenditures Budget (1)
Acquisitions	$	34,080	$	3,431	$	94,000
Drilling		107,378		20,754		149,000
Enhancements		22,892		6,821		9,000
Pipeline and field infrastructure		3,841		3,015		—
CO ₂ purchases		6,985		3,308		—
Total		175,176		37,329		252,000
Operational Area (2):
STACK		141,291		25,467		242,000
Active EOR Areas		27,616		9,707
Other		6,269		2,155		10,000
Total	$	175,176	$	37,329	$	252,000

(1)	Budget categories presented include allocations of capitalized interest and general and administrative expenses. In addition to the amounts in this table, we have budgeted $2.9 million for other plant, property and equipment.

(2)	Costs incurred includes capitalized interest and capitalized general and administrative expenses which for the Successor and Predecessor periods in 2017 totaled $10.6 million for our STACK play, $2.4 million for our Active EOR Areas and $0.5 million for our Other Areas.

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $2.1 million for property and equipment during 2017.

We utilized our 2017 capital to drill and complete 22 wells, complete three wells that were drilled in 2016, drill three wells which will be completed in 2018 and to participate in outside operated wells, all within our STACK play. Capital was also utilized for continuing development of our Active EOR properties up to the time the assets were sold and on selective leasehold acquisitions. In addition to these activities, we also conducted development under our JDA which included drilling and completing three wells and drilling a fourth to be completed in 2018. We began 2017 with one rig, added a second rig in March and ran both rigs through the end of the year.

Our capital budget for 2018 is $255 million consisting of $252 million to be spent on acquisition and development of oil and natural gas properties and $3 million to be spent on plant and equipment. The goal of our 2018 capital program is to demonstrate the value of our extensive STACK acreage position in Canadian and Garfield counties, while growing production. Approximately two thirds of our acquisition and development budget will be allocated to drilling and completions in our STACK play where we intend to drill and/or complete 35 gross operated wells and participate in outside operated drilling. We will also drill and/or complete an additional 26 gross wells under our JDA. Our planned wells are predominantly in Canadian, Garfield and Kingfisher counties in Oklahoma. The drilling program will entail running three rigs throughout the year with one deployed towards drilling JDA wells. The remaining one third of our acquisitions and development budget is allocated toward acquisitions, which included the 7,000 acre acquisition in Kingfisher County discussed earlier.

We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 2018 may be higher or lower than our budgeted amounts. Our level of exploration and development expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors. We will continue to monitor our capital spending in 2018 closely and may adjust our spending accordingly based on actual and projected cash flows, our liquidity and our capital requirements.

Pre-emergence indebtedness

Chapter 11 Proceedings and Emergence. The bankruptcy petition constituted an event of default with respect to our pre-petition Prior Credit Facility and Senior Notes. Prior to the Petition Date, these facilities were also in default as a result of nonpayment of interest, violations of financial covenants and the inclusion of a going concern explanatory paragraph in the audit opinion of our 2015 annual financial statements. The enforcement of any obligations under our pre-petition debt was automatically stayed as a result of the Chapter 11 Cases. On the Effective Date, our obligations under the Senior Notes, including principal and accrued interest, were fully extinguished in exchange for equity in the post-emergence Company. In addition, our Prior Credit Facility, previously consisting of a senior secured revolving credit facility, was restructured into an Exit Credit Facility consisting of the Exit Revolver and the Exit Term

Loan. The material provisions under our pre-emergence Senior Notes and Prior Credit Facility are described further in “Note 8—Debt” in Item 8. Financial Statements and Supplementary Data of this report .

Reclassification of Debt. With respect to presentation on our balance sheet at December 31, 2016, the balances outstanding under our Senior Notes were classified as liabilities subject to compromise. However, balances under our Prior Credit Facility, real estate mortgage notes, installment notes and capital leases were not classified as subject to compromise as these obligations were secured. Furthermore, as a result of certain debt defaults discussed above, which occurred in early 2016 and remained uncured during the pendency of the Chapter 11 Cases, all outstanding long-term debt was classified as current as of December 31, 2016.

Our debt consists of the following as of the dates indicated:

	Successor			Predecessor
(in thousands)	December 31, 2017			December 31, 2016
New Credit Facility	$	127,100		$	—
Prior Credit Facility		—			444,440
Real estate mortgage notes		9,177			9,595
Installment notes		—			434
Capital lease obligations		14,361			16,946
Unamortized issuance costs (1)		(5,979	)		(2,303	)
Total	$	144,659		$	469,112

_________________________________

(1)	Debt issuance costs are presented as a direct deduction from debt rather than an asset pursuant to recent accounting guidance. The balance on December 31, 2017, was related to the New Credit Facility while the balance on December 31, 2016, was related to the Prior Credit Facility.

Post-emergence indebtedness

As discussed above, our post-emergence exit financing consisted of the Exit Credit Facility, which was comprised of the Exit Revolver and the Exit Term Loan, entered into on the Effective Date. The material provisions under our Exit Credit Facility are described further in “Note 8—Debt” in Item 8. Financial Statements and Supplementary Data of this report. The initial opening amounts under the Exit Credit Facility were $120 million and $150 million on the Exit Revolver and Exit Term Loan, respectively. Concurrent with the receipt of cash proceeds from the sale of our EOR assets in November 2017, we fully repaid the outstanding balance of the Exit Term Loan and paid down a portion of on the Exit Revolver in November 2017. On December 21, 2017, we amended the Exit Credit Facility by subsequently entering into the New Credit Facility.

New Credit Facility. The facility is a $400 million facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our New Credit Facility is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base on December 21, 2017, was $285 million and the first borrowing base redetermination has been set for on or about May 1, 2018. Availability on the New Credit Facility as of December 31, 2017, after taking into account outstanding borrowings and letters of credit on that date, was $157.1 million.

Interest on the outstanding amounts under the New Credit Facility will accrue at an interest rate equal to either (i) the Alternate Base Rate (as defined in the New Credit Facility) plus an Applicable Margin (as defined in the New Credit Facility) that ranges between 1.50% to 2.50% depending on utilization or (ii) the Adjusted LIBO Rate (as defined in the New Credit Facility) applicable to one, two three or six month borrowings plus an Applicable Margin that ranges between 2.50% to 3.50% depending on utilization. In the case that an Event of Default (as defined under the New Credit Facility) occurs, the outstanding amounts will bear an additional 2.00% interest plus the applicable Alternate Base Rate or Adjusted LIBO Rate and corresponding Applicable Margin.

Commitment fees of 0.50% accrue on the average daily amount of the unused portion of the borrowing base and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the Applicable Margin used to determine the interest rate applicable to borrowings that are based on Adjusted LIBO Rate.

If the outstanding borrowings under our New Credit Facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days or (2) commencing within 30 days to repay the deficiency in equal monthly installments over a six -month period or (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency or (4) any combination of repayment as provided in the preceding three elections.

The New Credit Facility contains covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our New Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others.

The financial covenants require, for each fiscal quarter ending on and after December 31, 2017, that we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the New Credit Facility) of no greater than 4.0 to 1.0 calculated on a trailing four-quarter basis. We were in compliance with these financial covenants as of December 31, 2017.

The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our New Credit Facility, we consider the current ratio calculated under our New Credit Facility to be a useful measure of our liquidity because it includes the funds available to us under our New Credit Facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives.

The following table discloses the current ratio for our loan compliance compared to the ratio calculated per GAAP:

(in thousands)	December 31, 2017
Current assets per GAAP	$	95,894
Plus—Availability under New Credit Facility		157,072
Current assets as adjusted	$	252,966
Current liabilities per GAAP	$	117,075
Less—Short term derivative instruments		(8,959	)
Less—Short-term asset retirement obligations		(2,774	)
Less—Current maturities of long term debt		(3,273	)
Current liabilities as adjusted	$	102,069
Current ratio per GAAP		0.82
Current ratio for loan compliance		2.48

________________________________

(1)	The Company did not provide financial covenant calculations to our Prior Credit Facility lender during bankruptcy while our debt was in default; hence the ratio as of December 31, 2016, is not disclosed.

Capital leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million through the sale and subsequent leaseback of existing compressors owned by us. The lease financing obligations are for 84 month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are $3.2 million annually. In conjunction with the sale of our EOR assets, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank National Association. The subleases are structured such that the lease payments and remaining lease term are identical to the original leases.

Liquidity outlook

As of March 22, 2018, our cash balance was approximately $21.8 million with $206.1 million outstanding on our New Credit Facility and borrowing availability of $78.1 million. Upon consummation of the Reorganization Plan, our capital structure has been significantly improved as it is no longer burdened by $1.2 billion of previous Senior Note debt and the associated interest obligation, which previously averaged approximately $107 million each year. The initial balance on our Exit Credit Facility of $270 million upon emergence has been paid down through the course of the year, primarily from proceeds of our EOR balance sheet and the resulting balance of our New Credit Facility of $127.1 million represents our lowest debt level in recent years. We believe our current liquidity level and balance sheet provide flexibility and positions us to fund our business throughout the commodity price cycle. Although we will continue to evaluate the commodity price environment and our level of capital spending throughout 2017, we currently believe that we are able to meet our obligations and fund our drilling plans at a minimum for the next 12 months.

Financial position

The following were material changes in our balance sheet:

	Successor		Predecessor
(in thousands)	December 31, 2017		December 31, 2016			Change
Assets
Cash and cash equivalents	$	27,732	$	186,480		$	(158,748	)
Accounts receivable, net		60,363		46,226			14,137
Property and equipment		50,641		41,347			9,294
Total oil and natural gas properties		992,353		555,184			437,169
Liabilities
Accounts payable and accrued liabilities		75,414		42,442			32,972
Accrued payroll and benefits payable		11,276		3,459			7,817
Revenue distribution payable		17,966		9,426			8,540
Long-term debt and capital leases, classified as current		3,273		469,112			(465,839	)
Long-term debt and capital leases, less current maturities		141,386		—			141,386
Asset retirement obligations (current and noncurrent)		35,990		72,137			(36,147	)
Liabilities subject to compromise		—		1,284,144			(1,284,144	)
Total stockholders' equity (deficit)		842,766		(1,042,153	)		1,884,919

•

The decrease in cash is primarily due to repayments to extinguish the Prior Credit Facility.

•

Accounts receivable increased as result of an increase in joint interest billings from our capital program.

•

The increase to property and equipment was primarily due to the adoption of fresh start accounting which resulted in increases to reflect fair value and due to the reclassification of capital leases for compressors from the full cost amortization base to into this category. These increases were partially offset by divestitures which were largely driven by the EOR asset sale.

•

The increase to oil and natural gas properties was primarily due to our adoption of fresh start accounting, which resulted in an increase in carrying value to reflect fair value, and to a lesser extent, due to capital expenditures in the current year. These increases were partially offset by amortization and the ceiling test impairment recorded during the year as well as our EOR asset sale. See “Note 4—Fresh start accounting” in Item 8. Financial Statements and Supplementary Data of this report.

•

Accounts payable and accrued liabilities are higher as a result of activity at year-end 2017 and prepayments from third parties for our operated wells received in 2017.

•

Accrued payroll and benefits payable increased primarily due to the accrual of bonuses in 2017 whereas bonuses were not accrued in 2016 as a result of certain Bankruptcy Court provision.

•

Long term debt was lower in total due to the extinguishment of the Prior Credit Facility which was subsequently replaced by the Exit Credit Facility and more recently by the New Credit Facility, ending the year at a lower outstanding balance than the prior year. Furthermore, all long term debt was previously classified as current due to the potential acceleration from being in default while in bankruptcy. Upon emergence, debt is classified as current vs. noncurrent according to scheduled repayments.

•

Asset retirement obligations decreased primarily due to our EOR asset sale where the plugging obligations related to our EOR assets have been transferred to the buyer.

•

Liabilities subject to compromise have been settled pursuant to the provisions under our Reorganization Plan by exchange of equity, payment or reinstatement.

•

Total stockholders’ equity increased as a result of the exchange of debt for equity under our Reorganization Plan, the gain from settlement of our liabilities subject to compromise and the gain from our fresh-start accounting adjustments.

Contractual obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2017:

(in thousands)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Debt:
New Credit Facility, including estimated interest and other fees	$	6,196	$	12,408	$	139,322	$	—	$	157,926
Other long-term notes, including estimated interest		1,086		2,173		2,173		7,002		12,434
Capital lease obligations, including estimated interest		3,181		12,028		—		—		15,209
Asset retirement obligations (1)		2,774		—		—		33,216		35,990
Derivative obligations		10,125		4,333		—		—		14,458
Operating lease obligations		1,365		2,691		1,575		204		5,835
Other commitments		9,332		288		—		—		9,620
Total	$	34,059	$	33,921	$	143,070	$	40,422	$	251,472

________________________________

(1)	Due to the uncertainty in the timing of our asset retirement obligations, all noncurrent amounts have been included in the “More than 5 years” category.

We rent equipment used on our oil and natural gas properties and have operating lease agreements for office equipment. Rent expense for the years ended December 31, 2017, 2016, and 2015 was $5.0 million, $6.7 million, and $8.8 million, respectively. Our operating leases include leases relating to office equipment, which have terms of up to five years, and leases on CO ₂ recycle compressors, which have terms of seven years. Amounts related to our operating lease obligations are disclosed in the table above.

Aside from operating leases, we also have capital leases for our CO ₂ recycle compressors, for which the amounts are disclosed above. In conjunction with the sale of our EOR assets, all our leased CO ₂ compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank National Association. The subleases are structured such that the lease payments and remaining lease term are identical to the original leases.

Other commitments consist of contracts in place as of December 31, 2017, that are not currently recorded on our consolidated balance sheets. The bulk of these commitments are for three drilling rig contracts that extend through mid-2018 and the purchase of seismic data.

Our contracts to purchase CO ₂ for our EOR operations were discharged upon the sale of our EOR assets.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and other sources that we believe are reasonable at the time. Actual results may differ from the estimates and assumptions we used in preparation of our financial statements. We evaluate our estimates and assumptions on a regular basis. Described below are the most significant policies and the related estimates and assumptions we apply in the preparation of our financial statements. See “Note 1—Nature of operations and summary of significant accounting policies” in Item 8. Financial Statements and Supplementary Data in this report for an additional discussion of accounting policies and estimates made by management.

Bankruptcy proceedings. We have applied Accounting Standards Codification 852 “Reorganizations” (“ASC 852”) in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization items, net” in the accompanying Consolidated Statements of Operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on our consolidated balance sheets at December 31, 2016 in “Liabilities subject to compromise”. These liabilities were reported at the amounts we anticipate will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. Upon emergence from bankruptcy, we qualified for and applied fresh start accounting to our financial statements in accordance with ASC 852 as (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Reorganization Plan was less than the post-petition liabilities and allowed claims. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Predecessor and Successor periods

may lack comparability See “Note 3—Chapter 11 Reorganization” and “Note 4—Fresh start accounting” in Item 8. Financial Statements and Supplementary Data of this report for more information.

Revenue recognition . We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded in the month payment is received. Historically, our actual payments have not significantly deviated from our accruals.

Derivative instruments . We seek to reduce our exposure to unfavorable changes in oil, natural gas and natural gas liquids prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps and collars. In the past, we have also entered into basis swaps and various types of option contracts. We follow the provisions of Accounting Standards Codification 815 “Derivatives and Hedging,” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Our derivative contracts have been executed with institutions that are parties to our New Credit Facility. We believe the credit risks associated with all of these institutions are acceptable.

From time to time, we may enter into derivative contracts which require payment of a premium. The premium can be paid at the time the contracts are initiated or deferred until the contracts settle. The fair value of our derivatives contracts are reported net of any deferred premium that are payable under the contracts.

Since we have elected to not designate any of our derivative contracts as hedges, we mark our contracts to their period end market values and the change in the fair value of the contracts is included in “Non-hedge derivative (losses) gains” in our consolidated statements of operations. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.

Oil and natural gas properties.

•

Full cost accounting . We use the full cost method of accounting for our oil and natural gas properties. Under this method, all costs incurred in the exploration and development of oil and natural gas properties are capitalized into a cost center. These costs include drilling and equipping productive wells, dry hole costs, seismic costs and delay rentals. Capitalized costs also include salaries, employee benefits, consulting services and other expenses that directly relate to our exploration and development activities.

•

Proved oil and natural gas reserves quantities . Proved oil and natural gas reserves are the quantities of crude 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.

The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Our proved reserve information included in this report is based on estimates prepared by Cawley, Gillespie & Associates, Inc. and, prior to 2017, also by Ryder Scott Company and our engineering staff. Cawley, Gillespie & Associates, Inc. evaluated 100% of the estimated future net revenues of our proved reserves as of December 31, 2017. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

•

Depreciation, depletion and amortization . The quantities of proved oil and natural gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. The depreciation, depletion and amortization rate is determined using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based on the relative energy content.

•

Full cost ceiling limitation. Under the full cost method, the net capitalized costs of oil and natural gas properties recorded on our consolidated balance sheets cannot exceed the estimated future net revenues discounted at 10% plus the cost of unproved properties not being amortized. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues exclude escalations based upon future conditions. If we have downward revisions to our estimated reserve quantities, it is possible that write-downs could occur in the future as well.

•

Costs not subject to amortization. Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling, and capitalized interest are initially excluded from our amortization base. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of an uneconomic well under a process that is conducted each quarter. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment at least once annually or if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves. In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of fresh start accounting, a substantial portion of the carrying value of our unevaluated properties is the result of an increase to reflect the fair value of our acreage in our STACK play.

•

Future development and abandonment costs. Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and natural gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

We record a liability for the estimated fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. Significant assumptions used in estimating such obligations include estimates of the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments, all of which are Level 3 inputs in the fair value hierarchy. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required for the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our estimated future cash flows.

Income taxes and related valuation allowance on deferred tax assets. Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. In assessing the need for valuation allowances, we consider the weight of all available evidence, both positive and negative, concerning the realization of the deferred tax asset. Among the more significant types of evidence that we consider are:

•

taxable income in prior carryback years;

•

future reversals of existing taxable temporary differences;

•

tax planning strategies; and

•

future taxable income exclusive of reversing temporary differences.

As of December 31, 2017, the Company had a full valuation allowance against its net deferred tax asset. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.

Impairment of long-lived assets . Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.

Recent Accounting Pronouncements

See “Note 1—Nature of operations and summary of significant accounting policies” in Item 8. Financial Statements and Supplementary Data of this report for a discussion of recently adopted and issued accounting standards. Additionally, we are monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and International Accounting Standards Board.

Effects of inflation and pricing

While the general level of inflation affects certain of our costs, factors unique to the oil and natural gas industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and natural gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on us.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity prices

Our financial condition, results of operations 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 due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our New Credit Facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration, and development activities. Based on our production for the year ended December 31, 2017, our gross revenues from commodity sales would change approximately $6.0 million for each $1.00 change in oil and NGL prices and $1.5 million for each $0.10 change in natural gas prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into various types of derivative instruments, which in the past has included commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Non-hedge derivative (losses) gains” in the consolidated statements of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Please see “Note 9—Derivative instruments” in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our derivative instruments.

Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those reviewed when deciding to enter into the original derivative position.

The fair value of our outstanding derivative instruments at December 31, 2017, was a net liability of $13.1 million. Based on our outstanding derivative instruments as of December 31, 2017, a 10% increase in the December 31, 2017, forward curves used to mark-to-market our derivative instruments would have increased our net liability position to $44.7 million, while a 10% decrease would have resulted in a net asset position of $17.4 million.

Our outstanding oil derivative instruments as of February 28, 2018, are summarized below:

			Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls		Swaps		Purchased puts		Sold calls
March 2018
Swaps		186	$	58.00	$	—	$	—
Collars		15	$	—	$	50.00	$	60.50
April - June 2018
Swaps		546	$	58.00	$	—	$	—
Collars		46	$	—	$	50.00	$	60.50
July - September 2018
Swaps		515	$	58.21	$	—	$	—
Collars		46	$	—	$	50.00	$	60.50
October - December 2018
Swaps		515	$	58.21	$	—	$	—
Collars		46	$	—	$	50.00	$	60.50
January - March 2019
Swaps		333	$	54.26	$	—	$	—
April - June 2019
Swaps		337	$	54.26	$	—	$	—
July - September 2019
Swaps		321	$	54.26	$	—	$	—
October - December 2019
Swaps		321	$	54.26	$	—	$	—
January - March 2020
Swaps		394	$	49.59	$	—	$	—
April - June 2020
Swaps		357	$	49.42	$	—	$	—
July - September 2020
Swaps		375	$	49.46	$	—	$	—
October - December 2020
Swaps		422	$	49.68	$	—	$	—
January - March 2021
Swaps		134	$	44.34	$	—	$	—
April - June 2021
Swaps		135	$	44.34	$	—	$	—
July - September 2021
Swaps		136	$	44.34	$	—	$	—
October - December 2021
Swaps		138	$	44.34	$	—	$	—

Our outstanding natural gas derivative instruments as of February 28, 2018, are summarized below:

Period and type of contract	Volume BBtu		Weighted average fixed price per MMBtu
March 2018
Swaps		977	$	2.87
April - June 2018
Swaps		2,783	$	2.86
July - September 2018
Swaps		2,609	$	2.87
October - December 2018
Swaps		2,519	$	2.88
January - March 2019
Swaps		1,889	$	2.80
April - June 2019
Swaps		1,878	$	2.80
July - September 2019
Swaps		1,838	$	2.81
October - December 2019
Swaps		2,027	$	2.81
January - March 2020
Swaps		900	$	2.77
April - June 2020
Swaps		900	$	2.77
July - September 2020
Swaps		900	$	2.77
October - December 2020
Swaps		900	$	2.77

Interest rates

All of the outstanding borrowings under our New Credit Facility as of December 31, 2017 are subject to market rates of interest as determined from time to time by the banks. As of December 31, 2017, borrowings bear interest at the Adjusted LIBO Rate, as defined under the New Credit Facility, which resulted in a weighted average interest rate of 4.17% on the amount outstanding. Any increase in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level under our New Credit Facility of $285.0 million, equal to our borrowing base at December 31, 2017, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $2.9 million.

ITEM 8. FINANCIAL STATEMEN TS AND SUPPLEMENTARY DATA

Index to financial statements

	Page

Chaparral Energy, Inc. consolidated financial statements:

Report of independent registered public accounting firm	78

Consolidated Balance Sheets	79

Consolidated Statements of Operations	81

Consolidated Statements of Stockholders’ Equity (Deficit)	82

Consolidated Statements of Cash Flows	83

Notes to Consolidated Financial Statements	84

Report of independent regist ered public accounting firm

Board of Directors and Stockholders

Chaparral Energy, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017 (Successor) and 2016 (Predecessor), the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the period from March 22, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through March 21, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor) and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 (Successor) and 2016 (Predecessor), and the results of its operations and its cash flows for the period from March 22, 2017 through December 31, 2017 (Successor), the period from January 1, 2017 through March 21, 2017 (Predecessor), and the years ended December 31, 2016 and 2015 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

Emergence from bankruptcy

As discussed in Note 3 to the consolidated financial statements, on March 10, 2017, the United States Bankruptcy Court for the District of Delaware entered an order confirming the plan for reorganization, which became effective on March 21, 2017. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with FASB Accounting Standards Codification® (ASC) 852, Reorganizations , for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods, as described in Note 4.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2000.

Oklahoma City, Oklahoma

March 29, 2018

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	Successor			Predecessor
	December 31,			December 31,
(dollars in thousands, except share data)	2017			2016
Assets
Current assets:
Cash and cash equivalents	$	27,732		$	186,480
Accounts receivable, net		60,363			46,226
Inventories, net		5,138			7,351
Prepaid expenses		2,661			3,886
Total current assets		95,894			243,943
Property and equipment, net		50,641			41,347
Oil and natural gas properties, using the full cost method:
Proved		634,294			4,323,964
Unevaluated (excluded from the amortization base)		482,239			20,353
Accumulated depreciation, depletion, amortization and impairment		(124,180	)		(3,789,133	)
Total oil and natural gas properties		992,353			555,184
Other assets		418			5,513
Total assets	$	1,139,306		$	845,987

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

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets—continued

	Successor			Predecessor
	December 31,			December 31,
(dollars in thousands, except share data)	2017			2016
Liabilities and stockholders’ equity (deficit)
Current liabilities:
Accounts payable and accrued liabilities	$	75,414		$	42,442
Accrued payroll and benefits payable		11,276			3,459
Accrued interest payable		187			732
Revenue distribution payable		17,966			9,426
Long-term debt and capital leases, classified as current		3,273			469,112
Derivative instruments		8,959			7,525
Total current liabilities		117,075			532,696
Long-term debt and capital leases, less current maturities		141,386			—
Derivative instruments		4,167			5,844
Deferred compensation		696			—
Asset retirement obligations		33,216			65,456
Liabilities subject to compromise		—			1,284,144
Commitments and contingencies (Note 16)
Stockholders’ equity (deficit):
Predecessor preferred stock, 600,000 shares authorized, none issued and outstanding as of December 31, 2016		—			—
Predecessor Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 333,686 shares issued and outstanding as of December 31, 2016		—			4
Predecessor Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 344,859 shares issued and outstanding as of December 31, 2016		—			3
Predecessor Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882 shares issued and outstanding as of December 31, 2016		—			2
Predecessor Class E Common stock, $0.01 par value, 10,000,000 shares authorized and 504,276 shares issued and outstanding as of December 31, 2016		—			5
Predecessor Class F Common stock, $0.01 par value, 1 share authorized, issued, and outstanding as of December 31, 2016		—			—
Predecessor Class G Common stock, $0.01 par value, 3 shares authorized and 2 shares issued and outstanding as of December 31, 2016		—			—
Predecessor additional paid in capital		—			425,231
Successor preferred stock, 5,000,000 shares authorized, none issued and outstanding as of December 31, 2017		—			—
Successor Class A Common stock, $0.01 par value, 180,000,000 shares authorized and 38,956,250 shares issued and outstanding as of December 31, 2017		389			—
Successor Class B Common stock, $0.01 par value, 20,000,000 shares authorized and 7,871,512 shares issued and outstanding as of December 31, 2017		79			—
Successor additional paid in capital		961,200			—
Accumulated deficit		(118,902	)		(1,467,398	)
Total stockholders' equity (deficit)		842,766			(1,042,153	)
Total liabilities and stockholders' equity (deficit)	$	1,139,306		$	845,987

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
(in thousands, except share and per share data)	December 31, 2017			March 21, 2017			2016			2015
Revenues:
Commodity sales	$	226,493		$	66,531		$	252,152		$	324,315
Sublease revenue		586			—			—			—
Total revenues		227,079			66,531			252,152			324,315
Costs and expenses:
Lease operating		72,132			19,941			90,533			110,659
Transportation and processing		9,503			2,034			8,845			8,541
Production taxes		11,750			2,417			9,610			9,953
Depreciation, depletion and amortization		92,599			24,915			122,928			216,574
Loss on impairment of oil and gas assets		42,146			—			281,079			1,491,129
Loss on impairment of other assets		179			—			1,393			16,207
General and administrative		39,617			6,843			20,953			39,089
Liability management		—			—			9,396			—
Cost reduction initiatives		691			629			2,879			10,028
Restructuring		3,531			—			—			—
Sublease expense		197			—			—			—
Total costs and expenses		272,345			56,779			547,616			1,902,180
Operating (loss) income		(45,266	)		9,752			(295,464	)		(1,577,865	)
Non-operating (expense) income:
Interest expense		(14,147	)		(5,862	)		(64,242	)		(112,400	)
(Loss) gain on extinguishment of debt		(635	)		—			—			31,590
Non-hedge derivative (losses) gains		(30,802	)		48,006			(22,837	)		145,288
Write-off of Senior Note issuance costs, discount and premium		—			—			(16,970	)		—
(Loss) gain on sale of assets		(25,996	)		206			(117	)		1,584
Other income (expense), net		686			1,167			528			740
Net non-operating (expense) income		(70,894	)		43,517			(103,638	)		66,802
Reorganization items, net		(3,091	)		988,727			(16,720	)		—
(Loss) income before income taxes		(119,251	)		1,041,996			(415,822	)		(1,511,063	)
Income tax (benefit) expense		(349	)		37			(102	)		(177,219	)
Net (loss) income	$	(118,902	)	$	1,041,959		$	(415,720	)	$	(1,333,844	)
Earnings per share:
Basic for Class A and Class B	$	(2.64	)	*			*			*
Diluted for Class A and Class B	$	(2.64	)	*			*			*
Weighted average shares used to compute earnings per share:
Basic for Class A and Class B		44,984,046		*			*			*
Diluted for Class A and Class B		44,984,046		*			*			*

____________________________________________________________

* Item not disclosed. See “Note 2—Earnings per share.”

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity (deficit)

	Common stock						Additional paid in capital			Accumulated deficit			Total
(dollars in thousands)	Shares			Amount
Balance at January 1, 2015 - Predecessor		1,423,916		$	14		$	429,678		$	282,166		$	711,858
Restricted stock issuances		1,209			—			—			—			—
Restricted stock forfeited		(15,091	)		—			—			—			—
Restricted stock repurchased		(5,725	)		—			—			—			—
Stock-based compensation		—			—			1,629			—			1,629
Net loss		—			—			—			(1,333,844	)		(1,333,844	)
Balance at December 31, 2015 - Predecessor		1,404,309			14			431,307			(1,051,678	)		(620,357	)
Restricted stock forfeited		(9,006	)		—			—			—			—
Restricted stock repurchased		(2,597	)		—			—			—			—
Stock-based compensation		—			—			(6,076	)		—			(6,076	)
Net loss		—			—			—			(415,720	)		(415,720	)
Balance at December 31, 2016 - Predecessor		1,392,706			14			425,231			(1,467,398	)		(1,042,153	)
Restricted stock forfeited		(1,454	)		—			—			—			—
Restricted stock cancelled		(8,964	)		—			—			—			—
Stock-based compensation		—			—			194			—			194
Net income		—			—			—			1,041,959			1,041,959
Balance at March 21, 2017 - Predecessor		1,382,288			14			425,425			(425,439	)		—
Cancellation of Predecessor equity		(1,382,288	)		(14	)		(425,425	)		425,439			—
Balance at March 21, 2017 - Predecessor		—		$	—		$	—		$	—		$	—

Issuance of Successor common stock - rights offering		4,197,210		$	42		$	49,985		$	—		$	50,027
Issuance of Successor common stock - backstop premium		367,030			4			—			—			4
Issuance of Successor common stock - settlement of claims		40,417,902			404			898,510			—			898,914
Issuance of Successor warrants		—			—			118			—			118
Balance at March 21, 2017 - Successor		44,982,142			450			948,613			—			949,063
Stock-based compensation		1,853,236			18			12,587			—			12,605
Restricted stock cancelled		(7,616	)		—			—			—			—
Net loss		—			—			—			(118,902	)		(118,902	)
Balance at December 31, 2017 - Successor		46,827,762		$	468		$	961,200		$	(118,902	)	$	842,766

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
(in thousands)	December 31, 2017			March 21, 2017			2016			2015
Cash flows from operating activities
Net (loss) income	$	(118,902	)	$	1,041,959		$	(415,720	)	$	(1,333,844	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Non-cash reorganization items		—			(1,012,090	)		—			—
Depreciation, depletion and amortization		92,599			24,915			122,928			216,574
Loss on impairment of assets		42,325			—			282,472			1,507,336
Write-off of Senior Note issuance costs, discount and premium		—			—			16,970			—
Deferred income taxes		—			—			—			(177,487	)
Derivative losses (gains)		30,802			(48,006	)		22,837			(145,288	)
Loss (gain) on sale of assets		25,996			(206	)		117			(1,584	)
Loss (gain) on extinguishment of debt		635			—			—			(31,590	)
Other		1,573			645			3,611			6,057
Change in assets and liabilities:
Accounts receivable		(12,092	)		198			(9,243	)		15,720
Inventories		(489	)		466			3,576			(1,968	)
Prepaid expenses and other assets		3,245			(497	)		(1,620	)		481
Accounts payable and accrued liabilities		2,622			8,733			25,987			(17,200	)
Revenue distribution payable		6,941			(1,875	)		509			(12,075	)
Deferred compensation		9,714			143			(5,257	)		(5,524	)
Net cash provided by operating activities		84,969			14,385			47,167			19,608
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties		(157,718	)		(31,179	)		(146,296	)		(313,481	)
Proceeds from asset dispositions		189,735			1,884			1,349			42,618
Proceeds from derivative instruments		15,676			1,285			90,590			233,605
Cash in escrow		42			—			48			—
Net cash provided by (used in) investing activities		47,735			(28,010	)		(54,309	)		(37,258	)
Cash flows from financing activities
Proceeds from long-term debt		33,000			270,000			181,000			120,000
Repayment of long-term debt		(176,407	)		(444,785	)		(1,952	)		(102,978	)
Repurchase of Senior Notes		—			—			—			(9,995	)
Proceeds from rights offering, net		—			50,031			—			—
Principal payments under capital lease obligations		(2,017	)		(568	)		(2,491	)		(2,400	)
Payment of other financing fees		(4,671	)		(2,410	)		—			(1,404	)
Net cash (used in) provided by financing activities		(150,095	)		(127,732	)		176,557			3,223
Net (decrease) increase in cash and cash equivalents		(17,391	)		(141,357	)		169,415			(14,427	)
Cash and cash equivalents at beginning of period		45,123			186,480			17,065			31,492
Cash and cash equivalents at end of period	$	27,732		$	45,123		$	186,480		$	17,065

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

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 1 : Nature of operations and summary of significant accounting policies

Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Our properties are located primarily in Oklahoma and our commodity products, which include crude oil, natural gas and natural gas liquids, are primarily sold to refineries and gas processing plants within close proximity to our producing properties. As discussed in “Note 3—Chapter 11 reorganization” we filed voluntary petitions for bankruptcy relief on May 9, 2016, and subsequently operated as debtor in possession, in accordance with the applicable provisions of the Bankruptcy Code, until emergence from bankruptcy on March 21, 2017. The cancellation of all existing shares outstanding followed by the issuance of new shares in the reorganized Company upon our emergence from bankruptcy caused a related change of control under US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Company’s consolidated financial statements on or after March 21, 2017, are not comparable with the consolidated financial statements prior to that date. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to March 21, 2017, and to the pre-emergence company as “Predecessor” for periods prior to and including March 21, 2017.

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Principles of consolidation

The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring use of assumptions, judgments and estimates on our consolidated financial statements include: quantities of proved oil and natural gas reserves; value of nonproducing leasehold; cash flow estimates used in impairment tests of other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; estimates of our stock-based compensation awards, assigning fair value and allocating purchase price in connection with business combinations; forecasting our effective income tax rate and valuation allowances associated with deferred income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates.

Reclassifications

Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2017, cash with a recorded balance totaling $26,165 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

As of December 31, 2016, we had restricted cash of $1,400 which was required to be maintained during the pendency of our bankruptcy. The restricted cash is included in “Cash and cash equivalents” in our consolidated balance sheets. As of December 31, 2017, we no longer had restricted cash.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We establish our allowance for doubtful accounts by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and our assessment of the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. When we recover amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery. Accounts receivable consisted of the following:

	Successor			Predecessor
	December 31,			December 31,
	2017			2016
Joint interests	$	29,032		$	13,818
Accrued commodity sales		26,516			31,304
Derivative settlements		157			—
Other		5,326			1,657
Allowance for doubtful accounts		(668	)		(553	)
	$	60,363		$	46,226

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. We evaluate our inventory each quarter and when there is evidence that the utility of our inventory, in their disposal in the ordinary course of business, will be less than cost, whether due to physical deterioration, obsolescence, changes in price levels, or other causes, we record an impairment loss for the difference. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories consisted of the following:

	Successor			Predecessor
	December 31,			December 31,
	2017			2016
Equipment inventory	$	4,163		$	8,165
Commodities		1,154			1,418
Inventory valuation allowance		(179	)		(2,232	)
	$	5,138		$	7,351

We recorded lower of cost or net realizable value adjustments, for the periods disclosed below, due to depressed industry conditions which resulted in lower demand for such equipment and hence lower market prices, as well as due to obsolescence. These adjustments are reflected in “Loss on impairment of other assets” in our consolidated statements of operations.

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
Inventory - valuation adjustment	$	179	$	—	$	1,393	$	10,192

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Property and equipment

Property and equipment is capitalized and stated at cost, while maintenance and repairs are expensed currently.

Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives of our assets are as follows:

Furniture and fixtures		10 years
Automobiles and trucks		5 years
Machinery and equipment		10 — 20 years
Office and computer equipment		5 — 10 years
Building and improvements		10 — 40 years

Oil and natural gas properties

Capitalized Costs . We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, and other internal costs directly attributable to these activities.

Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of an uneconomic well under a process that is conducted each quarter. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment at least once annually or if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of fresh start accounting, a substantial portion of the carrying value of our unevaluated properties is the result of an increase to reflect the fair value of our acreage in our STACK play (see “Note 4—Fresh start accounting”). See “Note 17—Oil and natural gas activities (unaudited)” for further details of our unevaluated oil and natural gas properties.

Depreciation, depletion and amortization . Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.

Ceiling Test . In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of December 31, 2017, 2016, and 2015 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC. As discussed in “Note 4—Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the carrying value of our oil and natural gas properties being restated based on their estimated fair value.

Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.

We recorded impairment losses of $6,015 related to four drilling rigs during the year ended December 31, 2015. The loss was recorded as a result of the deterioration in commodity prices and drilling activity whereby the value of such equipment had declined while utilizing third party equipment had become more cost effective. The loss is reflected in “Loss on impairment of other assets” in our consolidated statements of operations.

In October 2016, the Company entered into an agreement for the sale of all our drilling rigs. The sale closed in January 2017.

Our bankruptcy filing on May 9, 2016, (see “Note 3—Chapter 11 reorganization”) was an event that required an assessment whether the carrying amounts of our long-lived assets would be recoverable. Our evaluation indicated that no additional impairment was necessary as a direct result of the bankruptcy. As discussed in “Note 4—Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the carrying value of our assets being restated based on their fair value.

Income taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in results of operations in the period the rate change is enacted. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized. See “Note 12—Income taxes” for further discussion of our income taxes including the expected impacts of our emergence from Chapter 11 bankruptcy proceedings on the amount and availability of our loss carryforwards to offset future taxable income. See “Note 12—Income taxes” discussing the 2017 Tax Act and Staff Accounting Bulletin No. 118 issued by the SEC.

If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2017 and 2016, we have no uncertain tax positions and as such have not recorded a liability or accrued interest or penalties related to uncertain tax positions.

We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2009 through 2017 tax years generally remain subject to examination by federal and state tax authorities.

Derivative transactions

We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. Our derivative instruments are not designated as hedges for accounting purposes, thus changes in the fair value of derivatives are reported immediately in “Non-hedge derivative (losses) gains” in the consolidated statements of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the consolidated statements of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.

Within current and noncurrent classifications on the balance sheet, we offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See “Note 9—Derivative instruments” for additional information regarding our derivative transactions.

Fair value measurements

Fair value is defined by the Financial Accounting Standards Board (“FASB”) as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and our drilling rigs, which were sold in January 2017. See “Note 10—Fair value measurements” for additional information regarding our fair value measurements.

Asset retirement obligations

We own oil and natural gas properties that require expenditures to plug, abandon or remediate wells and to remove tangible equipment and facilities at the end of oil and natural gas production operations in accordance with applicable federal and state laws. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in “Depreciation, depletion and amortization” in our consolidated statements of operations. In certain instances, we are required to make deposits to escrow accounts for plugging and abandonment obligations. As discussed in “Note 4—Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in our asset retirement obligations being restated based on their fair value. See “Note 11—Asset retirement obligations” for additional information regarding our asset retirement obligations.

Environmental liabilities

We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2017 and 2016, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.

Revenue recognition

Sales of oil, natural gas and NGLs are recorded when title of production passes to the customer. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products are recognized at the time of delivery of materials. As discussed below, beginning in 2018, we adopted new authoritative guidance that supersedes previous revenue recognition requirements. Under the new guidance, our commodity sales will be recorded when control of the product transfers to the customer and any costs and fees levied by the customer subsequent to the transfer of control will be recognized as a reduction in revenue.

Gas balancing

We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. The volumes of gas sold may differ from the volumes to which we are entitled based on our interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves, net to the Company, will not be sufficient to enable the under-produced owner to recoup its entitled share through production. Our recorded liability is included in “Accounts payable and accrued liabilities” on the consolidated balance sheets. No receivables are recorded for those wells where we have taken less than our share of production. Our aggregate imbalance positions at December 31, 2017 and 2016 were immaterial.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Stock-based compensation

Pre-emergence stock compensation

Prior to our emergence from bankruptcy, our stock-based compensation programs consisted of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. We considered the measurement of fair value of our phantom stock, RSU and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy.

The estimated fair value of the phantom stock and RSU awards were remeasured at the end of each reporting period based on our total asset value less total liabilities, in accordance with the provisions of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. A crucial input to the measurement was the value of oil and natural gas properties priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards was recognized over the vesting period using the straight-line method and the accelerated method, respectively.

Our previous restricted stock awards included those with a service condition and those with both performance and market conditions. The fair value of our restricted stock awards that included a service condition was based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and was remeasured at the end of each reporting period until settlement. We recognized compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

The grant date fair value of restricted stock awards that included a market condition was measured using a Monte Carlo model. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.

Post-emergence stock compensation

Our post-emergence management incentive plan consists of restricted stock awards that are subject to service vesting conditions (the “Time Shares”) and shares that are subject to performance vesting conditions (the “Performance Shares”). Both Time and Performance Shares are classified as equity-based awards. Compensation cost is recognized and measured based on fair value as determined by the market price of our common stock currently trading on the OTCQB tier of the OTC Markets Group, Inc.

The Time Shares are subject to a graded vesting schedule over three annual installments and expense is recognized under the accelerated method. The Performance Shares vest in three tranches over three calendar years according to performance conditions established each year. The performance conditions for a given year are unique to that year and vesting with respect to performance conditions for a given year is independent of the vesting with respect to other years. As a result, the requisite service period for each of the three tranches of Performance Shares relate to the individual year for which performance is measured and do not overlap. Periodic expense for Performance Shares throughout a given fiscal year is based on the number of awards expected to vest in that year. Performance conditions had not been established for 2018 and 2019 at the time the awards were granted, hence a grant date for purposes of determining a measurement value had not been established either. Furthermore, since the requisite service period for Performance Shares related to 2018 and 2019 performance conditions will not commence until each of those fiscal years commences, no expense was recognized in 2017 in connection with those awards. Performance Shares related to 2017 performance conditions vested based on accomplishment of multiple conditions that generally relate to drilling results and strategic goals. The accomplishment of an individual condition resulted in vesting of shares that was independent of vesting with respect to the other conditions (i.e. simultaneous accomplishment of multiple conditions was not required for vesting). The number of shares vesting with respect to certain 2017 performance conditions was primarily at the discretion of the Board; hence a grant date for the related shares was not established for purposes of determining a measurement value until March 15, 2018, when the Board ultimately determined the number of shares vesting. Requisite service on Performance Shares subject to these discretionary 2017 performance conditions was being rendered in 2017 and therefore expense was recognized in 2017. As permitted by a recent accounting update, we do not recognize expense based on an estimate of forfeitures but rather recognize the impact of forfeitures only as they occur.

See “Note 13—Deferred compensation” for additional information relating to stock-based compensation.

Joint development agreement

On September 25, 2017, we entered into a joint development agreement (“JDA”) with BCE Roadrunner LLC, a wholly-owned subsidiary of Bayou City Energy Management, LLC (“BCE”), pursuant to which BCE will fund 100 percent of our drilling, completion and equipping costs associated with 30 STACK wells, subject to well cost caps that vary by well-type across location and targeted formations, ranging from $3,400 and $4,000 per gross well. The JDA wells, which will be drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County, with the ability to expand the JDA to drill additional wells in the future. The JDA provides us with a means to accelerate the delineation of our position within our Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and potentially adding reserves. In exchange, BCE will

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

receive wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retain 15%) until the program reaches a 14% internal rate of return. Once achieved, ownership interest in all wells will revert such that we will own a 75% working interest and BCE will retain a 25% working interest. We will retain all acreage and reserves outside of the wellbore, with both parties paying their working interest share of lease operating expenses. We will record revenues and operating costs associated with our JDA wells according to our working interest share as specified above.

Liability management

Liability management expenses, which were incurred in 2016, include third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 petition, such expenses, to the extent that they were incremental and directly related to our bankruptcy reorganization, are reflected in “Reorganization items” in our consolidated statements of operations.

Cost reduction initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to depressed commodity pricing environment. The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
One-time severance and termination benefits	$	678	$	608	$	2,772	$	7,757
Professional fees		13		21		107		2,271
Total cost reduction initiatives expense	$	691	$	629	$	2,879	$	10,028

Restructuring

In conjunction with our EOR asset divestiture (see “Note 6—Acquisitions and divestitures”), we terminated 86 employees. We consider this exit activity to be a restructuring in that it has materially changed the scope and manner in which our business is conducted. The restructuring expense related to the divestiture is predominantly comprised of one-time severance and termination benefits for the affected employees and as of December 31, 2017, we had a remaining payable of $1,629 for benefits yet to be paid.

Subleases

As discussed in “Note 6 — Acquisitions and divestitures”, we closed the sale of our EOR assets in November 2017. The EOR assets included CO ₂ compressors that were considered integral to the operations and were leased under six lease agreements by the Company from U.S. Bank. In conjunction with the sale, we continued to lease the compressors, but executed sublease agreements with the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and hence we did not record any losses upon initiation of the subleases. Of the original lease agreements, three are classified as capital leases (see “Note 8 — Debt”) while the remaining three are classified as operating leases (see “Note 16 — Commitments and contingencies”). Prior to the asset sale, the capital leases were included in our full cost amortization base and hence subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating” expense on our statement of operations. Based on the facts and circumstances relating to our original leases and the current subleases, we have determined that all the subleases are to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases, all payments received from the Sublessee are reflected as “Sublease revenue” on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as “Sublease expense” on our statement of operations. With respect to the capital leases, we have reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and will amortize the asset on a straight line basis prospectively. We will continue incurring interest expense on the capital leases.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Recently adopted accounting pronouncements

In May 2017, the FASB issued authoritative guidance which provides clarification on determining which changes to the terms and conditions of share-based payment awards require an entity to apply modification accounting. The guidance is effective for fiscal years, including interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted in any interim period. The guidance should be applied prospectively to an award modified on or after the adoption date. We adopted this guidance in, 2017, with no material impact to our financial statements or results of operations.

In March 2016, the FASB issued authoritative guidance with the objective to simplify several aspects of the accounting for share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholdings and accounting for forfeitures. Classification of these aspects on the statement of cash flows is also addressed. We have adopted this guidance, which was effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter, in 2017, with no material impact to our financial statements or results of operation. We did not have any previously unrecognized excess tax benefits that required an adjustment to the opening balance of retained earnings under the modified retrospective transition method required by the guidance.

In March 2016, the FASB issued authoritative guidance that clarifies that the assessment of whether an embedded contingent put or call option in a financial instrument is clearly and closely related to the debt host requires only an analysis of the four-step decision sequence described in Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“ASC 815”). We adopted this guidance, which was effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter, in 2017, with no material impact to our financial statements or results of operations.

In August 2014, the FASB issued authoritative guidance that required entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and required additional disclosures if certain criteria were met. The guidance was adopted on December 31, 2016, and other than discussions regarding our emergence from bankruptcy and the related exit financing in “Note 3—Chapter 11 reorganization” and “Note 8—Debt”, there were no additional required disclosures as contemplated by this guidance.

Recently issued accounting pronouncements

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The updated guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period and it will be adopted by us on January 1, 2018. The new standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. During 2015 and 2016, the FASB released further updates that, among others, provided supplemental guidance and clarification to this topic including clarification on principal vs. agent considerations and identifying performance obligations and licensing.

We will adopt the revenue recognition update effective January 1, 2018 using the modified retrospective approach. We have completed an assessment of our marketing contracts covering a majority portion of our revenue. Based on this assessment, we do not expect the new guidance to have a material impact on prior and future net income and therefore we will not be required to record a cumulative effect adjustment. However, we expect the guidance to impact our classification of certain costs for gathering, transportation and processing of gas as part of the transaction price rather than reported expense. Accordingly, amounts currently reported as “Transportation and processing” on our statement of operations will be reflected as a revenue deduction upon adoption of the standard. We did not identify any other changes to our revenue recognition policies that would result in a material effect on the timing of our revenue recognition or our financial position, results of operations, net income or cash flows. We do not believe further disaggregation of revenue will be required under the new standard. The adoption of the new guidance will have an impact on our revenue related disclosures and internal controls over financial reporting as our revenue recognition related disclosures will expand upon adoption of the new standard. We are currently in the process of finalizing documentation of new policies, procedures, systems, controls and data requirements as the standard is implemented.

In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted. As we currently do not own any equity investments nor do we have any financial liabilities recognized under the fair value option, we do not expect this guidance to materially impact our financial statements or results of operations upon adoption in the first quarter of 2018.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

In February 2016, the FASB issued authoritative guidance significantly amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. Furthermore, all leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2018 and interim periods thereafter, and should be applied using a modified retrospective approach. Early adoption is permitted. Our current operating leases are predominantly comprised of a limited number of leases for CO ₂ compressors. However, we also enter into contractual arrangements relating to rights of ways or surface use that are typical of upstream oil and gas operations. We are currently assessing whether such arrangements are included in the new guidance, especially in light of a guidance update issued in January 2018 which provides a practical expedient on land easements. We are in the process of evaluating the impact of this guidance on our consolidated financial statements and related disclosures and as contracts are reviewed under the new standard, this analysis could result in an impact to our financial statements; however, that impact is currently not known.

In June 2016, the FASB issued authoritative guidance which modifies the measurement of expected credit losses of certain financial instruments. The guidance is effective for fiscal years beginning after December 15, 2020, however early adoption is permitted for fiscal years beginning after December 15, 2018. The updated guidance impacts our financial statements primarily due to its effect on our accounts receivables. Our history of accounts receivable credit losses almost entirely relates to receivables from joint interest owners in our operated oil and natural gas wells. Based on this history and on mitigating actions we are permitted to take to offset potential losses such as netting past due amounts against revenue and assuming title to the working interest, we do not expect this guidance to materially impact our financial statements or results of operations.

In August 2016, the FASB issued authoritative guidance which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable. Early adoption is permitted. We will adopt this update effective January 1, 2018, however, we do not expect this guidance to have a material impact on our financial statements or results of operations.

In November 2016, the FASB issued authoritative guidance requiring that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. Adoption of this standard will change the presentation of our cash flows but is not expected to have a material impact on our financial statements or results of operations.

In January 2017, the FASB issued authoritative guidance that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described under updated revenue recognition guidance. The guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted. We expect that adoption of the new guidance may reduce the likelihood that a future transaction would be accounted for as a business combination although such a determination may require a greater degree of judgment. We will adopt this update prospectively effective January 1, 2018.

Note 2: Earnings per share

We have not historically presented earnings per share (“EPS”) because our common stock did not previously trade on a public market, either on a stock exchange or in the over-the-counter (“OTC”) market. Accordingly, we were permitted under accounting guidance to omit such disclosure. However, the OTCQB tier of the OTC Markets Group Inc. began quoting our Class A common stock on May 26, 2017, under the symbol “CHPE”. From May 18, 2017, through May 25, 2017, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP”. Our Class B common stock is not listed or quoted on the OTCQB or

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

any other stock exchange or quotation system. Our Class A and Class B common stock shares equally in dividends and undistributed earnings. We are presenting basic and diluted EPS for the Successor period subsequent to our emergence from bankruptcy but are not presenting EPS for any Predecessor period.

We are required under accounting guidance to compute EPS using the two-class method which considers multiple classes of common stock and participating securities. All securities that meet the definition of a participating security are to be included in the computation of basic EPS under the two-class method. Our unvested restricted stock awards are considered to be participating securities as they include non-forfeitable dividend rights in the event a dividend is paid on our common stock. Our participating securities do not participate in undistributed net losses because they are not contractually obligated to do so and hence are not included in the computation of EPS for the Successor period from March 22, 2017, to December 31, 2017, since a net loss has occurred.

A reconciliation of the components of basic and diluted EPS is presented below:

	Successor
	Period from
	March 22, 2017
	through
(in thousands, except share and per share data)	December 31, 2017
Numerator for basic and diluted earnings per share
Net loss	$	(118,902	)
Denominator for basic earnings per share
Weighted average common shares - Basic for Class A and Class B		44,984,046
Denominator for diluted earnings per share
Weighted average common shares - Diluted for Class A and Class B		44,984,046
Earnings per share
Basic for Class A and Class B	$	(2.64	)
Diluted for Class A and Class B	$	(2.64	)
Participating securities excluded from earnings per share calculations
Unvested restricted stock awards		1,833,136
Antidilutive securities excluded from earnings per share calculations
Warrants (1)		140,023

____________________________________________________________

(1)	The warrants to purchase shares of our Class A common stock are antidilutive due to the exercise price exceeding the average price of our Class A shares for the periods presented and due to the net losses we incurred.

Note 3 : Chapter 11 reorganization

On March 10, 2017 (the “Confirmation Date”), the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy.

Debtor-In-Possession. During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by us which were designed primarily to minimize the impact of the Chapter 11 Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business required the approval of the Bankruptcy Court.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Plan of Reorganization. Pursuant to the terms of the Reorganization Plan, which was supported by us, certain lenders under our Prior Credit Facility (collectively, the “Lenders”) and certain holders of our Senior Notes (collectively, the “Noteholders”), the following transactions occurred on or around the Effective Date:

•

We issued 44,982,142 shares of common stock of the reorganized company (“New Common Stock”), which were the result of the transactions described below. We also entered into a stockholders agreement and a Registration Rights Agreement and amended our certificate of incorporation and bylaws for the authorization of the New Common Stock and to provide registration rights thereunder, among other corporate governance actions;

•

Our Predecessor common stock was cancelled, extinguished and discharged and the Predecessor equity holders did not receive any consideration in respect of their equity interests;

•

The $1,267,410 of indebtedness, including accrued interest, attributable to our Senior Notes was exchanged for New Common Stock. In addition, we issued or reserved shares of New Common Stock to be exchanged in settlement of $2,439 of certain general unsecured claims. In aggregate, the shares of New Common Stock issued or to be issued in settlement of the Senior Note and these general unsecured claims represented approximately 90% percent of outstanding Successor common shares;

•

We completed a rights offering backstopped by certain holders of our Senior Notes (the “Backstop Parties”) which generated $50,031 of gross proceeds. The rights offering resulted in the issuance of New Common Stock, representing approximately nine percent of outstanding Successor common shares, to holders of claims arising under the Senior Notes and to the Backstop Parties;

•

In connection with the rights offering described above, the Backstop Parties received approximately one percent of outstanding Successor common shares as a backstop fee;

•

Additional shares, representing seven percent of outstanding Successor common shares on a fully diluted basis, were authorized for issuance under a new management incentive plan;

•

Our Prior Credit Facility, previously consisting of a senior secured revolving credit facility was restructured into an Exit Credit Facility consisting of a first-out revolving facility (“Exit Revolver”) and a second-out term loan (“Exit Term Loan”). On the Effective Date, the entire balance on the Prior Credit Facility in the amount of $444,440 was repaid while we received gross proceeds representing the opening balances on our Exit Revolver of $120,000 and an Exit Term Loan of $150,000. For more information refer to “Note 8—Debt;”

•

We paid $6,954 for creditor-related professional fees and also funded a $11,000 segregated account for debtor-related professional fees in connection with the reorganization related transactions above;

•

Certain other priority or convenience class claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claimholders;

•

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Liabilities subject to compromise. In accordance with ASC Topic 852, Reorganizations (“ASC 852”), our financial statements include amounts classified as liabilities subject to compromise which represent estimates of pre-petition obligations that were allowed as claims in our bankruptcy case. These liabilities are reported at the amounts allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. The amounts disclosed below as of March 21, 2017, reflect the liabilities immediately prior to our Reorganization Plan becoming effective. As part of the Reorganization Plan, the Bankruptcy Court approved the settlement of these claims and they were subsequently settled in cash or equity, reinstated or otherwise reserved for at emergence.

	Predecessor
	March 21, 2017		December 31, 2016
Accounts payable and accrued liabilities	$	6,687	$	9,212
Accrued payroll and benefits payable		3,949		4,048
Revenue distribution payable		3,050		3,474
Senior Notes and associated accrued interest		1,267,410		1,267,410
Liabilities subject to compromise	$	1,281,096	$	1,284,144

Note 4: Fresh start accounting

Upon emergence from bankruptcy, we qualified for and applied fresh start accounting to our financial statements in accordance with the provisions set forth in ASC 852 as (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Reorganization Plan was less than the post-petition liabilities and allowed claims.

Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares in the reorganized Company caused a related change of control under US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Predecessor and Successor periods may lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (“ASC 205”). ASC 205 states that financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, “black-line” financial statements are presented to distinguish between the Predecessor and Successor periods.

Enterprise Value and Reorganization Value

Reorganization value represents the fair value of the Company’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the Company's assets immediately after restructuring. The reorganization value was allocated to the Company’s individual assets based on their estimated fair values.

The Company’s reorganization value was derived from enterprise value. Enterprise value represents the estimated fair value of an entity's long-term debt and equity. The enterprise value of the Company on the Effective Date, as approved by the Bankruptcy Court in support of the Plan, was estimated to be within a range of $1,050,000 to $1,350,000 with a mid-point value of $1,200,000. Based upon the various estimates and assumptions necessary for fresh start accounting, as further discussed below, the estimated enterprise value was determined to be $1,200,000 before consideration of cash and cash equivalents and outstanding debt at the Effective Date.

The following table reconciles the enterprise value to the estimated fair value of the Successor’s common stock as of the Effective Date:

Enterprise value	$	1,200,000
Plus: cash and cash equivalents		45,123
Less: fair value of outstanding debt		(296,061	)
Less: fair value of warrants (consideration for previously accrued consulting fees)		(118	)
Fair value of Successor common stock on the Effective Date	$	948,944
Total shares issued under the Reorganization Plan		44,982,142
Per share value (1)	$	21.10

____________________________________________________________

(1)	The per share value shown above is calculated based upon the financial information determined using US GAAP at the Effective Date.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

The following table reconciles the enterprise value to the estimated reorganization value of the Successor’s assets as of the Effective Date:

Enterprise value	$	1,200,000
Plus: cash and cash equivalents		45,123
Plus: current liabilities		82,254
Plus: noncurrent liabilities excluding long-term debt		64,735
Reorganization value of Successor assets	$	1,392,112

Valuation of oil and gas properties

The Company’s principal assets are its oil and gas properties, which are accounted for under the full cost method of accounting. The oil and gas properties include proved reserves and unevaluated leasehold acreage. With the assistance of valuation consultants, the Company estimated the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Effective Date.

The fair value analysis was based on the Company’s estimates of proved, probable and possible reserves developed internally by the Company’s reservoir engineers. Discounted cash flow models were prepared using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising the proved, probable and possible reserves. The value estimated for probable and possible reserves was utilized as an estimate of the fair value of the Company’s unevaluated leasehold acreage, which was further corroborated against comparable market transactions. Future revenues were based upon the forward NYMEX strip for oil and natural gas prices as of the Effective Date, adjusted for differentials realized by the Company. Development and operating cost estimates for the oil and gas properties were adjusted for inflation. The after-tax cash flows were discounted to the Effective Date at discount rate of 8.5%. This discount rate was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected return on equity for similar industry participants. Risk adjustment factors were applied to the values derived for the proved non-producing, proved undeveloped, probable and possible reserve categories based on consideration of the risks associated with geology, drilling success rates, development costs and the timing of development and extraction. The discounted cash flow models also included depletion, depreciation and income tax expense associated with an after-tax valuation analysis.

From this analysis the Company estimated the fair value of its proved reserves and undeveloped leasehold acreage to be $604,065 and $585,574, respectively, as of the Effective Date. These amounts are reflected in the Fresh Start Adjustments item (i) below.

Other valuations

Our adoption of fresh start accounting also required adjustments to certain other assets and liabilities on our balance sheet including property and equipment, other assets and asset retirement obligations.

Property and equipment — consists of real property which includes our headquarters, field offices and pasture land, and personal property which includes vehicles, machinery and equipment, office equipment and fixtures and a natural gas pipeline. These assets were valued using a combination of cost, income and market approaches with the exception of pasture land where we relied on government data to determine fair value.

Other assets — includes, among others, an equity investment in a company that operates ethanol plants. The equity investment was valued utilizing a combination of the market approaches such as the guideline public company method and the similar transactions method. This equity investment was sold in June 2017.

Asset retirement obligations — our fresh start updates to these obligations included application of the Successor’s credit adjusted risk free rate, which now incorporates a term structure based on the estimated timing of plugging activity, and resetting all obligations to a single layer.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Consolidated balance sheet

The following consolidated balance sheet is as of March 21, 2017. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Reorganization Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Effective Date:

				Reorganization				Fresh Start
	Predecessor			Adjustments				Adjustments				Successor
Assets
Current assets:
Cash and cash equivalents	$	180,456		$	(135,333	)	(a)	$	—			$	45,123
Accounts receivable, net		46,837			—				—				46,837
Inventories, net		6,885			—				—				6,885
Prepaid expenses		4,933			(535	)	(b)		—				4,398
Derivative instruments		19,058			—				—				19,058
Total current assets		258,169			(135,868	)			—				122,301
Property and equipment		38,391			—				18,987		(i)		57,378
Oil and natural gas properties, using the full cost method:
Proved		4,355,576			—				(3,751,511	)	(i)		604,065
Unevaluated (excluded from the amortization base)		26,039			—				559,535		(i)		585,574
Accumulated depreciation, depletion, amortization and impairment		(3,811,326	)		—				3,811,326		(i)		—
Total oil and natural gas properties		570,289			—				619,350		(i)		1,189,639
Derivative instruments		14,295			—				—				14,295
Other assets		5,499			2,410		(c)		590		(i)		8,499
Total assets	$	886,643		$	(133,458	)		$	638,927			$	1,392,112
Liabilities and stockholders’ equity (deficit)
Current liabilities:
Accounts payable and accrued liabilities	$	64,413		$	(2,737	)	(a)(d)	$	—			$	61,676
Accrued payroll and benefits payable		7,366			2,186		(d)		—				9,552
Accrued interest payable		2,095			(2,095	)	(a)		—				—
Revenue distribution payable		7,975			3,050		(d)		—				11,025
Long-term debt and capital leases, classified as current		468,814			(464,182	)	(e)		—				4,632
Total current liabilities		550,663			(463,778	)			—				86,885
Long-term debt and capital leases, less current maturities		—			291,429		(f)		—				291,429
Deferred compensation		—			519		(d)		—				519
Asset retirement obligations		66,973			—				(2,757	)	(i)		64,216
Liabilities subject to compromise		1,281,096			(1,281,096	)	(d)		—				—
Commitments and contingencies
Stockholders’ (deficit) equity:
Predecessor common stock		14			(14	)	(g)		—				—
Predecessor additional paid in capital		425,425			(425,425	)	(g)		—				—
Successor common stock		—			450		(g)		—				450
Successor additional paid in capital		—			948,613		(g)		—				948,613
(Accumulated deficit) retained earnings		(1,437,528	)		795,844		(h)		641,684		(j)		—
Total stockholders' (deficit) equity		(1,012,089	)		1,319,468				641,684				949,063
Total liabilities and stockholders' equity (deficit)	$	886,643		$	(133,458	)		$	638,927			$	1,392,112

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Reorganization adjustments

(a)	Adjustments reflect the following net cash payments recorded as of the Effective Date from implementation of the Plan:

Cash proceeds from rights offering	$	50,031
Cash proceeds from Exit Term Loan		150,000
Cash proceeds from Exit Revolver		120,000
Fees paid to lender for Exit Term Loan		(750	)
Fees paid to lender for Exit Revolver		(1,125	)
Payment in full to extinguish Prior Credit Facility		(444,440	)
Payment of accrued interest on Prior Credit Facility		(2,095	)
Payment of previously accrued creditor-related professional fees		(6,954	)
Net cash used	$	(135,333	)

(b)	Reclassification of previously prepaid professional fees to debt issuance costs associated with the Exit Credit Facility.

(c)	Reflects issuance costs related to the Exit Credit Facility:

Fees paid to lender for Exit Term Loan	$	750
Fees paid to lender for Exit Revolver		1,125
Professional fees related to debt issuance costs on the Exit Credit Facility		535
Total issuance costs on Exit Credit Facility	$	2,410

(d)

As part of the Plan, the Bankruptcy Court approved the settlement of certain allowable claims, reported as liabilities subject to compromise in the Company’s historical consolidated balance sheet. As a result, a gain was recognized on the settlement of liabilities subject to compromise calculated as follows:

Senior Notes including interest	$	1,267,410
Accounts payable and accrued liabilities		6,687
Accrued payroll and benefits payable		3,949
Revenue distribution payable		3,050
Total liabilities subject to compromise		1,281,096
Amounts settled in cash, reinstated or otherwise reserved at emergence		(10,089	)
Fair value of equity issued in settlement of Senior Notes and certain general unsecured creditors		(898,914	)
Gain on settlement of liabilities subject to compromise	$	372,093

(e)	Reflects extinguishment of Prior Credit Facility along with associated unamortized issuance costs, establishment of Exit Credit Facility and adjustments to reclassify existing debt back to their scheduled maturities:

Reclassification from current to noncurrent, based on scheduled repayment, of debt no longer in default	$	(22,612	)
Establishment of Exit Term Loan - current portion		1,183
Payment in full to extinguish Prior Credit Facility		(444,440	)
Write-off unamortized issuance costs associated with Prior Credit Facility		1,687
	$	(464,182	)

(f)	Reflects establishment of our Exit Credit Facility pursuant to our Reorganization Plan, net of issuance costs, as well as adjustments to reclassify existing debt back to their scheduled maturities:

Origination of the Exit Term Loan, net of current portion	$	148,817
Origination of the Exit Revolver		120,000
Reclassification from current to noncurrent, based on scheduled repayment, of debt no longer in default		22,612
	$	291,429

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

(g)	Adjustment represents (i) the cancellation of Predecessor equity on the Effective Date, (ii) the issuance of 44,982,142 shares of Successor common stock on the Effective Date and (iii) the issuance of 140,023 warrants on the Effective Date (see “Note 3—Chapter 11 reorganization”)

Cancellation of predecessor equity - par value	$	(14	)
Cancellation of predecessor equity - paid in capital		(425,425	)
Issuance of successor common stock in settlement of claims		898,914
Issuance of successor common stock under rights offering		50,031
Issuance of warrants		118
Net impact to common stock-par and additional paid in capital	$	523,624

(h)	Reflects the cumulative impact of the following reorganization adjustments:

Gain on settlement of liabilities subject to compromise	$	372,093
Cancellation of predecessor equity		425,438
Write-off unamortized issuance costs associated with Prior Credit Facility		(1,687	)
Net impact to retained earnings	$	795,844

Fresh start adjustments

(i)

Represents fresh start accounting adjustments primarily to (i) remove accumulated depreciation, depletion, amortization and impairment, (ii) increase the value of proved oil and gas properties, (iii) increase the value of unevaluated oil and gas properties primarily to capture the value of our acreage in the STACK, (iv) increase other property and equipment primarily due to increases to land, vehicles, machinery and equipment and (v) decrease asset retirement obligations. These fair value measurements giving rise to these adjustments are primarily based on Level 3 inputs under the fair value hierarchy (See “Note 10—Fair value measurements”).

(j)	Reflects the cumulative impact of the fresh start adjustments discussed herein.

Reorganization items

We use this category to reflect, where applicable, post-petition revenues, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. Reorganization items are as follows:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through			Year ended
	December 31, 2017		March 21, 2017			December 31, 2016
Gains on the settlement of liabilities subject to compromise	$	—	$	(372,093	)	$	—
Fresh start accounting adjustments		—		(641,684	)		—
Professional fees		3,091		18,790			15,484
Claims for non-performance of executory contract		—		—			1,236
Rejection of employment contracts		—		4,573			—
Write off unamortized issuance costs on Prior Credit Facility		—		1,687			—
Total reorganization items	$	3,091	$	(988,727	)	$	16,720

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 5 : Supplemental disclosures to the consolidated statements of cash flows

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
	December 31, 2017			March 21, 2017			2016			2015
Net cash provided by operating activities included:
Cash payments for interest	$	17,195		$	4,105		$	25,764		$	116,379
Interest capitalized		(2,142	)		(248	)		(2,139	)		(9,670	)
Cash payments for interest, net of amounts capitalized	$	15,053		$	3,857		$	23,625		$	106,709
Cash payments for income taxes	$	150		$	—		$	250		$	640
Cash payments for reorganization items	$	18,006		$	11,405		$	10,670		$	—
Non-cash financing activities included:
Repayment of Prior Credit Facility with proceeds from early termination of derivative contracts (See Note 9)	$	—		$	—		$	103,560		$	—
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	6,746		$	716		$	22,282		$	4,000
Change in accrued oil and gas capital expenditures	$	9,534		$	5,387		$	(19,725	)	$	(105,312	)

Note 6: Acquisitions and divestitures

2017 Acquisitions and divestitures

In November 2017, we closed on the sale of our EOR assets along with some minor assets within geographic proximity for cash proceeds, net of preliminary post-closing adjustments, of $163,630 plus certain contingent payments through December 2020. As these properties comprised a material portion of our oil and natural gas reserves and our assessment indicated that our depletion rate would be significantly altered subsequent to the sale, in accordance with the full cost method of accounting for conveyances, we recognized a loss of $25,163 on the sale. The loss is recognized in “Loss (gain) on sale of assets” in the consolidated statements of operations.

In December 2017, we closed on the sale of certain producing properties located in Osage County, Oklahoma, for proceeds, net of preliminary post-closing adjustments, of $14,117. In addition we had various other divestitures of non-core oil and gas properties throughout the year ended December 31, 2017 resulting in proceeds of approximately $9,200. Other than our EOR asset sale, these transactions did not individually, or in the aggregate, represent a material portion of our oil and natural gas reserves and therefore we did not record any gain or loss on the sale and instead, reduced our full cost pool by the amount of the net proceeds.

In December 2017, we entered into purchase and sale agreements, scheduled to close in January 2018, to acquire acreage in the STACK play in Kingfisher County, Oklahoma. In early January 2018, immediately prior to closing the purchase, we amended the transaction to include additional acreage. The final purchase closed for $60,643 encompassing 7,000 acres.

2016 Divestitures

During 2016, we did not have any significant divestitures of our oil and natural gas properties.

2015 Divestitures

During 2015, we sold various non-core oil and gas properties for total proceeds of $36,654. The properties sold include acreage in various counties in South-Central Oklahoma in the SCOOP play (“South-Central Oklahoma Oil Province”) and oil and gas properties in Osage County.

As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

100

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 7: Property and equipment

Major classes of property and equipment are shown in the following table. As discussed in “Note 4—Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in restating our property and equipment to fair value, thus resetting the accumulated depreciation and amortization balance.

	Successor		Predecessor
	December 31,		December 31,
	2017		2016
Furniture and fixtures	$	519	$	2,518
Automobiles and trucks		4,464		9,793
Machinery and equipment		22,467		53,757
Office and computer equipment		5,046		20,817
Building and improvements		19,728		25,085
		52,224		111,970
Less accumulated depreciation and amortization		6,158		79,415
		46,066		32,555
Land		4,575		8,792
	$	50,641	$	41,347

Note 8: Debt

As of the dates indicated, long-term debt and capital leases consisted of the following:

	Successor			Predecessor
	December 31,			December 31,
	2017			2016 (2)
New Credit Facility	$	127,100		$	—
Prior Credit Facility		—			444,440
Real estate mortgage notes, principal and interest payable monthly, bearing interest at 5.50%, due December 2028; collateralized by real property		9,177			9,595
Installment notes payable		—			434
Capital lease obligations		14,361			16,946
Unamortized issuance costs (1)		(5,979	)		(2,303	)
Total debt, net		144,659			469,112
Less current portion		3,273			469,112
Total long-term debt, net	$	141,386		$	—

(1)	Debt issuance costs are presented as a direct deduction from debt rather than an asset pursuant to recent accounting guidance. The balance on December 31, 2017, was related to the New Credit Facility while the balance as of December 31, 2016, was related to the Prior Credit Facility.

(2)

Senior Notes have not been included in this table as they were classified as “Liabilities subject to compromise” at December 31, 2016. Additionally, as a result of certain debt defaults which occurred in early 2016 and remained uncured during the pendency of the Chapter 11 Cases, all outstanding long-term debt was classified as current at December 31, 2016.

Maturities of long-term debt and capital leases, excluding unamortized debt issuance costs, are as follows as of December 31, 2017:

2018	$	3,273
2019		12,300
2020		658
2021		697
2022		127,836
2023 and thereafter		5,874
	$	150,638

101

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Chapter 11 Proceedings, Emergence and Successor Debt

The bankruptcy petition in 2016 constituted an event of default with respect to the Predecessor’s Prior Credit Facility and Senior Notes. Prior to the Petition Date, these facilities were also in default as a result of nonpayment of interest, violations of financial covenants and the inclusion of a going concern explanatory paragraph in the audit opinion of our 2015 annual financial statements. The enforcement of any obligations under the Predecessor’s debt was automatically stayed as a result of the Chapter 11 Cases.

On the Effective Date, our obligations under the Senior Notes, including principal and accrued interest, were fully extinguished in exchange for equity in the Successor. In addition, our Prior Credit Facility, previously consisting of a senior secured revolving credit facility, was restructured into the Ninth Restated Credit Agreement (the Exit Credit Facility) consisting of a senior secured first-out revolving credit facility (the Exit Revolver) and a senior secured second-out term loan (the Exit Term Loan). On the Effective Date, the entire balance on the Prior Credit Facility in the amount of $444,440 was repaid while we received gross proceeds, before lender fees, representing the opening balances on our Exit Revolver and Exit Term Loan of $120,000 and $150,000, respectively.

Concurrent with the receipt of cash proceeds from the sale of our EOR assets, we fully repaid the outstanding balance of the Exit Term Loan and paid down $10,900 on the Exit Revolver in November 2017. On December 21, 2017, we entered into the Tenth Restated Credit Agreement (the New Credit Facility).

New Credit Facility

The New Credit Facility is a $400,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our New Credit Facility is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base on December 21, 2017, was $285,000 and the first borrowing base redetermination has been set for on or about May 1, 2018. Availability on the New Credit Facility as of December 31, 2017, after taking into account outstanding borrowings and letters of credit on that date, was $157,072.

Other Provisions

Interest payment dates are dependent on the type of borrowing. In the case of Alternate Base Rate loans, interest is payable quarterly in arrears. In the case of Adjusted LIBO Rate borrowings, interest is payable on the last day of each relevant interest period and, in the case of any interest period longer than three months, on each successive date three months after the first day of such interest period.

102

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others.

The New Credit Facility is guaranteed by all of our wholly owned subsidiaries, subject to customary exceptions, and is secured by first priority security interests on substantially all of our assets.

Predecessor Debt

Senior Notes

The Senior Notes were our senior unsecured obligations and were redeemable, in whole or in part, prior to their maturity at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption. Interest on the Senior Notes was payable semi-annually, and the principal was due upon maturity.

During December 2015, we repurchased approximately $42,045 of our outstanding Senior Notes on the open market for $9,995 in cash. As a result, we recorded a gain on extinguishment of debt of $31,590 for the year ended December 31, 2015.

Certain of the Senior Notes were issued at a discount or a premium which is amortized to interest expense over the term of the respective series of Senior Notes. Net amortization of the discount (premium) was $32 and $945 during the years ended December 31, 2016, and 2015.

In March 2016 we wrote off the remaining unamortized issuance costs, premium and discount related to our Senior Notes. These deferred items are typically amortized over the life of the corresponding bond. However, as a result of not paying the interest due on our 2021 Senior Notes by the end of our grace period on March 31, 2016, we triggered an Event of Default on our Senior Notes. While uncured, the Event of Default effectively allows the lender to demand immediate repayment, thus shortening the life of our Senior Notes. As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount on March 31, 2016, as follows:

Non-cash expense for write-off of debt issuance costs on Senior Notes	$	17,756
Non-cash expense for write-off of debt discount costs on Senior Notes		4,014
Non-cash gain for write-off of debt premium on Senior Notes		(4,800	)
Total	$	16,970

Pursuant to accounting guidance, while in bankruptcy, we did not accrue interest expense on our Senior Notes during the pendency of the Chapter 11 Cases as we did not expect to pay such interest. As a result, reported interest expense was $22,582 and $65,225 lower than contractual interest for the Predecessor periods of January 1, 2017 to March 21, 2017, and the year ended December 31, 2016.

As discussed in “Note 3—Chapter 11 reorganization”, on the Effective Date, our obligations with respect to the Senior Notes, including principal and accrued interest, were cancelled and holders of the Senior Notes received their agreed-upon pro-rata share of the Successor’s equity.

Prior Credit Facility

In April 2010, we entered into an Eighth Restated Credit Agreement (the Prior Credit Facility), a senior secured revolving credit facility collateralized by our oil and natural gas properties, and, as amended, was originally scheduled to mature on November 1, 2017. Availability under our Prior Credit Facility was subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually. The initial borrowing base on our Prior Credit Facility for 2016 was $550,000; however subsequent to the defaults on this facility in March 2016, we had no availability under the facility until our debt was restructured upon exiting bankruptcy.

Amounts borrowed under our Prior Credit Facility were subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elected to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at December 31, 2016, was subject to the ABR which resulted in a weighted average interest rate of 5.25% on the outstanding amount. This rate did not include an additional 2.00% default margin which was waived by the Lenders pursuant to our Reorganization Plan.

103

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Our Prior Credit Facility, as amended, also had certain negative and affirmative covenants that required, among other things, maintaining a Current Ratio, a Consolidated Net Secured Debt to Consolidated EBITDAX ratio and an Interest Coverage Ratio (all ratios as defined in the amendment). Subsequent to our debt defaults in March 2016 and through the pendency of our Chapter 11 Cases, we ceased quarterly reporting of our covenant compliance, which included these ratios, to the administrative agent of the facility.

Pursuant to the Reorganization Plan and in conjunction with a repayment of the entire balance of $444,440 on the Effective Date, our Prior Credit Facility was amended and restated in its entirety by the Exit Credit Facility as discussed above.

Capital Leases

In 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool. The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are $3,181 annually. In conjunction with the sale of our EOR assets, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank National Association. The subleases are structured such that the lease payments and remaining lease term are identical to the original leases.

Note 9: Derivative instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas and natural gas liquids. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. As of December 31, 2017, our derivatives consisted of commodity price swaps and collars. See “Note 1—Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for derivative transactions.

Commodity price swaps allow us to receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (purchased put) and ceiling price (sold call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party.

The following table summarizes our crude oil derivatives outstanding as of December 31, 2017:

			Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls		Swaps		Purchased puts		Sold calls
2018
Swaps		2,116	$	54.92	$	—	$	—
Collars		183	$	—	$	50.00	$	60.50
2019
Swaps		1,312	$	54.26	$	—	$	—
2020
Swaps		1,004	$	51.32	$	—	$	—

104

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

The following table summarizes our natural gas derivative instruments outstanding as of December 31, 2017:

Period and type of contract	Volume BBtu		Weighted average fixed price per MMBtu
2018
Swaps		10,491	$	2.87
2019
Swaps		7,632	$	2.81
2020
Swaps		3,600	$	2.77

In February 2018, we renegotiated the fixed pricing of certain crude oil swaps scheduled to settle during 2018 in exchange for entering crude oil swaps, scheduled to settle from 2020 through 2021, at lower-than-market pricing. The renegotiated swaps cover 1,086 MBbls and have a new fixed price of $60.00 per barrel, replacing the original weighted average fixed price of $54.80 per barrel. The new crude oil swaps scheduled to settle from 2020 through 2021 have weighted average fixed prices of $46.26 and $44.34 per barrel, respectively, and cover 543 MBbls each year.

On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts, originally scheduled to settle from 2015 through 2017 and covering 495 MBbls of oil and 12,280 BBtu of natural gas, in order to maintain compliance with the hedging limits imposed by covenants under our Prior Credit Facility. As a result, we received net proceeds of $15,395 which are included in “non-hedge derivative (losses) gains” disclosed below for the year ended December 31, 2015.

Due to defaults under the master agreements governing our derivative contracts, our outstanding derivative positions were early terminated in May 2016. These derivative contracts, originally scheduled to settle from 2016 through 2018, covered 3,400 MBbls of oil and 28,800 BBtu of natural gas. Proceeds from the early terminations, inclusive of amounts receivable at the time of termination for previous settlements, totaled $119,303. Of this amount, in the third quarter of 2016, $103,560 was utilized to offset outstanding borrowings under our Prior Credit Facility and the remainder was remitted to the Company.

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the consolidated balance sheets at fair value. See “Note 10—Fair value measurements” for additional information regarding fair value measurements. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.

	Successor								Predecessor
	As of December 31, 2017								As of December 31, 2016
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas derivative contracts	$	1,332	$	(1,054	)	$	278		$	184	$	(3,658	)	$	(3,474	)
Crude oil derivative contracts		—		(13,404	)		(13,404	)		—		(9,895	)		(9,895	)
Total derivative instruments		1,332		(14,458	)		(13,126	)		184		(13,553	)		(13,369	)
Less:
Netting adjustments (1)		1,332		(1,332	)		—			184		(184	)		—
Derivative instruments - current		—		(8,959	)		(8,959	)		—		(7,525	)		(7,525	)
Derivative instruments - long-term	$	—	$	(4,167	)	$	(4,167	)	$	—	$	(5,844	)	$	(5,844	)

(1)

Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted only to the extent that they related to the same current versus noncurrent classification on the balance sheet.

Effect of derivative instruments on the consolidated statements of operations

105

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

“Non-hedge derivative (losses) gains” in the consolidated statements of operations is comprised of the following:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through		Year ended December 31,
	December 31, 2017			March 21, 2017		2016			2015
Change in fair value of commodity price derivatives	$	(46,478	)	$	46,721	$	(176,607	)	$	(88,317	)
Settlement gains on commodity price derivatives		15,676			1,285		62,626			218,210
Settlement gains on early terminations of commodity price derivatives		—			—		91,144			15,395
Non-hedge derivative (losses) gains	$	(30,802	)	$	48,006	$	(22,837	)	$	145,288

Note 10: Fair value measurements

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see “Note 9—Derivative instruments”). We had no Level 1 assets or liabilities as of December 31, 2017 or December 31, 2016. Our derivative contracts classified as Level 2 as of December 31, 2017 and 2016 consisted of commodity price swaps which are valued using an income approach. Future cash flows from these derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at a rate that captures our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.

As of December 31, 2017 and 2016 our derivative contracts classified as Level 3 consisted of collars. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or our counterparty credit risk for derivative assets.

The fair value hierarchy for our financial assets and liabilities is shown by the following table:

	Successor									Predecessor
	As of December 31, 2017									As of December 31, 2016
	Derivative assets			Derivative liabilities			Net assets (liabilities)			Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	1,332		$	(14,163	)	$	(12,831	)	$	184		$	(13,455	)	$	(13,271	)
Significant unobservable inputs (Level 3)		—			(295	)		(295	)		—			(98	)		(98	)
Netting adjustments (1)		(1,332	)		1,332			—			(184	)		184			—
	$	—		$	(13,126	)	$	(13,126	)	$	—		$	(13,369	)	$	(13,369	)

(1)

Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.

106

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy were as follows for the periods presented:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			December 31,
Net derivative assets (liabilities)	December 31, 2017			March 21, 2017			2016
Beginning balance	$	715		$	(98	)	$	123,068
Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains		(1,010	)		813			(9,314	)
Settlements received		—			—			(113,852	)
Ending balance	$	(295	)	$	715		$	(98	)
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$	(1,010	)	$	813		$	(98	)

Nonrecurring fair value measurements

Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the years ended December 31, 2017 and 2016 were escalated using an annual inflation rate of 2.30% and 2.42%, respectively. The estimated future costs to dispose of properties added once we emerged from bankruptcy through December 31, 2017, were discounted, depending on the economic remaining estimated life of the property or the expected timing of the plugging and abandonment activity, with a credit-adjusted risk-free rate ranging from 5.13% to 7.63%. The discount rate used for the year ended December 31, 2016, was our weighted average credit-adjusted risk-free interest rate ranging from 8.20% to 20.00%. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 11—Asset retirement obligations” for additional information regarding our asset retirement obligations.

Impairment of long-lived assets. As discussed in “Note 1—Nature of operations and summary of significant accounting policies”, we recorded an impairment of $6,015 during the second quarter of 2015 related to our four stacked drilling rigs and drill pipe. The estimated fair value related to the impairment assessment was primarily based on third party estimates and, therefore, was classified within Level 3 of the fair value hierarchy. No impairment was recognized on our drilling rigs for the years ended December 31, 2017 and 2016. As discussed in “Note 1—Nature of operations and summary of significant accounting policies,” our drilling rigs were sold in January 2017.

Fair value of other financial instruments

Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.

The carrying value and estimated fair value of our debt at December 31, 2017 and 2016 were as follows:

	Successor				Predecessor
	December 31, 2017				December 31, 2016
Level 2	Carrying value (1)		Estimated fair value		Carrying value (1)		Estimated fair value
New Credit Facility	$	127,100	$	127,100	$	—	$	—
Other secured debt		9,177		9,177		10,029		10,029
9.875% Senior Notes due 2020		—		—		298,000		268,200
8.25% Senior Notes due 2021		—		—		384,045		344,680
7.625% Senior Notes due 2022		—		—		525,910		470,689

(1)	The carrying value excludes deductions for debt issuance costs and discounts.

107

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

The carrying value of our New Credit Facility and other secured long-term debt approximates fair value as the rates are comparable to those at which we could currently borrow under similar terms, are variable and incorporate a measure of our credit risk. The fair value of our Senior Notes was estimated based on quoted market prices. We have not disclosed the fair value of outstanding amounts under our Prior Credit Facility as of December 31, 2016, as it was not practicable to obtain a reasonable estimate of such value while the Predecessor was in bankruptcy.

See “Note 1—Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for fair value measurements.

Concentrations of credit risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our credit facilities at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a Lender, or an affiliate of a Lender, under our credit facilities can be offset against amounts owed to such counterparty Lender. As of December 31, 2017, the counterparties to our open derivative contracts consisted of four financial institutions.

The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements.

	Offset in the consolidated balance sheets									Gross amounts not offset in the consolidated balance sheets
	Gross assets (liabilities)			Offsetting assets (liabilities)			Net assets (liabilities)			Derivatives (1)		Amounts outstanding under credit facilities (2)		Net amount
Successor - December 31, 2017
Derivative assets	$	1,332		$	(1,332	)	$	—		$	—	$	—	$	—
Derivative liabilities		(14,458	)		1,332			(13,126	)		—		—		(13,126	)
	$	(13,126	)	$	—		$	(13,126	)	$	—	$	—	$	(13,126	)

Predecessor - December 31, 2016
Derivative assets	$	184		$	(184	)	$	—		$	—	$	—	$	—
Derivative liabilities		(13,553	)		184			(13,369	)	$	—		—		(13,369	)
	$	(13,369	)	$	—		$	(13,369	)	$	—	$	—	$	(13,369	)

(1)

Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they related to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.

(2)

The amount outstanding under our credit facilities that is available to offset out net derivative assets due from counterparties that are lenders under our credit facilities.

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our credit facilities. Payment on our derivative contracts could be accelerated in the event of a default on our New Credit Facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $14,458 at December 31, 2017.

Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.

108

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Commodity sales to our top three purchasers accounted for the following percentages of our total commodity sales, excluding the effects of hedging activities, for the years ended December 31:

	Successor			Predecessor
	2017			2016			2015
Coffeyville Resources LLC		20.9	%		19.3	%		14.5	%
Phillips 66 Company		14.6	%		15.1	%		11.8	%
Valero Energy Corporation		13.3	%		15.6	%		20.7	%

If we were to lose a purchaser, we believe we are able to secure other purchasers for the commodities we produce.

Note 11: Asset retirement obligations

The following table presents the balance and activity of our asset retirement obligations:

Liability for asset retirement obligations as of December 31, 2015 - Predecessor	$	48,612
Liabilities incurred in current period		3,918
Liabilities settled and disposed in current period		(2,729	)
Revisions in estimated cash flows		18,364
Accretion expense		3,972
Liability for asset retirement obligations as of December 31, 2016 - Predecessor		72,137
Liabilities incurred in current period		535
Liabilities settled and disposed in current period		(869	)
Revisions in estimated cash flows		181
Accretion expense		1,249
Liability for asset retirement obligations as of March 21, 2017 - Predecessor	$	73,233
Fair value fresh-start adjustment	$	(2,757	)
Liability for asset retirement obligations as of March 21, 2017 - Successor	$	70,476
Liabilities incurred in current period		2,498
Liabilities settled and disposed in current period		(44,097	)
Revisions in estimated cash flows		4,248
Accretion expense		2,865
Liability for asset retirement obligations as of December 31, 2017 - Successor	$	35,990
Less current portion included in accounts payable and accrued liabilities		2,774
Asset retirement obligations, long-term	$	33,216

Liabilities incurred include obligations related to new wells drilled and wells acquired during the period. Liabilities settled and disposed for the Successor period increased significantly when compared to previous periods largely due to the sale of our EOR assets. Revisions in estimated cash flows for the Successor period was largely driven by a reduction in the estimated lives of certain wells and to a lesser extent, higher than expected remediation costs for certain wells we are currently plugging in the Gulf Coast.

We had funds held in escrow that were legally restricted for certain of our asset retirement obligations. The funds were discharged upon the sale of our EOR assets. The balance of this escrow account was $1,519 at December 31, 2016, and is included in “Other assets” in our consolidated balance sheets.

See “Note 10—Fair value measurements” for additional information regarding fair value measurements.

Note 12: Income taxes

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. We are subject to U.S. federal corporate income taxes, state income tax in states where business is conducted (most notably Oklahoma), and margin tax in the state of Texas.

109

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Tax Cuts and Jobs Act. On December 22, 2017, the Tax Cuts and Jobs Act (the “2017 Tax Act”) was enacted. The 2017 Tax Act amends existing U.S. tax laws that impact the company, most notably a reduction of the maximum U.S. federal corporate income tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017.

The other changes to existing U.S. tax laws as a result of the 2017 Tax Act, which we believe have the most significant impact on the our federal corporate income taxes are as follows:

•

Preservation of long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling costs;

•

Limitations regarding the deductibility of interest expense to 30% of the taxpayer’s adjusted taxable income after December 31, 2017;

•

Limitations of the utilization of net federal operating loss carryforwards to 80% of taxable income for losses arising after December 31, 2017 with an indefinite carryforward;

•

Modified provisions related to the limitations on deductions for executive performance based compensation; and

•

Repeal of the corporate alternative minimum tax (“AMT”) and allowing taxpayers to claim a refund on any AMT credit carryovers from 2018 through 2022.

Reduction of the U.S. Corporate Income Tax Rate. We measure deferred tax assets and liabilities using enacted tax rates that will apply in the years in which the temporary differences are expected to be recovered or paid. Accordingly, our deferred tax assets and liabilities were remeasured to reflect the reduction in the U.S. corporate income tax rate from 35 percent to 21 percent, resulting in a $112,715 decrease in net deferred tax assets for the year ended December 31, 2017 and a 95% decrease to our effective tax rate. A corresponding change was recorded to the valuation allowance, and therefore there was no impact to current period income tax expense.

Section 162(m) Limitation on Compensation . Chaparral’s management compensation includes performance based compensation that has been previously deductible. The 2017 Tax Act made certain changes to section 162(m) of the Internal Revenue Code which impacts the deductibility of performance based stock compensation paid to executives after January 1, 2018 including expanding the definition of a covered employee and eliminating the exception for performance based compensation. As a result, we recorded a provisional Section 162(m) adjustment of $8,200 related to stock based compensation. We will monitor future guidance set forth by the U.S. Treasury Department, the IRS, state tax authorities and other standard-setting bodies with regard to Section 162(m) provisions under the 2017 Tax Act, and anticipate completing our analysis prior to filing our 2017 tax return in the third quarter of 2018, which is within the one year measurement period required under Staff Accounting Bulletin No. 118 issued by the SEC.

We recognized the income tax effects of the 2017 Tax Act in our 2017 financial statements in accordance with Staff Accounting Bulletin No. 118, issued by SEC Staff to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the 2017 Tax Act. We have recognized the tax impacts related to the remeasurement of deferred tax assets and liabilities and included these amounts in our Consolidated Financial Statements for the year ended December 31, 2017. The ultimate impact may differ from these amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and assumptions we have made, additional regulatory guidance that may be issued and actions we may take as a result of the 2017 Tax Act. Any subsequent adjustment to these amounts will be recorded to adjust the initial recognition of tax reform in the quarter of 2018 when the analysis is complete.

110

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Income tax (benefit) expense from continuing operations consists of the following:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through		Year ended December 31,
	December 31, 2017			March 21, 2017		2016			2015
Current income taxes
Federal	$	(162	)	$	—	$	(10	)	$	(21	)
State		(187	)		37		(92	)		195
Total current income taxes		(349	)		37		(102	)		174
Deferred income taxes
Federal		—			—		—			(161,879	)
State		—			—		—			(15,514	)
Total deferred income taxes		—			—		—			(177,393	)
Income tax (benefit) expense	$	(349	)	$	37	$	(102	)	$	(177,219	)

A reconciliation of the U.S. federal statutory income tax rate to the effective tax rate is as follows:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
	December 31, 2017			March 21, 2017			2016			2015
Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Remeasurement of deferred taxes		(94.7	)%		—			—			—
State income taxes, net of federal benefit		5.8	%		2.2	%		4.1	%		3.1	%
Statutory depletion		0.4	%		—			—			—
Valuation allowance		55.9	%		(25.9	)%		(39.0	)%		(26.5	)%
Other, net		(2.4	)%		(11.3	)%		(0.1	)%		0.1	%
Effective tax rate		—			—			—			11.7	%

111

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Components of the deferred tax assets and liabilities are as follows:

	Successor			Predecessor
	December 31,			December 31,
	2017			2016
Deferred tax assets related to
Asset retirement obligations	$	18,470		$	15,825
Accrued expenses, allowance and other		4,359			31,711
Property and equipment		—			241,126
Derivative instruments		3,379			7,048
Net operating loss carryforwards
Federal		193,010			241,109
State		44,536			33,605
Statutory depletion carryforwards		2,870			4,158
Enhanced oil recovery credit		10,009			—
Alternative minimum tax credit carryforwards		154			308
		276,787			574,890
Less valuation allowance		(215,157	)		(574,338	)
Deferred tax asset		61,630			552
Deferred tax liabilities related to
Property and equipment		(61,333	)		—
Inventories		(297	)		(552	)
Deferred tax liability		(61,630	)		(552	)
Net deferred tax liability	$	—		$	—

Deferred tax asset valuation allowance. The ultimate realization of our deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. We assess the realizability of our deferred tax assets each period by considering whether it is more likely than not that all or a portion of our deferred tax assets will not be realized. We consider all available evidence (both positive and negative) when determining whether a valuation allowance is required. We evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment.

Due to continued tax losses, we maintained our deferred tax asset position at December 31, 2017. We believe that it is more likely than not that these deferred tax assets will not be realized and as such we are maintaining the full valuation allowance against our net deferred tax assets. As a result of the reduction in U.S. federal corporate rate and favorable temporary differences, we reduced our valuation allowance by $359,181 against our deferred tax assets at December 31, 2017, and remain in a full valuation allowance position. The net change in the U.S. federal and state valuation allowance for the year ended December 31, 2017, including discrete items of $408,039 primarily as a result of increase in value of our oil and gas properties in conjunction with implementation of fresh start accounting and the reduction of the maximum U.S. federal corporate income tax under the 2017 Tax Act offset by increases applicable to current year losses.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can determine that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if we recognize taxable income. As long as we conclude that the valuation allowance against its net deferred tax assets is necessary, we likely will not have any additional deferred income tax expense or benefit.

Net operating loss carryforwards. We have federal net operating loss carryforwards of approximately $919,097 at December 31, 2017, which will expire between 2028 and 2037 if not utilized in earlier periods. At December 31, 2017, we have state net operating loss carryforwards of approximately $1,121,523, which will expire between 2018 and 2037 if not utilized in earlier periods. In addition, at December 31, 2017 we had federal percentage depletion carryforwards of approximately $13,668, which are not subject to expiration.

112

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Our ability to utilize our loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “IRC”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% stockholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the IRC imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards after an ownership change. The limitation is generally equal to the product of (a) the fair market value of the equity of the Company multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold.

Important in the determination of the tax attributes of a debtor corporation following emergence from Chapter 11 is the amount of cancellation of indebtedness income realized. On the emergence date, as described in “Note 3—Chapter 11 reorganization,” pursuant to the Reorganization Plan, $1,267,410 of indebtedness, including accrued interest, attributable to our Senior Notes and $2,439 of general unsecured claims were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC of 1986, as amended provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. While we are currently in the process of finalizing the bankruptcy related calculations, it is our expectation that the fair market value of the consideration received by our creditors upon emergence is substantially the same as the adjusted issue price of the indebtedness extinguished. Accordingly, the amount of CODI realized upon emergence may be relatively low, possibly zero. However, to the extent the finally determined fair market value of the consideration is less than the adjusted issue price of the indebtedness, and CODI was realized, such amount of CODI would be excluded from taxable income and would reduce our prior tax attributes, which could include net operating losses, capital losses, alternative minimum tax credits and tax basis in assets. Any reduction of tax attributes is expected to be fully offset by a corresponding decrease in valuation allowance.

The IRC 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. The Company’s emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of the IRC. However, the IRC provides alternatives for taxpayers emerging from a Chapter 11 bankruptcy proceeding that may mitigate or even eliminate an annual limitation. The Company is in the process of analyzing these alternatives in order to minimize the impact of the ownership change on its ability to utilize tax attributes in future periods. This analysis will be dependent on a number of factors, including verifying qualification for each alternative, analyzing the possibility of a second ownership change during the two year period following emergence, and analyzing transactions subsequent to emergence generating taxable gains or losses. The Company will make a final determination regarding the most beneficial alternative upon filing its 2017 U.S. Federal income tax return prior to its extended due date in the fall of 2018.

Note 13: Deferred compensation

Phantom Stock Plan and Restricted Stock Unit Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Plan”), to provide deferred compensation to certain key employees (the “Participants”). Under the Plan, awards generally vested at the end of five years and were cash-settled within 120 days of the vesting date.

Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) as a replacement for the Phantom Plan.

Under the RSU Plan, awards generally vested in equal annual increments over a three-year period and were cash-settled, generally within 120 days of the vesting date.

We did not grant any Phantom Unit or RSU awards during 2016 and due to the severe decline in commodity pricing, which resulted in a steep decline in our estimated proved reserves, the fair value per Phantom Unit and RSU as of January 1, 2017, was $0.00. As of January 1, 2017, there were 98,596 unvested RSUs and 0 unvested Phantom shares, all of which were cancelled upon our emergence from bankruptcy on the Effective Date.

Cash Incentive Plan

We adopted the Long-Term Cash Incentive Plan (the “Cash LTIP”) on August 7, 2015. The Cash LTIP provides additional cash compensation to certain employees of the Company in the form of awards that generally vest in annual increments over a four-year

113

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

period. Since the awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We accrue for the cost of each annual increment over the period service is required to vest. A summary of compensation expense for the Cash LTIP is presented below:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
Cash LTIP expense (net of amounts capitalized)	$	1,192	$	5	$	696	$	410
Cash LTIP grants		5,637		—		—		3,297
Cash LTIP payments		1,285		42		666		—

As of December 31, 2017, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $1,476.

2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserved a total of 86,301 shares of the Predecessor’s Class A common stock for awards issued under the 2010 Plan. All of our Affiliated Entities’ employees, officers, directors, and consultants, as defined in the 2010 Plan, were eligible to participate in the 2010 Plan.

The awards granted under the 2010 Plan consisted of shares that were subject to service vesting conditions (the “Time Vested” awards) and shares that were subject to market and performance vested conditions (the “Performance Vested” awards). As of result of our bankruptcy, the estimated fair value of our Time Vested restricted awards was $0.00 per share since the Petition Date.

A summary of our restricted stock activity for the Predecessor period is presented below:

	Time Vested							Performance Vested
	Weighted average grant date fair value		Restricted shares			Vest date fair value		Weighted average grant date fair value		Restricted shares
	($ per share)							($ per share)
Unvested and outstanding at January 1, 2015 - Predecessor	$	791.52		25,834				$	292.92		38,943
Granted	$	533.80		610				$	113.90		599
Vested	$	775.17		(8,468	)	$	4,497	$	—		—
Forfeited	$	774.21		(3,997	)			$	323.53		(11,094	)
Unvested and outstanding at December 31, 2015 - Predecessor	$	795.13		13,979				$	278.97		28,448
Granted	$	—		—				$	—		—
Vested	$	798.85		(5,279	)	$	93	$	—		—
Forfeited	$	799.30		(2,033	)			$	283.99		(6,973	)
Unvested and outstanding at December 31, 2016 - Predecessor	$	790.91		6,667				$	277.33		21,475
Granted	$	—		—				$	—		—
Vested	$	812.91		(2,602	)	$	—	$	—		—
Forfeited	$	785.70		(468	)			$	195.75		(986	)
Cancelled	$	775.66		(3,597	)			$	281.26		(20,489	)
Unvested and outstanding at March 21, 2017 - Predecessor				—							—

During 2016 and 2015 we repurchased and canceled 2,597 and 5,725 vested shares, respectively.

2017 Management Incentive Plan

As discussed in “Note 3—Chapter 11 reorganization,” our Reorganization Plan authorized the issuance of 7% of outstanding Successor common shares on a fully diluted basis toward a new management incentive plan. On August 9, 2017, we adopted the Chaparral Energy, Inc. Management Incentive Plan (the “MIP”). The MIP provides for the following types of awards: options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other incentive awards. The aggregate number of shares of Class A common stock, par value $0.01 per share, reserved for issuance pursuant to the MIP was initially set at 3,388,832 subject to changes in the event additional shares of common stock are issued under our Reorganization Plan. The MIP contemplates

114

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

that any award granted under the plan may provide for the earlier termination of restrictions and acceleration of vesting in the event of a Change in Control, as may be described in the particular award agreement.

Pursuant to the MIP, in 2017, 1,833,136 shares of restricted stock were granted to employees and members of our Board of Directors (the “Board”). Of the grants awarded to employees, 75% were comprised of shares that are subject to service vesting conditions (the “Time Shares”) and 25% were comprised of shares that are subject to performance vested conditions (the “Performance Shares”). All grants to the Board were Time shares.

Upon evaluating the provisions of both Time and Performance Shares, we classified both awards as equity-based awards. Compensation cost will be recognized and measured according to the grant date fair value of the awards which are based on the market price of our common stock currently trading on the OTCQB tier of the OTC Markets Group, Inc.

The Time Shares vest in equal annual installments over the three -year vesting period. The Performance Shares vest in three tranches annually according to performance conditions established each year which generally relate to profitability, drilling results and other strategic goals. See “Note 1—Nature of operations and summary of significant accounting policies” for a discussion of our accounting policies regarding the MIP.

A summary of our restricted stock activity pursuant to our MIP for the Successor period in 2017 is presented below:

	Successor
	Time Shares				Performance Shares
	Weighted average grant date fair value		Restricted shares		Weighted average grant date fair value		Restricted shares
	($ per share)				($ per share)
Unvested and outstanding at March 21, 2017	$	—		—	$	—		—
Granted (1)	$	20.11		1,403,626	$	20.12		429,510
Vested	$	—		—	$	20.05		(152,421	)
Cancelled	$	—		—	$	20.05		(7,616	)
Unvested and outstanding at December 31, 2017	$	20.11		1,403,626	$	20.15		269,473

________________________________________________________

(1)

Includes 269,473 Performance Shares attributable to 2018 and 2019 performance conditions where performance goals were not established at the time the awards were granted. Also includes 89,955 Performance Shares attributable to 2017 conditions where determination of accomplishment is discretionary. Under accounting guidance, a grant date for measurement purposes was not established for these awards when they were initially granted but instead will be established when performance goals have been determined, for the former, or when vesting is determined, for the latter.

We have the ability to repurchase shares for tax withholding or pursuant to certain share repurchase provisions in our MIP award agreements. However, our employees also have the ability to sell shares on the open market to cover employee tax withholdings. There have been no repurchases of vested shares in 2017. We expect to repurchase approximately 235,000 shares in 2018 for tax withholding purposes. Based on the market price of $23.69 per share, the aggregate intrinsic value of unvested restricted shares outstanding was $39,636 as of December 31, 2017.

Companywide stock award

In December 2017, we issued 100 shares to each employee for a total of 20,100 shares. There were no vesting requirements for these awards and thus compensation was recognized in full on the award date based on the closing price of our common stock on that date. The compensation cost is included in the table below.

Stock-based compensation cost

Compensation cost is calculated net of forfeitures. As allowed by recent accounting guidance, we will recognize the impact of forfeitures on expense due to employee terminations as they occur instead of incorporating an estimate of such forfeitures. For awards with performance conditions, we will assess the probability that a performance condition will be achieved at each reporting period to determine whether and when to recognize compensation cost.

115

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. Stock-based compensation expense is as follows for the periods indicated:

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017
	through			through			Year ended December 31,
	December 31, 2017			March 21, 2017			2016			2015
Stock-based compensation expense (credit)	$	12,606		$	194		$	(6,196	)	$	(2,169	)
Less: stock-based compensation cost capitalized		(2,773	)		(39	)		958			229
Total stock-based compensation expense (credit), net	$	9,833		$	155		$	(5,238	)	$	(1,940	)
Payments for stock-based compensation	$	—		$	—		$	49		$	3,991
Recognized tax expense associated with stock-based compensation	$	—		$	—		$	—		$	(229	)

During the third quarter of 2016, we recorded a cumulative catch up adjustment of $5,985 to reverse the aggregate compensation cost associated with our Performance Vested awards in order to reflect a decrease in the probability that requisite service would be achieved for these awards. Expense during 2016 was a credit as a result of the aforementioned catch up adjustment, forfeitures and the reduction in fair value of our liability-based awards. Payments for stock-based compensation were $0, $49, and $3,991 during 2017, 2016, and 2015, respectively As of December 31, 2017, and 2016, accrued payroll and benefits payable included $0 and $0, respectively, for stock-based compensation costs expected to be settled within the next twelve months. There are no recorded liabilities with respect to stock-based-compensation as of December 31, 2017, since all outstanding awards are equity awards. There are no recorded liabilities with respect to stock-based-compensation as of December 31, 2016, since the estimated fair value of our Time Vested restricted awards was $0.00 per share since the Petition Date. Unrecognized stock-based compensation cost of approximately $19,174 as of December 31, 2017 is expected to be recognized over a weighted-average period of 1.5 years. This amount does not include Performance Shares attributable to 2018 and 2019 performance conditions since requisite service for those shares had not commenced as of December 31, 2017 .

Note 14: Stockholders' equity

Predecessor Common Stock

Our Amended and Restated Certificate of Incorporation filed April 12, 2010, created seven classes of $0.01 par value per share common stock, classes A through G, with the rights and preferences summarized below. The class A common stock carries standard voting, dividend and liquidation rights. The class B, C and D common stock was issued to our former stockholders, with a separate class issued to each stockholder. The class E and class F common stock was issued to CCMP. One share of class G common stock was issued to two former stockholders.

On the Effective Date, all existing common stock of the Predecessor was cancelled and each holder of such stock did not receive any distribution or retain any property on account of their stock interest.

Successor Common Stock

On the Effective Date, we issued a total of 44,982,142 shares of Successor common stock consisting of 37,110,630 shares of Class A common stock and 7,871,512 shares Class B common stock pursuant to our Reorganization Plan and our new organizational documents. The new Class A shares and Class B shares have identical economic and voting rights. However, Class B shares are subject to certain redemption provisions upon demand to the Company by certain stockholders undertaking an initial public offering, as described in our Third Amended and Restated Certificate of Organization. Further, shares of Class B Common Stock are subject to automatic conversion to Class A Common Stock upon the earlier of an initial public offerings meeting certain conditions, whether or not the redemption provisions were exercised, or December 15, 2018.

116

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Summary of changes in common stock

The following is a summary of the changes in our common shares outstanding:

	Common Stock
	Class A			Class B			Class C			Class E			Class F			Class G			Total
Shares issued at January 1, 2015 - Predecessor		364,896			344,859			209,882			504,276			1			2			1,423,916
Restricted stock issuance		1,209			—			—			—			—			—			1,209
Restricted stock repurchased		(5,725	)		—			—			—			—			—			(5,725	)
Restricted stock forfeited		(15,091	)		—			—			—			—			—			(15,091	)
Shares issued at December 31, 2015 - Predecessor		345,289			344,859			209,882			504,276			1			2			1,404,309
Restricted stock repurchased		(2,597	)		—			—			—			—			—			(2,597	)
Restricted stock forfeited		(9,006	)		—			—			—			—			—			(9,006	)
Shares issued at December 31, 2016 - Predecessor		333,686			344,859			209,882			504,276			1			2			1,392,706
Restricted stock forfeited		(1,454	)		—			—			—			—			—			(1,454	)
Restricted stock cancelled		(8,964	)		—			—			—			—			—			(8,964	)
Shares issued at March 21, 2017 - Predecessor		323,268			344,859			209,882			504,276			1			2			1,382,288
Cancellation of Predecessor equity		(323,268	)		(344,859	)		(209,882	)		(504,276	)		(1	)		(2	)		(1,382,288	)
Shares issued at March 21, 2017 - Predecessor		—			—			—			—			—			—			—

Issuance of Successor common stock - rights offering		4,197,210			—			—			—			—			—			4,197,210
Issuance of Successor common stock - backstop premium		367,030			—			—			—			—			—			367,030
Issuance of Successor common stock - settlement of claims		32,546,390			7,871,512			—			—			—			—			40,417,902
Shares issued at March 21, 2017 - Successor		37,110,630			7,871,512			—			—			—			—			44,982,142
Stock-based compensation		1,853,236			—			—			—			—			—			1,853,236
Restricted stock cancelled		(7,616	)		—			—			—			—			—			(7,616	)
Shares issued at December 31, 2017 - Successor		38,956,250			7,871,512			—			—			—			—			46,827,762

Note 15: Retirement benefits

We provide a 401(k) retirement plan for all employees and matched 100% of employee contributions up to 7% of each employee’s gross wages during 2017, 2016 and 2015. At December 31, 2017, 2016, and 2015, there were 210, 315, and 395 employees, respectively, participating in the plan. Our contribution expense was as follows:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
401(k) contribution expense	$	1,267	$	396	$	1,781	$	2,363

Note 16: Commitments and contingencies

Letters of Credit. Standby letters of credit (“Letters”) available under our New Credit Facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. Our outstanding Letters, as of both December 31, 2017 and 2016, totaled $828. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the years ended December 31, 2017, 2016, or 2015.

Commitments. We have commitments totaling $9,620, substantially all of which are due in one year. These commitments are primarily related to contracts for drilling rigs which extend through mid-2018 and the purchase of seismic data.

117

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Our contracts to purchase CO ₂ for our EOR operations were discharged upon the sale of our EOR assets.

Operating Leases. We rent equipment used on our oil and natural gas properties and have operating lease agreements for CO ₂ recycle compressors and office equipment. Rent expense for the years ended December 31, 2017, 2016, and 2015 was $4,971, $6,693, and $8,753, respectively. Our leases relating to office equipment have terms of up to five years. In June 2014, we entered into two non-cancelable operating leases for CO ₂ recycle compressors at our EOR facilities which expire in 2021. In May 2016, we took delivery of an additional CO ₂ compressor for which we have entered into a non-cancelable operating lease which expires in 2023. In conjunction with the sale of our EOR assets, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank National Association. The subleases are structured such that the lease payments and remaining lease term are identical to the original leases.

As of December 31, 2017, total remaining payments associated with our operating leases, of which substantially all were related to our CO ₂ compressors, were:

2018	$	1,365
2019		1,361
2020		1,330
2021		1,297
2022		278
2023 and thereafter		204
	$	5,835

Employment Agreements. Prior to the Effective Date, Mr. K. Earl Reynolds, the Company’s Chief Executive Officer, was employed under the provisions of an employment agreement effective January 1, 2014. As part of our Reorganization Plan, we entered into a new employment agreement with Mr. Reynolds on the Effective Date.

Prior to the Effective Date, Mr. Joseph O. Evans, the Company’s Chief Financial Officer and Executive Vice President, was employed under the provisions of an employment agreement effective April 12, 2010. As part of our Reorganization Plan, we entered into a new employment agreement with Mr. Evans on the Effective Date.

Prior to the Effective Date, Mr. James M. Miller, the Company’s Senior Vice President—Operations, was employed under the provisions of an employment agreement effective April 12, 2010. As part of our Reorganization Plan, we entered into a new employment agreement with Mr. Miller on the Effective Date.

Mr. Jeff Smail, the Company’s Vice President – Corporate Finance, Planning/Reserves and Marketing, is employed under the provisions of an employment agreement effective May 1, 2015.

The employment agreements for Messrs. Reynolds, Evans, Miller and Smail each provides, among other things, for a minimum salary level, subject to review and potential increase by the Compensation Committee of the Board of Directors, as well as participation in the Company's incentive plans and other employee benefits. The employment agreements also obligate us to pay certain separation benefits in the event of voluntary termination, termination without cause, termination for good reason and termination in the event of disability or death.

Litigation and Claims

118

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

indicated they seek damages in excess of $ 5,000 , the majority of which would be comprised of interest and may increase with the passage of time. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court.

In addition to filing claims on behalf of the named and putative plaintiffs, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of $150,000 in our Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90,000 inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims, to which we will also object. On June 7, 2017 we appealed the Bankruptcy Court order to the United States District Court for the District of Delaware. Under the Reorganization Plan, the plaintiffs are identified as a separate class of creditors, Class 8. Class 8 claims are entitled to receive their pro rata share of new stock issued to the holders of general unsecured claims (including claims of the Noteholders). Although the members of Class 8 voted to reject the Plan, the Bankruptcy Court confirmed the Plan on March 10, 2017, without objection by the plaintiffs.

We anticipate any monetary liability related to this claim will be discharged. We dispute plaintiffs’ allegations and dispute that the case meets the requirements for a class action .

119

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

defenses. On March 18, 2016, the case was removed to the United States District Court for the Western District of Oklahoma under the Class Action Fairness Act. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. On October 14, 2016, the plaintiffs filed an Amended Complaint adding additional defendants and increasing the Class Area to 25 Central Oklahoma counties. Other defendants filed motions to dismiss the action which was granted on May 12, 2017. On July 18, 2017, plaintiffs filed a Second Amended Complaint adding additional named plaintiffs as putative class representatives and adding three additional counties to the putative class area. In the Second Amended Complaint, plaintiffs seek damages for nuisance, negligence, abnormally dangerous activities, and trespass. Due to Chaparral’s bankruptcy, plaintiffs specifically limit alleged damages related to Chaparral’s disposal activities occurring after our emergence from bankruptcy on March 21, 2017. We moved to dismiss the Second Amended Complaint on September 15, 2017.

Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75,000 in our Chapter 11 Cases. W e filed an objection to class treatment of the proof of claim filed by the West plaintiffs in our Bankruptcy proceeding. The Bankruptcy Court had a hearing on our objection and on February 9, 2018, the Court granted our objection to class treatment of the proof of claim. We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case .

James Butler et al. v. Berexco, L.L.C., Chaparral Energy, L.L.C, et al . On October 13, 2017, a group of fifty-two individual plaintiffs filed a lawsuit in the District Court of Payne County, State of Oklahoma against twenty-six named defendants, including us, and twenty-five unnamed defendants. Plaintiffs are all property owners and residents of Payne County, Oklahoma, and allege salt water disposal activities by the defendants, owners or operators of salt water disposal wells, induced earthquakes which have caused damage to real and personal property, and emotional damages. Plaintiffs claim absolute liability for ultra-hazardous activities, negligence, gross negligence, public and private nuisance, trespass, and ask for compensatory and punitive damages. On December 18, 2018, we moved the court to dismiss the claims against us. Prior to plaintiffs responding to our motion, a hearing on a motion to stay the Butler case was held on January 4, 2018. The judge granted the motion to stay proceedings, ruling from the bench that the Butler case was stayed pending final judgment or denial of class certification in the Lisa West et al. v. ABC Oil Company, Inc. case. Our motion to dismiss will not be considered until the stay is lifted, at which time, if necessary, we will dispute plaintiffs’ claims, dispute that the remedies requested are available under Oklahoma law, and vigorously defend the case .

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. In addition, other proofs of claim have been filed in our bankruptcy case which we anticipate repudiating. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows .

120

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 17 : Oil and natural gas activities (unaudited)

Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
Property acquisition costs
Proved properties	$	179	$	527	$	390	$	1,192
Unproved properties		33,901		2,904		15,497		24,735
Total acquisition costs		34,080		3,431		15,887		25,927
Development costs		140,180		32,657		114,472		150,261
Exploration costs		916		1,241		19,055		33,091
Total	$	175,176	$	37,329	$	149,414	$	209,279

Depreciation, depletion, and amortization expense of oil and natural gas properties was as follows:

	Successor		Predecessor
	Period from		Period from
	March 22, 2017		January 1, 2017
	through		through		Year ended December 31,
	December 31, 2017		March 21, 2017		2016		2015
DD&A (1)	$	84,899	$	23,442	$	115,765	$	208,352
DD&A per BOE:	$	12.86	$	13.05	$	12.97	$	20.42

________________________________

(1)	Includes accretion of asset retirement obligations.

Oil and natural gas properties not subject to amortization consists of unevaluated leasehold acquisition costs, capitalized interest related to the leasehold costs and wells or facilities for which reserve volumes are not classified as proved until completed. The costs of unevaluated oil and natural gas properties, by year incurred, consisted of the following:

	Year Cost Incurred
	2017		2016		2015		Total
Leasehold acreage (1)	$	453,437	$	12,959	$	315	$	466,711
Capitalized interest (2)		2,134		—		—		2,134
Wells in progress of completion		13,394		—		—		13,394
Total unevaluated oil and natural gas properties excluded from amortization	$	468,965	$	12,959	$	315	$	482,239

________________________________

(1)

In the past, the costs associated with unevaluated properties typically related to historical acquisition costs of leasehold acreage. However, the year-end balance for 2017 includes an increase in carrying value to fair value of $419,677 as a result of the application of fresh start accounting upon emergence from bankruptcy. See “Note 4—Fresh start accounting.”

(2)

As of December 31, 2017, this amount reflects the cumulative interest capitalized on the historical acquisition cost of leasehold acreage subsequent to our establishing opening balances under fresh start accounting. Interest is not capitalized on amounts related to the fair value gross up discussed above.

The carrying value of wells in progress of completion will be transferred to the amortization base upon completion in 2018. With respect to leasehold acreage, the carrying value of undeveloped leasehold acreage will be evaluated and transferred to the amortization base within the next two to five years. Leasehold acreage also includes value assigned to held-by-production leasehold upon adoption of fresh start accounting; the carrying value of such leasehold will be transferred to the amortization base as those locations are evaluated.

121

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 18 : Disclosures about oil and natural gas activities (unaudited)

The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. (prior to 2017), each an independent petroleum and geological engineering firm, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” 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.

Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2017 are as follows:

	Oil (MBbls)			Natural gas (MMcf)			Natural gas liquids (MBbls)			Total (MBoe)
Proved developed and undeveloped reserves
As of January 1, 2015		101,247			247,756			16,853			159,393
Purchase of minerals in place		38			1,120			46			271
Sales of minerals in place		(2,225	)		(3,656	)		(117	)		(2,951	)
Extensions and discoveries		3,651			13,759			1,096			7,040
Revisions (1)		(19,840	)		(61,973	)		(4,257	)		(34,426	)
Improved recoveries (2)		36,414			—			—			36,414
Production		(5,519	)		(18,788	)		(1,550	)		(10,200	)
Balance at December 31, 2015		113,766			178,218			12,071			155,541
Extensions and discoveries		4,037			18,085			1,499			8,550
Revisions (1)		(16,312	)		(44,965	)		(57	)		(23,864	)
Production		(4,870	)		(15,889	)		(1,408	)		(8,926	)
Balance at December 31, 2016		96,621			135,449			12,105			131,301
Sales of minerals in place		(74,918	)		(1,663	)		(46	)		(75,241	)
Extensions and discoveries		8,957			39,843			5,442			21,040
Revisions (1)		3,515			11,135			2,216			7,586
Production		(4,571	)		(14,598	)		(1,395	)		(8,399	)
Balance at December 31, 2017		29,604			170,166			18,322			76,287
Proved developed reserves:
January 1, 2015		54,862			158,265			11,787			93,027
December 31, 2015		40,300			132,323			9,169			71,524
December 31, 2016		28,590			108,800			9,352			56,076
December 31, 2017		18,301			123,451			11,858			50,734
Proved undeveloped reserves:
January 1, 2015		46,385			89,491			5,066			66,366
December 31, 2015		73,466			45,895			2,902			84,017
December 31, 2016		68,031			26,649			2,753			75,225
December 31, 2017		11,303			46,715			6,464			25,553

(1)

The upward revision in 2017 was due to changes in pricing and costs. The downward revision in our reserves during 2016 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC, revision in the base water flood decline curve at our North Burbank Unit, and the decline in SEC pricing. The downward revision in our reserves during 2015 was primarily due to the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic.

(2)	Improved recoveries in 2015 resulted from the addition of reserves from remaining future phases of CO ₂ injection at our North Burbank EOR unit.

122

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

The following information was developed using procedures prescribed by GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

We believe that, in reviewing the information that follows, the following factors should be taken into account:

•

future costs and sales prices will probably differ from those required to be used in these calculations;

•

actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

•

a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

•

future net revenues may be subject to different rates of income taxation.

Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 9—Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	Successor			Predecessor
	December 31,			December 31,
	2017			2016			2015
Future cash flows	$	2,331,940		$	4,635,481		$	6,327,363
Future production costs		(899,380	)		(1,998,001	)		(2,670,692	)
Future development and abandonment costs		(336,828	)		(1,147,390	)		(1,536,063	)
Future income tax provisions		—			—			(89,999	)
Net future cash flows		1,095,732			1,490,090			2,030,609
Less effect of 10% discount factor		(597,859	)		(961,309	)		(1,345,920	)
Standardized measure of discounted future net cash flows	$	497,873		$	528,781		$	684,689

123

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	For the year ended December 31,
	2017			2016			2015
Beginning of year	$	528,781		$	684,689		$	1,894,700
Sale of oil and natural gas produced, net of production costs		(175,246	)		(141,732	)		(196,319	)
Net changes in prices and production costs		125,795			(296,299	)		(2,230,601	)
Extensions and discoveries		136,887			79,990			101,384
Improved recoveries		—			—			524,436
Changes in future development costs		(4,879	)		278,653			204,199
Development costs incurred during the period that reduced future development costs		37,912			63,894			80,103
Revisions of previous quantity estimates (1)		68,428			(223,218	)		(495,794	)
Purchases and sales of reserves in place, net		(238,445	)		—			(47,079	)
Accretion of discount		24,267			68,545			237,134
Net change in income taxes		—			21,139			605,766
Changes in production rates and other		(5,627	)		(6,880	)		6,760
End of year	$	497,873		$	528,781		$	684,689

(1)

Amounts in 2017 are primarily the result of increased volumes due to changes in pricing and costs. Amounts in 2016 are primarily the result of removing proved undeveloped reserves that are not expected to be developed within the five years, a revision in the base water flood decline curve at our North Burbank Unit and the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic. Amounts in 2015 are primarily the result of the decrease in SEC pricing, lower margins on existing reserves and a decrease in taxes as a result of the lower margins.

The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.

	2017		2016		2015
Oil (per Bbl)	$	51.34	$	42.75	$	50.28
Natural gas (per Mcf)	$	2.98	$	2.49	$	2.58
Natural gas liquids (per Bbl)	$	24.17	$	13.47	$	15.84

Note 19: Supplemental quarterly financial information (unaudited)

The following tables present a summary of our unaudited interim results of operations:

	Predecessor		Successor
	First		First			Second		Third			Fourth
	Quarter		Quarter			Quarter		Quarter			Quarter
2017
Total revenues	$	66,531	$	7,808		$	74,048	$	75,947		$	69,276
Operating income (loss) (1)	$	9,752	$	(6,292	)	$	4,600	$	2,135		$	(45,709	)
Net income (loss) (2)(3)	$	1,041,959	$	(19,683	)	$	21,365	$	(19,115	)	$	(101,469	)
Earnings per share:
Basic for Class A and Class B	*		*			$	0.47	$	(0.42	)	$	(2.26	)
Diluted for Class A and Class B	*		*			$	0.47	$	(0.42	)	$	(2.26	)

____________________________________________________________

(1)	Includes loss on impairment of oil and natural gas properties of $42,146 for the fourth quarter.

(2)	Includes a loss from the sale of our EOR assets of $25,163 for the fourth quarter. See “Note 6 —Acquisitions and divestitures” for additional information.

(3)

Includes reorganization items income (expense) related to the Company’s restructuring under Chapter 11 filings of $988,727, $(620), $(1,070), $(858), and $(543) for the Predecessor first quarter, Successor first, second, third, and fourth quarters, respectively. See “Note 4 —Fresh start accounting” for additional information.

* Item not disclosed. See “Note 2—Earnings per share.”

124

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

	Predecessor
	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
2016
Total revenues	$	48,239		$	65,990		$	65,847		$	72,076
Operating income (loss) (1)(2)	$	(103,718	)	$	(209,864	)	$	7,519		$	10,599
Net income (loss) (3)(4)	$	(138,406	)	$	(256,654	)	$	(5,491	)	$	(15,169	)
Earnings per share	*			*			*			*

____________________________________________________________

(1)	Includes loss on impairment of oil and natural gas properties of $77,896 and $203,183 for the first and second quarters, respectively.

(2)	Includes liability management expense of $5,589 and $3,807 for the first and second quarters, respectively. See “Note 1 —Nature of operations and summary of significant accounting policies” for additional information.

(3)	Includes expense from writing-off the Senior Note issuance costs, discount and premium for the first quarter. See “Note 8—Debt” for additional information.

(4)	Includes reorganization items income (expense) related to the Company’s restructuring under Chapter 11 filing of $(5,355), $(5,504), and $(5,861) for the second, third, and fourth quarters, respectively. See “Note 4 —Fresh start accounting” for additional information.

* Item not disclosed. See “Note 2—Earnings per share.”

Note 20: Related party transactions

Pursuant to our Reorganization Plan, on January 5, 2017, we entered into the Retirement Agreement and General Release (the “Retirement Agreement”) with Mark A. Fischer, our former chief executive officer, whereupon Mr. Fischer terminated his employment with the Company on that date. The Retirement Agreement includes severance consisting of cash and certain tangible assets in the amount of $4,038. Mr. Fisher provided consulting services to the Company during the period subsequent to his termination until the Effective Date for which he received warrants to purchase the Company’s common stock (see Note 3 — Chapter 11 reorganization) and cash for a total of $305 in compensation. The expense for Mr. Fischer’s severance and consulting services are reflected in “Reorganization items, net” and “General and administrative” expense, respectively, in our consolidated statement of operations during the 2017 Predecessor period. All amounts due to Mr. Fischer pursuant to the Retirement Agreement have been paid as of December 31, 2017.

125

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCO UNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at December 31, 2017 at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers, or persons performing similar functions, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

•

pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions relating to and the dispositions of our assets;

•

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

•

provide reasonable assurance regarding prevention or the timely detection of unauthorized acquisition, or the use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in the 2013 Internal Control-Integrated Framework , management concluded that our internal control over financial reporting was effective as of December 31, 2017 .

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.

ITEM 9B. OTHER INFORMATION

None.

126

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

ITEM 11. EXECUTIVE COMPENSATION

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

127

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements, Schedules and Exhibits

(1) Financial Statements-Chaparral Energy, Inc. and Subsidiaries:

The Financial Statements listed in the Index to Consolidated Financial Statements are filed as part of this report on Form 10-K (see Part II, Item 8-Financial Statements and Supplementary Data).

(2) Financial Statement Schedules

All other consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.

(3) Exhibits

Exhibit No.		Description

2.1*		First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code, dated March 7, 2017 (Incorporated by reference to Exhibit 1 of Exhibit 99.1 of the Company’s Current Report on Form 8-K filed on March 14, 2017).

2.2*		Asset Purchase and Sale Agreement dated October 13, 2017, by and among Chaparral Energy, L.L.C., Chaparral CO2, L.L.C., Chaparral Real Estate, L.L.C., and Perdure Petroleum, L.L.C. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed on November 21, 2017).

2.3*		Purchase and Sale Agreement dated December 22, 2017, by and among Blake Production Company, Inc., Fairway Energy L.L.C., Vernon Resources L.L.C., ABV Ventures L.L.C., and Chaparral Energy, L.L.C. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed on December 27, 2017).

2.4**		First Amendment to Purchase and Sale Agreement dated January 2, 2018, by and among Blake Production Company, Inc., Fairway Energy L.L.C., Vernon Resources LLC, ABV Ventures LLC and Chaparral Energy, L.L.C.

2.5*		Purchase and Sale Agreement dated December 22, 2017, by and between BVD INC. and Chaparral Energy, L.L.C. (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K filed on December 27, 2017).

3.1*		Third Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc., dated as of March 21, 2017 (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

3.2*		Amended and Restated Bylaws of Chaparral Energy, Inc., dated as of March 21, 2017 (Incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

4.1*		Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

4.2*		Warrant Agreement dated as of March 21, 2017, among Chaparral Energy, Inc. and Computershare Inc. as warrant agent (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

4.3*		Stockholders Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

4.4*		First Amendment to Stockholders Agreement, dated as of March 6 , 2018, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on March 9, 2018).

10.1*†		Form of Indemnification Agreement between Chaparral Energy, Inc. and the directors and officers of Chaparral Energy, Inc. (Incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

128

Exhibit No.		Description

10.2*†		Chaparral Energy, LLC Long-Term Cash Incentive Plan Agreement (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 16, 2015).

10.3*†		Amended and Restated Employment Agreement, dated as of March 21, 2017, by and between the Company and K. Earl Reynolds (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q filed on May 15, 2017).

10.4*†		Amended and Restated Employment Agreement, dated as of March 21, 2017, by and between the Company and Joseph O. Evans (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q filed on May 15, 2017).

10.5*†		Amended and Restated Employment Agreement, dated as of March 21, 2017, by and between the Company and James M. Miller (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q filed on May 15, 2017).

10.6*		Amended and Restated Credit Agreement dated as of March 21, 2017, among Chaparral Energy, Inc. as borrower, the lenders and prepetition borrowers party thereto and JPMorgan Chase Bank, N.A., as administrative agent (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on March 27, 2017).

10.7*		Tenth Restated Credit Agreement, dated as of December 21, 2017, among Chaparral Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on December 27, 2017).

10.8*†		Chaparral Energy, Inc. Management Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on August 15, 2017).

10.9*†		Form of Time Vesting Restricted Stock Award Agreement (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on August 15, 2017).

10.10*†		Form of Time Performance Vesting Restricted Stock Award Agreement (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on August 15, 2017).

21.1		List of Subsidiaries of the Company.

23.1		Consent of Grant Thornton LLP.

23.2		Consent of Cawley, Gillespie & Associates, Inc.

23.3		Consent of Ryder Scott Company, L.P.

31.1		Certification by Principal Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

31.2		Certification by Principal Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

32.1		Certification by Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1		Report of Cawley, Gillespie & Associates, Inc.

99.2*		Findings of Fact, Conclusions of Law and Order Confirming the First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code, as entered by the Bankruptcy Court on March 10, 2017. (Incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K filed on March 14, 2017).

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

129

Exhibit

No.

Description

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

*	Incorporated by reference

**	The schedules and exhibits to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. Chaparral Energy, Inc. will furnish copies of such schedules to the Securities and Exchange Commission upon request.

†	Management contract or compensatory plan or arrangement

130

SIGNAT URES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CHAPARRAL ENERGY, INC.

By:		/s/ K. Earl Reynolds
Name:		K. Earl Reynolds
Title:		Chief Executive Officer
		(Principal Executive Officer)

Date: March 29, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Robert F. Heinemann	Chairman of the Board	March 29, 2018
Robert F. Heinemann

/s/ K. Earl Reynolds	Chief Executive Officer and Director	March 29, 2018
K. Earl Reynolds	(Principal Executive Officer)

/s/ Joseph O. Evans	Chief Financial Officer and Executive Vice President	March 29, 2018
Joseph O. Evans	(Principal Financial Officer and Principal Accounting Officer)

/s/ Douglas E. Brooks	Director	March 29, 2018
Douglas E. Brooks

/s/ Matthew D. Cabell	Director	March 29, 2018
Matthew D. Cabell

/s/ Samuel Langford	Director	March 29, 2018
Samuel Langford

/s/ Kenneth W. Moore	Director	March 29, 2018
Kenneth W. Moore

/s/ Gysle Shellum	Director	March 29, 2018
Gysle Shellum

131

Exhibit 2.4

US 4291685

FIRST AMENDMENT

PURCHASE AND SALE AGREEMENT

This FIRST AMENDMENT TO PURCHASE AND SALE AGREEMENT (this “ Amendment ”) is dated as of January 2, 2018, by and between Blake Production Company, Inc., a Texas corporation, Fairway Energy L.L.C., an Oklahoma limited liability company, Vernon Resources LLC, an Oklahoma limited liability company, and ABV Ventures LLC, an Oklahoma limited liability company (each individually and all collectively referred to herein as “ Seller ”) and Chaparral Energy, L.L.C., an Oklahoma limited liability company (“ Buyer ”). Seller and Buyer are sometimes collectively referred to in this Amendment as the “ Parties ” or individually as a “ Party ”.

WHEREAS, the Parties are parties to that certain Purchase and Sale Agreement dated December 22, 2017 (the “ Purchase Agreement ”);

WHEREAS, the Parties desire and have agreed to amend the Purchase Agreement as more fully set forth herein.

NOW THEREFORE, for good and valuable consideration, the receipt and sufficiency of which is acknowledged, the Parties hereby agree as follows:

1. Amendments .

1.1 Amendment to Section 6 . The first sentence of Section 6 of the Purchase Agreement is hereby amended by deleting it in its entirety and replacing it with the following:

The purchase price for the Assets shall be Thirty-Six Million, Three Hundred Forty-Eight Thousand, Eight Hundred Sixty-Three and 09/100 Dollars ($36,348,863.09), in the respective proportions set forth on Annex I , payable by Buyer to accounts designated in writing by Seller at Closing by wire transfer of immediately available funds, and subject to adjustments as set forth below (the “ Purchase Price ”).

1.2 Amendment to Annex I . Annex I to the Purchase Agreement is hereby deleted in its entirety and replaced with Annex I to this Amendment.

2. Miscellaneous .

2.1 Each of the Parties acknowledges and agrees that it has received good, valuable and adequate consideration, and shall receive substantial benefit from, the execution and delivery of this Amendment.

2.2 Except as expressly modified and amended hereby, the Pur chase Agreement shall continue in full force and effect and the parties ratify and confirm the Purchase Agreement as modified and amended hereby.

2.3 This Amendment and the rights and obligations of the Parties hereto shall be

governed, construed, and enforced in accordance with the laws of the State of Oklahoma.

2.4 This Amendment may be executed by Buyer and Seller in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute one and the same instrument. Any .pdf or other electronic transmission hereof or signature hereon shall, for all purposes, be deemed originals.

[ Remainder of Page Intentionally Left Blank; Signature Pages Follow ]

IN WITNESS WHEREOF, the Parties have executed this Amendment as of the date first written above.

SELLER:

BLAKE PRODUCTION COMPANY, INC.

By: /s/ Blake Vernon

Name:

Title: President

FAIRWAY ENERGY L.L.C.

By: /s/ Blake Vernon

Name:

Title: President

VERNON RESOURCES LLC

By: /s/ James Vernon

Name:

Title: President

ABV VENTURES LLC

By: /s/ Austin Vernon

Name:

Title: President

IN WITNESS WHEREOF, the Parties have executed this Amendment as of the date first written above.

BUYER

CHAPARRAL ENERGY, L.L.C.

By: /s/ Lincoln McElroy

Name:

Title: Attorney-in-fact

Exhibit 21.1

Chaparral Energy Inc.

Subsidiaries

Name of Subsidiary	Jurisdiction of Formation	Effective Ownership
Chaparral Resources, L.L.C.	Oklahoma	Chaparral Energy, Inc. – 100%
Chaparral Real Estate, L.L.C.	Oklahoma	Chaparral Energy, Inc. – 100%
Chaparral CO2 , L.L.C.	Oklahoma	Chaparral Energy, Inc. – 100%
CEI Pipeline, L.L.C.	Texas	Chaparral Energy, Inc. – 100%
Chaparral Energy, L.L.C.	Oklahoma	Chaparral Energy, Inc. – 100%
CEI Acquisition, L.L.C.	Delaware	Chaparral Energy, L.L.C. –100%
Green Country Supply, Inc.	Oklahoma	Chaparral Energy, Inc. – 100%
Chaparral Biofuels, L.L.C.	Oklahoma	Chaparral Energy, Inc. – 100%
Chaparral Exploration, L.L.C.	Delaware	Chaparral Energy, Inc. – 100%
Roadrunner Drilling, L.L.C.	Oklahoma	Chaparral Resources, L.L.C. –100%

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated March 29, 2018, with respect to the consolidated financial statements included in the Annual Report of Chaparral Energy, Inc. on Form 10-K for the year ended December 31, 2017. We consent to the incorporation by reference of said report in the Registration Statements of Chaparral Energy Inc. on Form S-1 (File No. 333-218579, effective June 22, 2017) and Form S-8 (File No. 333-219976, effective August 15, 2017).

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
March 29, 2018

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Cawley, Gillespie & Associates, Inc. hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Chaparral Energy, Inc. (“Chaparral”) for the year ending December 31, 2017. We hereby further consent to (i) the use of the oil and gas reserve information in the Annual Report on Form 10-K of Chaparral for the year ending December 31, 2017, based on the reserve report dated February 6, 2018, prepared by Cawley, Gillespie & Associates, Inc. and (ii) inclusion of our summary report dated February 6, 2018 included in the Annual Report on Form 10-K of Chaparral for the year ending December 31, 2017 to be filed on or about March 29, 2018 as Exhibit 99.1.

We hereby further consent to the incorporation by reference in the Registration Statements on Form S-1 (File No. 333-218579, effective June 22, 2017) and Form S-8 (File No. 333-219976, effective August 15, 2017), as same may be amended from time to time, of such information.


/s/ Cawley, Gillespie & Associates, Inc.

Cawley, Gillespie & Associates, Inc.

Petroleum Engineers

Fort Worth, Texas

March 29, 2018

TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849

1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191

EXHIBIT 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Ryder Scott Company, L.P. hereby consents to incorporation by reference in the Registration Statements of Chaparral Energy, Inc. (“Chaparral”) on Form S-1 (File No. 333-218579, effective June 22, 2017) and Form S-8 (File No. 333-219976, effective August 15, 2017), as same may be amended from time to time, of the information contained in our report with respect to estimated future reserves and income attributable to certain of Chaparral’s leasehold interests as of December 31, 2016, and the use in Chaparral’s Annual Report on Form 10-K for the year ended December 31, 2017 of the references to our firm, in the context in which they appear.

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

March 29, 2018

SUITE 800, 350 7TH STREET, S.W. CALGARY, ALBERTA T2P 3N9TEL (403) 262-2799FAX (403) 262-2790

621 17TH STREET, SUITE 1550 DENVER , COLORADO 80293-1501 TEL (303) 623-9147FAX (303) 623-4258

Exhibit 31.1

CERTIFICATION

I, K. Earl Reynolds, Chief Executive Officer of Chaparral Energy, Inc., certify that:

I have reviewed this annual report on Form 10-K of Chaparral Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 29, 2018

/s/ K. Earl Reynolds

K. Earl Reynolds

Chief Executive Officer

Exhibit 31.2

CERTIFICATION

I, Joseph O. Evans, Chief Financial Officer of Chaparral Energy, Inc., certify that:

I have reviewed this annual report on Form 10-K of Chaparral Energy, Inc.;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 29, 2018

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

Exhibit 32.1

CERTIFICATION OF PERIODIC REPORT

I, K. Earl Reynolds, Chief Executive Officer of Chaparral Energy Inc. (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1)

the Annual Report on Form 10-K of the Company for the period ended December 31, 2017 (the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2)

the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Date: March 29, 2018

/s/ K. Earl Reynolds

K. Earl Reynolds

Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

CERTIFICATION OF PERIODIC REPORT

I, Joseph O. Evans, Chief Financial Officer of Chaparral Energy Inc. (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1)

the Annual Report on Form 10-K of the Company for the year ended December 31, 2017 (the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2)

the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Date: March 29, 2018

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

Cawley, Gillespie & Associates, Inc.

petroleum consultants


13640 BRIARWICK DRIVE, SUITE 100	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 1900
AUSTIN, TEXAS 78729-1707	FORT WORTH, TEXAS 76102-4905	HOUSTON, TEXAS 77002-5017
512-249-7000	817- 336-2461	713-651-9944
www.cgaus.com

February 6, 2018

Exhibit 99.1

Mr. Earl Reynolds
CEO
Chaparral Energy, Inc.
701 Cedar Lake Blvd.
Oklahoma City, Oklahoma 73114

	Re:	Evaluation Summary – SEC Pricing Case
		Chaparral Energy, LLC Interests
		Total Proved Reserves
		As of December 31, 2017

Dear Mr. Reynolds:

At your request, Cawley, Gillespie & Associates, Inc. (“CG&A”) prepared this report on February 6, 2018 for Chaparral Energy, LLC (“Chaparral”) for the purpose of submitting our summary level reserve estimates and economic forecasts attributable to the subject interests which are located in various gas and oil properties in various states. CG&A evaluated 100% of Chaparral’s estimated reserves and 100% of the estimated Present Worth discounted @ 10%. This report was prepared for public disclosure by Chaparral or its affiliates in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. This evaluation, effective December 31, 2017, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (“SEC”). A composite summary of the results of this audit are presented in the table below with respect to proved reserves of the interests of Chaparral:


				Proved
			Proved	Developed	Proved
			Developed	Non-Producing	Developed	Proved	Total
			Producing	(Shut In)	Non-Producing	Undeveloped	Proved
Net Reserves
	Oil	- Mbbl	17,962.4	294.5	43.4	11,302.4	29,602.6
	Gas	- MMcf	118,502.5	3,811.3	1,136.7	46,715.4	170,166.0
	NGL	- Mbbl	11,592.1	249.0	17.1	6,464.3	18,322.4
Net Revenue
	Oil	- M$	882,481.4	14,561.3	2,119.0	557,121.8	1,456,283.4
	Gas	- M$	305,491.6	10,524.4	3,297.8	121,166.0	440,479.9
	NGL	- M$	280,320.5	5,557.1	269.1	149,036.0	435,182.7
	Hedge	- M$	0.0	0.0	0.0	0.0	0.0
Severance Taxes		- M$	99,397.0	2,026.6	407.9	41,560.9	143,392.4
Ad Valorem Taxes		- M$	2,205.3	77.0	12.6	0.0	2,294.9
Operating Expenses		- M$	358,119.6	7,443.6	1,284.6	140,802.1	507,650.0
Workover Expenses		- M$	0.0	0.0	0.0	0.0	0.0
3 ^rd Party COPAS		- M$	0.0	0.0	0.0	0.0	0.0
Other Deductions		- M$	213,977.5	3,510.9	0.0	28,559.3	246,047.5
Investments		- M$	0.0	992.7	644.0	282,477.7	284,114.3
Net Operating Income (BFIT)		- M$	794,594.1	16,592.0	3,336.9	333,923.8	1,148,446.8
	Discounted @ 10%	- M$	422,912.8	8,737.5	1,461.3	77,394.4	510,506.2

Chaparral Energy, LLC Interests

February 6, 2018

Page 2

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

Presentation

This report is divided into five reserve category sections: Total Proved (“TP”), Proved Developed Producing (“PDP”), Proved Developed Non-Producing Shut-In (“PDNP-SI”), Proved Developed Non-Producing (“PDNP”) and Proved Undeveloped (“PUD”). Every reserve category contains a Table I which presents composite reserve estimates and economic forecasts for the particular reserve category. The data presented in the summary tables are explained on page 1 of the Appendix. The methods employed in estimating reserves are described in page 2 of the Appendix. For a more detailed explanation of the report layout, please refer to the Table of Contents following this letter.

Hydrocarbon Pricing

In this evaluation, the base oil and gas prices were $51.34/BBL and $2.98/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices during 2017 and the base gas price is based upon Henry Hub spot prices during 2017. Prices were not escalated.

The base prices were adjusted for differentials on a by area basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $49.194 per barrel of oil, $2.589 per MCF of gas and $23.751 per barrel of NGL. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, lease operating expenses and investments were calculated and prepared by Chaparral and were accepted as furnished. All economic parameters, including lease operating expenses and investments, were held constant (not escalated) throughout the life of these properties.

Possible Effects of Federal and State Legislation

Federal, state and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved reserves for this report. However, the impact of possible changes to legislation or regulations to future operating expenses and investment costs have not been included in the evaluation. These possible changes could have an effect on the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy.

Chaparral Energy, LLC Interests

February 6, 2018

Page 3

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Chaparral’s properties. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined, nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. The lead evaluator preparing this report was W. Todd Brooker, P.E., President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or Chaparral and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

This letter is for the use of Chaparral Energy, LLC. This letter should not be used, circulated, or quoted for any other purpose without the express written consent of Cawley, Gillespie & Associates, Inc. or except as required by law.


Yours very truly,
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F 693

W. Todd Brooker, P.E.
President


/s/ Agustin Presas Jr.
Agustin Presas Jr.
Vice President

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) Production Performance , (2) Material Balance , (3) Volumetric and (4) Analogy . Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production Performance . This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material Balance . This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which make this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric . This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy . This method which employs experience and judgment to estimate reserves is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

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APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

"(22) Proved oil and gas reserves . Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

"(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

"(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

"(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

"(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

"(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

"(6) Developed oil and gas reserves . Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

"(31) Undeveloped oil and gas reserves . Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects

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in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

"(18) Probable reserves . Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

"(17) Possible reserves . Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required , to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

"(26) Reserves . Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

Appendix

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