Chaparral Energy, Inc. - FORM 10-K

Attached files

file	filename
EX-4.4 - EXHIBIT 4.4 - Chaparral Energy, Inc.	a201910kexh44.htm
EX-99.1 - EXHIBIT 99.1 - Chaparral Energy, Inc.	a201910kex991.htm
EX-32.2 - EXHIBIT 32.2 - Chaparral Energy, Inc.	a201910kex322.htm
EX-32.1 - EXHIBIT 32.1 - Chaparral Energy, Inc.	a201910kex321.htm
EX-31.2 - EXHIBIT 31.2 - Chaparral Energy, Inc.	a201910kex312.htm
EX-31.1 - EXHIBIT 31.1 - Chaparral Energy, Inc.	a201910kex311.htm
EX-23.2 - EXHIBIT 23.2 - Chaparral Energy, Inc.	a201910kex232.htm
EX-23.1 - EXHIBIT 23.1 - Chaparral Energy, Inc.	a201910kex231.htm
EX-21.1 - EXHIBIT 21.1 - Chaparral Energy, Inc.	a201910kex211.htm

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, 2019



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

For the transition period from

Commission file number: 001-38602

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)




Delaware		73-1590941
(State or other jurisdiction of 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:



Title of class	Trading Symbol(s)	Name of each exchange on which registered
Class A common stock, par value $0.01 per share	CHAP	The New York Stock Exchange

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

None.

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ☐

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	x	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 28, 2019, 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 $157.8 million, based upon $4.71 per share, the last reported sales price of the shares on the New York Stock Exchange on such date.

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 x No ☐

Number of shares outstanding of each of the registrant’s classes of common stock as of March 6, 2020:




Class	Number of shares
Class A Common Stock, par value $0.01 per share	47,938,374

Documents incorporated by reference:

Certain information called for in Items 10, 11, 12, 13 and 14 of Part III will be included in an amendment to this Annual Report on Form 10-K to be filed no later than April 29, 2020.

CHAPARRAL ENERGY, INC.

Index to Form 10-K



Part I

Items 1. and 2.	Business and Properties	7

Item 1A.	Risk Factors	30

Item 1B.	Unresolved Staff Comments	48

Item 2.	Properties	48

Item 3.	Legal Proceedings	49

Item 4.	Mine Safety Disclosures	50

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	50

Item 6.	Selected Financial Data	52

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	53

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	70

Item 8.	Financial Statements and Supplementary Data	73

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	125

Item 9A.	Controls and Procedures	125

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		132

CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:


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


•	the amount, nature and timing of capital expenditures;


•	drilling, completion and performance of wells;


•	inventory of drillable locations;


•	competition;


•	government regulations;


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


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


•	changes in proved reserves;


•	operating costs and other expenses;


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


•	estimates of proved reserves;


•	exploitation of property acquisitions; and


•	marketing of oil and natural gas.

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described in Part I, Item 1A, Risk Factors, of this report, the risks and uncertainties include or relate to, but are not limited to:


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


•	worldwide supply of and demand for oil and natural gas;


•	volatility and declines in oil and natural gas prices;


•	geopolitical events affecting oil and natural gas prices;


•	recent changes in the composition of the board of directors of the Company (the “Board”)


•	the effects of the departure of our former Chief Executive Officer (“CEO”) and the hiring of a new CEO on our employees, suppliers, regulators and business counterparties;


•	our inability to retain and attract key personnel;


•	risks related to the geographic concentration of our assets;


•	our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;


•	drilling plans (including scheduled and budgeted wells);


•	geologic and reservoir complexity and variability;


•	uncertainties in estimating our oil and gas reserves and the present values of those reserves;


•	the number, timing or results of any wells;


•	changes in wells operated and in reserve estimates;


•	activities on properties we do not operate;


•	availability and cost of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;


•	competition in the oil and natural gas industry;


•	future tax matters;


•	outcome, effects or timing of legal proceedings (including environmental litigation);


•	our ability to make acquisitions and to integrate acquisitions;


•	effectiveness and extent of our risk management activities;


•	weather, including its impact on oil and natural gas demand and weather-related delays on operations;


•	integration of existing and new technologies into operations;


•	current borrowings, capital resources and liquidity;


•	covenant compliance under instruments governing any of our existing or future indebtedness, including our ability to comply with financial covenants under our Credit Agreement;


•	the effects of government regulation and permitting and other legal requirements;


•	legislation and regulatory initiatives;


•	volatility in the price of our common stock;


•	future growth and expansion;


•	future exploration;


•	changes in strategy and business discipline; and


•	the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions may change the schedule of any future production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

GLOSSARY OF CERTAIN DEFINED TERMS

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



Bankruptcy Court	United States Bankruptcy Court for the District of Delaware

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	One barrel of crude oil equivalent, determined 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 one pound of water from 58.5 to 59.5 degrees Fahrenheit.

Chapter 11 Cases	The voluntary petitions filed by Chaparral Energy, Inc. and its subsidiaries on May 9, 2016, seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware commencing cases for relief under chapter 11 of the Bankruptcy Code.

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.

Credit Agreement	Tenth Restated Credit Agreement, as amended, by and among Chaparral Energy, Inc., Royal Bank of Canada as Administrative Agent and the Lenders thereto.

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.

Effective Date	March 21, 2017, the date of the Company’s emergence from bankruptcy.

EOR Areas	Areas where we previously injected, planned to inject and/or recycled CO2 as a means of oil recovery.

Enhanced oil recovery (EOR)	The use of any improved recovery method, including injection of CO₂ or polymer, to remove additional oil after Secondary Recovery.

Exit Credit Facility	Ninth Restated Credit Agreement, dated as of March 21, 2017, by and among us, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent and each of the Lenders named therein, as amended.

Exit Revolver	A first-out revolving facility under the Exit Credit Facility.

Exit Term Loan	A second-out term loan under the Exit Credit Facility.

Exploratory well	A well drilled to find a new field or to find a new reservoir in a field previously found to produce oil or natural gas in another reservoir.

Field	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Horizontal drilling	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.



Indenture	Indenture dated June 29, 2018, among Chaparral Energy, Inc., the Guarantors party thereto, and UMB Bank, N.A., as Trustee, relating to our 8.750% Senior Notes due 2023.

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.

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 sum of fractional working interests owned in gross acres or gross wells.

NYMEX	The New York Mercantile Exchange.

NYSE	The New York Stock 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. Pursuant to the Reorganization Plan, upon emergence from bankruptcy, our Prior Credit Facility was amended and restated in its entirety by the Exit Credit Facility.

Prior Senior Notes	Collectively, our 9.875% senior notes due 2020, 8.25% senior notes due 2021, and 7.625% senior notes due 2022, of which all obligations have been discharged upon consummation of our Reorganization Plan.

Productive well	A well that is currently producing oil or natural gas or is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Proved developed reserves	Reserves that can be expected to be recovered (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.

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, regardless of whether deterministic or probabilistic methods are used for 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. For additional information, see the SEC’s definition in Rule 1-10(a)(22) of Regulation S-X, a link for which is available at the SEC’s website.

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%.

Reorganization Plan	First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors under Chapter 11 of the Bankruptcy Code.

Royalty Interest	An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.

SEC	The Securities and Exchange Commission.

Secondary recovery	The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.

Seismic	Also known as a seismograph, it is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations.

Senior Notes	Our 8.75% senior notes due 2023.

STACK	The STACK is a play in the Anadarko basin of Oklahoma in which we operate and derives its name from the acronym standing for Sooner Trend Anadarko Canadian Kingfisher. It is a horizontal drilling play in an area with multiple productive reservoirs that had previously been drilled with vertical wells. Our STACK areas encompass all or parts of Canadian, Garfield, Kingfisher, Major, Blaine, Dewey, Woodward, Logan and Grady counties in Oklahoma. Our STACK areas’ 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.

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 a 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.

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

As an independent oil and natural gas exploration and production company headquartered in Oklahoma City, we are focused in Oklahoma’s hydrocarbon rich Mid-Continent region. Of our 210,000 net surface acres in the Mid-Continent region, approximately 122,000 net acres are located in the STACK play, primarily in Canadian, Kingfisher and Garfield counties.

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 Devonian-age Woodford Shale formation and the Pennsylvanian-age Oswego formation.

Building on early success achieved from our initial STACK drilling activities, we significantly increased our leasing and drilling activities from 2017 to 2019. Our activities focused on expanding our understanding of the productive extent and hydrocarbon content of the play and holding acreage with production, and during this time we successfully tested productive zones in the play, introduced new completions to improve recoveries, demonstrated repeatability of results, reduced cycle times, and de-risked a sizeable portion of our acreage in the play. Additionally, in 2018, we commenced the evaluation of full section infill development with multi-well patterns to help determine optimum well spacing and to maximize economic recovery of oil and natural gas from each formation.

As of December 31, 2019, our estimated proved oil and natural gas reserves were 96.6 MMBoe with a PV-10 value of approximately $514 million. Our estimated proved reserve life is approximately 10.1 years. These estimated proved reserves included 79.3 MMBoe of reserves in the STACK, representing a 7% increase from the prior year. Our total proved reserves were 67% proved developed, 28% crude oil, 34% natural gas liquids and 38% natural gas. As of December 31, 2019, we had an interest in 2,782 gross producing wells (867 net), 866 gross (684 net) of which we operate. Our daily net production in the fourth quarter of 2019 was approximately 29.7 MMBoe of which 85% was attributable to our STACK assets.

From 2017 through 2019, we increased our STACK production at a compound annual growth rate of approximately 51.1%. During 2019, we spent $228.8 million on drilling and completion activities in our STACK play where we drilled and/or participated in the drilling of 130 (51 net) horizontal wells. While we intend to grow our reserves and production through the development of multi-year inventory of identified drilling locations within the STACK over the long term, we plan to decrease our drilling activity in 2020 in response to recent lower commodity prices. Our activity level in 2020 will reflect a balancing of our goals to reduce cash outspend in 2020 while positioning ourselves to comply with leverage and other financial covenant ratios found in our financing documents. To the extent we reduce drilling activity to preserve cash, the natural decline in production from existing wells, coupled with depressed commodity prices, would result in a commensurate decline in the revenues associated with our leverage covenants. At present, we are operating two horizontal drilling rigs; however, through the employment of short term contracts, we have retained the flexibility to reduce activity, as appropriate, to meet our goals. Our 2020 activities will focus on identifying and implementing cost reduction and cash flow optimization opportunities, prudently developing our acreage, expanding on the known productive extent of the play, monitoring production from optimized completions and continued refinement of our geologic and economic models in the area. We will also monitor the market for producing assets and may opportunistically acquire productive oil and gas wells with associated acreage.

Business Strategy

Our strategy is to leverage our operational and technical expertise in unconventional resource development to grow value by developing and exploiting our inventory of STACK horizontal drilling opportunities.

The key components of our strategy include:

Maintain Production and Reserves. Our December 31, 2019, reserve estimates reflect that our production rate on current proved developed producing properties will decline at annual rates of approximately 29%, 18%, and 14% 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.

Developing our Inventory. We plan on developing our inventory in a disciplined manner. Our goal is to effectively develop our assets in way that efficiently converts them into cash flow, while at the same time increasing long-term value for our stockholders. We utilize an earth model derived from 3-D seismic data to help identify our well locations, target intervals and well density. We design our wells in a way that enhances near-wellbore stimulated reservoir volume and manages well communication risk. We are continuously evaluating and applying lessons learned from one project to the next to enhance our return on the capital we invest in our operations. We continue to test the most efficient spacing and operating strategies in order to minimize depletion, competitive drainage and other communication issues between geologic targets. As we drill our inventory, we learn more about each of our geologic targets.

Reduction of Capital, G&A and Operating Costs. Reductions in capital, LOE and G&A costs have a direct impact on which wells and targets are economic. Since the beginning of 2019, the Company has reduced its corporate workforce and implemented cost reduction initiatives that will result in significant annualized G&A savings. The full impact of these 2019 reductions will be realized in 2020, although we saw initial savings flowing through in the second half of 2019. As for capital and LOE reductions, we have focused on capturing savings from current weakness in the sector, optimized water handling costs, and taken a data-driven approach to improve fixed costs and to reduce workover expenses. In 2020, our focus will remain on finding sustainable cost reductions and capturing savings in order to maximize our financial flexibility.

Competitive Strengths

We believe that the following strengths will help us achieve our business goals:

Strong Operational and Technical Expertise. Since emerging from our Chapter 11 restructuring in early 2017, we have concentrated on enhancing our operational and technical teams with proven industry leaders to strengthen our execution track record as we strive to create long-term stockholder value. As a result, we have assembled a seasoned and knowledgeable technical team with substantial experience and expertise in applying the most advanced technologies in unconventional resource play development, including 3-D seismic interpretation, horizontal drilling, comprehensive multi-stage hydraulic fracture stimulation programs and other technologies. Each of these industry veterans plays an integral role in furthering our geological understanding of our acreage, uncovering additional upside, and improving our operational results.

Established Acreage Position in the STACK. We have assembled a portfolio of STACK properties that offers significant development opportunities with economic rates of return. As of December 31, 2019, we hold over 247,000 gross (122,000 net) acres in the core of the STACK resource play. In addition, 83% of our net acreage position in the STACK is held by production. Based on our drilling and production results to date and offset operator activity in and around our project areas, we believe there are relatively low geologic risks and repeatable drilling opportunities across our core acreage.

High Degree of Operational Control. We are the operator of approximately 74% of our core STACK net acreage. This operating control allows us to better execute on our business strategies, including by designing cost efficient drilling programs to maximize hydrocarbon recovery. Additionally, as the operator of over a majority of our acreage, we retain the ability to increase or decrease out capital expenditure program based on commodity price outlooks.

Multi-year Drilling Inventory. We have identified a multi-year inventory of potential drilling and development locations in our STACK acreage. That acreage has multiple productive zones and we believe that our inventory of drilling locations will allow us to grow our reserves and production at attractive rates of return based on current expectations for commodity prices.

Operational Areas

The following tables present our production and proved reserves by our areas (and counties) of operation. Our operational areas currently include the STACK and Other. Please see Item 8. Financial Statements and Supplementary Data of this report for the results of our operations and financial position.



	Quarter ended	Twelve months ended
Net production (MBoe)	December 31, 2019	December 31, 2019
STACK:
Kingfisher County	875	2,821
Canadian County	1,159	3,703
Garfield County	254	1,192
Other	40	191
Total STACK	2,328	7,907
Other	408	1,686
Total	2,736	9,593



	Proved reserves as of December 31, 2019
	Oil (MBbls)	Natural gas (MMcf)	NGL (MBbls)	Total (MBoe)	Percent of total MBoe		PV-10 value ($MM)
STACK:
Kingfisher County	12,457	58,563	8,968	31,186	32	%	$	193
Canadian County	4,513	80,390	14,673	32,584	34	%	162
Garfield County	2,411	41,094	4,900	14,160	15	%	49
Other	97	4,623	526	1,394	1	%	7
Total STACK	19,478	184,670	29,067	79,324	82	%	$	411
Other	7,771	36,080	3,450	17,234	18	%	103
Total	27,249	220,750	32,517	96,558	100.0	%	$	514

Focused Areas

The STACK has been our predominant focus in recent years. It is a horizontal drilling play in an area with multiple productive reservoirs that had previously been drilled with vertical wells. It encompasses all or parts of Blaine, Canadian, Garfield, Kingfisher and Major counties in Oklahoma. The 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, and Oswego intervals. The Woodford Shale is the primary source of hydrocarbon generation and migration into 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 reservoirs allows us to effectively recover oil and gas from multiple formations using multi-well 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, 2019, we owned approximately 122,000 net surface acres in this play, which includes 194 gross operated producing horizontal wells and ownership interests in an additional 393 gross horizontal producing wells operated by others.

Primarily as a result of our drilling activity, our total annual production from this area increased to 7,907 MBoe in 2019 compared to 5,279 MBoe in 2018 and 3,464 MBoe in 2017. During 2019, we spent $228.8 million on drilling and completion activities in our STACK play where we drilled and/or participated in the drilling of 130 (51 net) horizontal wells.

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

Kingfisher County. The productive reservoirs in this area are the Meramec, Osage and Oswego. Of the various Oklahoma counties encompassed by the STACK play, our historical drilling experience has been predominantly in Kingfisher County, which included operating 88 gross (65 net) horizontal wells as of December 31, 2019. Including wells operated by others, we brought online 58 gross (20 net) wells in this county in 2019.

Canadian County. The productive reservoirs in this area are the Meramec and Woodford. Our STACK operations within this county include operating 59 gross (39 net) horizontal wells as of December 31, 2019. Including wells operated by others, we brought online 47 gross (26 net) wells in this county in 2019.

Garfield County. The productive reservoirs in this area are the Meramec and Osage. Our STACK operations within this county include operating 43 gross (31 net) horizontal wells as of December 31, 2019. Including wells operated by others, we brought online 20 gross (6 net) wells in this county in 2019. While our initial results in Garfield County were quite strong, they have become less consistent. We continue to analyze the data from our wells in Garfield County to better understand its complex geology.

Other Counties. We include our STACK assets dispersed across Major, Blaine, Dewey, Woodward, Logan and Grady counties, Oklahoma, within this category. The majority of our leasehold is held by production.

During 2019, we incurred $11.3 million in acquisitions primarily for leasing and pooling of acreage. This amount includes $0.8 million for seismic data and $1.4 million in non-monetary acreage trades.

Other Areas

With our core focus being in Kingfisher, Canadian and Garfield Counties in the past few years, our footprint outside the STACK is expected to be incrementally and consistently less significant to the Company over time. We deploy the free cash flow from these non-core properties to expand our development activities in the STACK. Our leasehold outside of the STACK is less attractive for drilling in the current price environment as compared to the STACK play, and therefore we have not expended any significant capital to develop this leasehold in recent years. Due to our asset sales and lack of capital spending in these non-core areas in recent years, production has declined from 3,173 MBoe in 2017 to 2,211 MBoe in 2018 and 1,686 MBoe in 2019.

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 funded 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. The JDA provided us with a means to accelerate the delineation of our position within our Garfield County and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and potentially adding reserves. We retained all acreage and reserves outside of the wellbores, with both parties paying their working interest share of lease operating expenses. We have drilled and completed all wells required under the JDA. See “Note 1: Nature of operations and summary of significant accounting policies” in Item 8. Financial Statements and Supplementary Data in this report for a discussion of the primary provisions under our JDA.

Oil and Natural Gas Reserves

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 third party reserve reports, all of which are currently prepared by Cawley, Gillespie & Associates, Inc. (“Cawley”), an independent petroleum engineering firm. To achieve reasonable certainty with respect to our estimated reserves, our engineers relied on an analysis and reporting software system designed specifically for reserves management that has been demonstrated to yield results with consistency and repeatability. Technical and economic data used include, but are not limited to, updated production data, well performance, formation logs, geological maps, reservoir pressure tests, and wellbore mechanical integrity information.

Our Vice President - Resource Development & Operations Management is the technical person primarily accountable for overseeing the preparation of our reserve estimates as of December 31, 2019. He holds a Bachelor of Science degree in petroleum engineering with 20 years of industry experience that includes diverse petroleum engineering roles.

Our Corporate Reserves engineers continually monitor asset performance in collaboration with our other reservoir engineers, making reserve estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Technical reviews are performed throughout the year by our geologic and engineering staff who evaluate pertinent geological and

engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of proved reserve quantities.

We have internal guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserve estimates. Internal controls within the reserve estimation process include:


•	The Corporate Reserves 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 the Accounting department; and


•	comparing and reconciling internally generated reserves estimates to those prepared by third parties.


•	The Corporate Reserves team reports directly to our Chief Executive Officer regarding publicly disclosed reserve estimates.

•

Our reserves estimates 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 Cawley to discuss its processes and findings. In addition, the audit committee of our board of directors (the “Board”) also meets with Cawley to review its findings. Final approval of the reserves is required by our Chief Executive Officer and Chief Financial Officer.

Our Corporate Reserves team works closely with Cawley to ensure the integrity, accuracy and timeliness of annual independent reserve estimates. Our internal reserve data is provided each year to Cawley, who prepares reserve estimates for 100% of our proved reserves using its own engineering assumptions and the economic data that we provide. The person responsible for overseeing the preparation of our reserve estimates at Cawley is a registered professional engineer with more than 22 years of petroleum consulting experience. Copies of the summary reserve reports prepared by Cawley with respect to our estimated reserves as of December 31, 2019, are attached as Exhibits 99.1 to this annual report.

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,
	2019			2018			2017
Estimated proved reserve volumes:
Oil (MBbls)	27,249			32,297			29,604
Natural gas (MMcf)	220,750			220,218			170,166
Natural gas liquids (MBbls)	32,517			25,807			18,322
Oil equivalent (MBoe)	96,558			94,807			76,287
Proved developed reserve percentage	67		%	59		%	67		%
Estimated proved reserve values (in thousands):
Future net revenue	$	1,080,077		$	1,618,480		$	1,095,732
PV-10 value	$	514,203		$	686,366		$	497,873
Standardized measure of discounted future net cash flows	$	514,203		$	686,366		$	497,873
Oil and natural gas prices: (1)
Oil (per Bbl)	$	55.69		$	65.56		$	51.34
Natural gas (per Mcf)	$	2.58		$	3.10		$	2.98
Natural gas liquids (per Bbl)	$	16.21		$	25.56		$	24.17
Estimated reserve life in years (2)	10.1			12.7			11.5

_____________________________________


(1)	Prices were based upon the average first day of the month prices for each month during the respective year and do not reflect differentials.


(2)	Calculated by dividing net proved reserves by net production volumes for the year indicated. The 2017 amount disclosed above excludes production from our EOR Areas as those assets have been sold.

Our net proved oil and natural gas reserves and PV-10 values consisted of the following:



	Net proved reserves as of December 31, 2019
	Oil (MBbls)	Natural gas (MMcf)	Natural gas liquids (MBbls)	Total (MBoe)	PV-10 value (in thousands)
Developed—producing	17,963	149,478	20,548	63,424	$	435,813
Developed—non-producing	484	2,709	401	1,337	9,849
Undeveloped	8,802	68,563	11,568	31,797	68,541
Total proved	27,249	220,750	32,517	96,558	514,203

Proved Undeveloped Reserves

The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2019:



(in MBoe)	Total
Proved undeveloped reserves as of January 1, 2019	39,339
Undeveloped reserves transferred to developed (1)	(2,944	)
Sales of minerals in place	—
Extensions and discoveries	4,622
Revisions and other (2)	(9,220	)
Proved undeveloped reserves as of December 31, 2019	31,797

_______________________________


(1)	Approximately $38.3 million of developmental costs incurred during 2019 related to undeveloped reserves that were transferred to developed.


(2)	The downward revision was primarily due to removal of reserves that are not planned to be developed within five years.

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, 2019, by area. 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)	242	183	91	65	333	248
Other	416	349	117	87	533	436
Total	658	532	208	152	866	684
Non-Operated Wells:
STACK	465	30	288	35	753	65
Other	789	89	374	29	1,163	118
Total	1,254	119	662	64	1,916	183
Total Wells:
STACK	707	213	379	100	1,086	313
Other	1,205	438	491	116	1,696	554
Total	1,912	651	870	216	2,782	867


(1)	Within the STACK, we have 179 gross (132 net) operated horizontal oil wells and 15 gross (7 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.



	2019				2018				2017
	Gross		Net		Gross		Net		Gross		Net
Development wells
Productive	128		49		159		33		127		27
Dry	1		—		1		—		—		—
Exploratory wells
Productive	2		2		9		4		5		1
Dry	—		—		—		—		—		—
Total wells
Productive	130		51		168		37		132		28
Dry	1		—		1		—		—		—
Total	131		51		169		37		132		28
Percent productive	99	%	100	%	100	%	100	%	100	%	100	%

As of December 31, 2019, we had 6 gross (6 net) operated wells drilled and awaiting completion in 2020.

Developed and Undeveloped Acreage

The following table sets forth our gross and net interest in developed and undeveloped acreage as of December 31, 2019, by state. This does not include acreage in which we hold only royalty interests.



	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Oklahoma:
Kingfisher County	57,397	32,396	3,652	603	61,049	32,999
Canadian County	61,080	22,919	1,681	494	62,761	23,413
Garfield County	41,844	30,918	29,409	19,892	71,253	50,810
Other	243,574	94,911	1,567	150	245,141	95,061
Texas	13,363	6,917	120	120	13,483	7,037
Other	2,092	1,282	—	—	2,092	1,282
Total	419,350	189,343	36,429	21,259	455,779	210,602

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 delay rentals are paid and/or production is established with respect to such leasehold acreage prior to such date. As of December 31, 2019, the undeveloped acreage summarized in the table above (gross and net) that is scheduled to so expire as follows:



	Gross Acres Expiring During The Year Ending December 31,
Location	2020	2021	2022	2023	2024	Total
Oklahoma:
Kingfisher County	925	1,088	1,479	160	—	3,652
Canadian County	27	525	1,129	—	—	1,681
Garfield County	15,011	7,021	7,377	—	—	29,409
Other	1,407	—	160	—	—	1,567
Texas	120	—	—	—	—	120



	Net Acres Expiring During The Year Ending December 31,
Location	2020	2021	2022	2023	2024	Total
Oklahoma:
Kingfisher County	407	16	180	—	—	603
Canadian County	21	201	272	—	—	494
Garfield County	9,795	5,109	4,988	—	—	19,892
Other	148	—	2	—	—	150
Texas	120	—	—	—	—	120

Property Acquisition, Development and Exploration Costs

The following tables summarize our costs incurred for oil and natural gas properties:



	Twelve Months Ended December 31, 2019
(in thousands)	STACK		Other		Total
Acquisitions (1)	$	11,312	$	—	$	11,312
Drilling (2)	228,820		—		228,820
Enhancements	7,226		2,590		9,816
Operational capital expenditures incurred	247,358		2,590		$	249,948
Other (3)	—		—		$	19,878
Total capital expenditures incurred	$	247,358	$	2,590	$	269,826

_________________________________


(1)	Includes $0.8 million for seismic data and $1.4 million in non-monetary acreage trades.


(2)	Includes $7.0 million on development of wells operated by others and $12.6 million under the JDA (see discussion in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations).


(3)	For 2019, this amount includes $8.5 million for capitalized general and administrative expenses and $11.8 million for capitalized interest..

For a discussion of the costs incurred in oil and natural gas producing activities for each of the last three years, please see “Note 19: Oil and natural gas activities (unaudited)” in Item 8. Financial Statements and Supplementary Data of this report.

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. As the company emerged from bankruptcy on March 21, 2017, we refer to the post-emergence reorganized company 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.



	Successor								Predecessor
							Period from		Period from
							March 22, 2017		January 1, 2017
	For the Year Ended December 31,						through		through
	2019			2018			December 31, 2017		March 21, 2017
Production:
Oil (MBbls)	3,111			2,684			3,535		1,036
Natural gas (MMcf)	22,095			17,549			11,552		3,046
Natural gas liquids (MBbls)	2,799			1,881			1,143		252
Combined (MBoe)	9,593			7,490			6,603		1,796
Average daily production:
Oil (Bbls)	8,523			7,354			12,404		12,950
Natural gas (Mcf)	60,534			48,078			40,533		38,075
Natural gas liquids (MBbls)	7,668			5,153			4,011		3,150
Combined (Boe)	26,282			20,520			23,171		22,446
Average prices (excluding derivative settlements):
Oil (per Bbl)	$	55.79		$	63.99		$	48.40	$	50.05
Natural gas (per Mcf)	$	1.83		$	2.37		$	2.55	$	3.00
Natural gas liquids (per Bbl)	$	15.04		$	24.24		$	22.69	$	22.00
Transportation and processing (per Boe) (1)	$	(2.40	)	$	(2.17	)	$	—	$	—
Combined (per Boe)	$	24.31		$	32.39		$	34.30	$	37.04
Average costs per Boe:
Lease operating expenses	$	5.17		$	7.24		$	10.92	$	11.10
Transportation and processing (1)	$	—		$	—		$	1.44	$	1.13
Production taxes	$	1.39		$	1.76		$	1.78	$	1.35
Depreciation, depletion, and amortization	$	11.43		$	11.74		$	14.03	$	13.87
General and administrative	$	3.57		$	5.18		$	6.00	$	3.81

_______________________________________________

(1) Transportation and processing costs are reclassified from expense to a revenue deduction beginning in 2018 pursuant to new accounting guidance.

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



	Successor								Predecessor
							Period from		Period from
							March 22, 2017		January 1, 2017
	For the Year Ended December 31,						through		through
	2019			2018			December 31, 2017		March 21, 2017
STACK Play
Production:
Oil (MBbls)	2,538			1,857			1,195		293
Natural gas (MMcf)	17,769			12,245			5,892		1,480
Natural gas liquids (MBbls)	2,407			1,381			631		116
Combined (MBoe)	7,907			5,279			2,808		656
Average daily production:
Oil (Bbls)	6,953			5,088			4,193		3,663
Natural gas (Mcf)	48,682			33,548			20,674		18,500
Natural gas liquids (MBbls)	6,595			3,784			2,214		1,450
Combined (Boe)	21,662			14,463			9,853		8,196
Average prices (excluding derivative settlements):
Oil (per Bbl)	$	56.10		$	64.12		$	49.05	$	49.67
Natural gas (per Mcf)	$	1.83		$	2.38		$	2.58	$	2.99
Natural gas liquids (per Bbl)	$	14.99		$	24.39		$	23.52	$	23.83
Transportation and processing (per Boe) (1)	$	(2.66	)	$	(2.51	)	$	—	$	—
Combined (per Boe)	$	24.03		$	31.95		$	31.57	$	33.16
Average costs per Boe:
Lease operating expenses	$	3.85		$	4.86		$	4.52	$	3.43
Transportation and processing (1)	$	—		$	—		$	2.46	$	2.29
Production taxes	$	1.29		$	1.49		$	1.08	$	0.78

_______________________________________________

(1) Transportation and processing costs are reclassified from expense to a revenue deduction beginning in 2018 pursuant to new accounting guidance.

Non-GAAP Financial Measures and Reconciliations

PV-10 value is a non-GAAP measure that differs from the standardized measure of discounted future net cash flows in that PV-10 value is a pre-tax number, while the standardized measure of discounted future net cash flows is an after-tax number. We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

The increase in PV-10 and standardized measure of discounted future net cash flows from 2017 to 2018 is primarily due to extension of and discoveries from our drilling activity and an increase in the SEC commodity price utilized to estimate reserves. The decrease in PV-10 and standardized measure of discounted future net cash flows from 2018 to 2019 is primarily due to a decrease in the SEC commodity price utilized to estimate reserves, partially offset by increases due to extension of and discoveries from our drilling activity.

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)	2019		2018		2017
Standardized measure of discounted future net cash flows	$	514,203	$	686,366	$	497,873
Present value of future income tax discounted at 10% (1)	—		—		—
PV-10 value	$	514,203	$	686,366	$	497,873

________________________________________

(1) As a result of the magnitude of its loss carryforwards and its tax basis in oil and gas properties, the Company does not expect to incur income taxes on its current estimate of net revenues from future production.

Management uses adjusted EBITDA (as defined below) as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is calculated in a manner generally consistent with the EBITDAX calculation that is used in the covenant ratio required under our Credit Agreement, 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, 2019.

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) impairment charges, (10) other significant, unusual non-cash charges and (11) certain expenses related to our restructuring, cost reduction initiatives, reorganization, severance and fresh start accounting activities, some or all of 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
	For the Year Ended December 31,						through			through
(in thousands)	2019			2018			December 31, 2017			March 21, 2017
Net (loss) income	$	(468,948	)	$	33,442		$	(118,902	)	$	1,041,959
Interest expense	22,666			11,383			14,147			5,862
Income tax (benefit) expense	—			(77		)	(349		)	37
Depreciation, depletion, and amortization	109,633			87,888			92,599			24,915
Non-cash change in fair value of derivative instruments	40,765			(37,807		)	46,478			(46,721		)
Impact of derivative repricing	—			(5,649		)	—			—
Loss (gain) on settlement of liabilities subject to compromise	—			48			—			(372,093		)
Fresh start accounting adjustments	—			—			—			(641,684		)
Interest income	(6		)	(12		)	(21		)	(133		)
Stock-based compensation expense	1,583			10,873			9,833			155
Loss (gain) on sale of assets	6			2,582			25,996			(206		)
Loss on extinguishment of debt	1,624			—			635			—
Write-off of debt issuance costs, discount and premium	—			—			—			1,687
Loss on impairment of other assets	7,188			—			179			—
Loss on impairment of oil and gas assets	430,695			20,065			42,146
Restructuring, reorganization and other	9,287			2,344			7,313			24,297
Adjusted EBITDA	$	154,493		$	125,080		$	120,054		$	38,075

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.

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, which would include, if necessary, obtaining financing on acceptable terms.

There is also competition between oil and natural gas producers and producers of alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by federal, state and local governments; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations.

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, including the effect of regional or global health

pandemics (such as, for example, the coronavirus).

Members of the OPEC establish prices and production quotas from time to time with the intent of managing the global supply and maintaining, lowering or increasing certain price levels. We are unable to predict what effect, if any, such actions will have on both the price and volume of crude oil sales from our wells.

In several initiatives, FERC has required pipeline transportation companies to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated it will ultimately expand natural gas markets and improve their reliability.

Environmental Matters and Regulation

We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities.

General

Our operations, like the operations of other companies in our industry, are subject to stringent federal, tribal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:


•	require the acquisition of various permits before drilling commences;


•	require the installation of costly emission monitoring and/or pollution control equipment;


•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;


•	require the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with our operations;


•	limit or prohibit drilling activities on lands lying within wilderness, wetlands, certain animal habitats and other protected areas;


•	restrict the construction and placement of wells and related facilities;


•	require remedial measures to address pollution from current or former operations, such as cleanup of releases, pit closure and plugging of abandoned wells;


•	impose substantial liabilities for pollution resulting from our operations;


•	with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement; and


•	impose safety and health standards for worker protection.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible or economically desirable. The regulatory burden on the oil and natural gas industry increases the cost of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and

regulations, and any changes that result in more stringent and costly permitting, pollution control, or waste handling, disposal and clean-up requirements for the oil and natural gas industry could significantly increase our operating costs.

We routinely monitor our properties and operations in an effort to ensure that our properties and operations are, and remain, in 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, 2019, 2018 and 2017, we did not incur any material expenditures for the installation of remediation or pollution control equipment at any of our facilities or for the conduct of remedial or corrective actions. As of the date of this report, we are not aware of any other environmental issues or claims that will require material capital expenditures during 2020 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 and local governments have pursued additional regulation of our operations and other states and local governments may do so as well.

Environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry include the following:

Hazardous Substances and Wastes

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and non-hazardous wastes. Under the authorization and oversight of the federal Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. EPA also retains enforcement authority in any state-administered RCRA programs. Drilling fluids, produced waters, and many other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions. However, there is no guarantee that Congress, the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation under RCRA. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste, if they have hazardous characteristics.

We believe that we are currently in 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 January 2020, EPA and the U.S. Army Corps of Engineers jointly issued a final rule defining the “Waters of the United States,” which are protected under the Clean Water Act. The new rule narrows the definition of Waters of the United States and therefore limits the scope of waters subject to the jurisdiction of the Clean Water Act, excluding, for example, streams that do not flow year-round and wetlands without a direct surface connection to other jurisdictional waters.

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 continues to release well completion seismicity guidance, which most recently directs operators to adopt a seismicity response plan and take certain prescriptive actions, including mitigation, following anomalous seismic activity within 3.1 miles of hydraulic fracturing operations. In addition, since 2015, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has issued a number of directives restricting the future volume of wastewater disposed of via subsurface injection and directing the shut in of certain injection wells, including in areas where we operate.

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the Clean Water Act if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. The Supreme Court heard oral arguments on the case in November 2019, which remains pending. In January 2020, EPA and the U.S. Army Corps of Engineers jointly issued a final rule defining the “Waters of the United States” to specifically exclude groundwater. However, should Clean Water Act permitting be required for saltwater injection wells, the costs of permitting and compliance for our operations could increase.

Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA, potentially the Clean Water Act, and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Congress has previously considered legislation to amend the federal SDWA to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of bills previously proposed before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Such proposed legislation, which has been introduced in various forms to each session of Congress since 2009, would require the reporting and public disclosure of chemicals used in the fracturing process, which is already required by some state agencies governing our operations, including the Oklahoma Corporation Commission and the Railroad Commission of Texas. Such disclosure requirements could make it easier for third parties opposing the use of hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could repeal the exemptions for hydraulic fracturing from the SDWA.

These federal legislative efforts slowed while EPA studied the issue of hydraulic fracturing. In 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water, as well as review the application of other environmental statutes to hydraulic fracturing activities, including RCRA and the Clean Water Act. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing fluid and providing a comprehensive list of chemicals identified in fracturing fluid and flowback/produced water. EPA completed the study of the potential impacts of hydraulic fracturing activities on water resources and published its final assessment in December 2016. In its assessment, the EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances. The results of the study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. A number of states and communities are currently considering legislation to ban or restrict hydraulic fracturing.

On March 20, 2015, the United States Bureau of Land Management (“BLM”) released its new regulations governing hydraulic fracturing operations on federal and Indian lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule in June 2016, but the U.S. Court of Appeals for the Tenth Circuit (the “Tenth Circuit”) later lifted the lower court’s stay on the basis that the BLM had proposed to rescind the rule in June 2017. In December 2017, the BLM repealed the 2015 regulations, and environmental organizations and the

State of California are suing the BLM and the Secretary of the U.S. Department of the Interior over the repeal. The regulations, if reinstated, may result in additional levels of regulation or complexity with respect to existing regulations that could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

The Clean Air Act

The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements, such as emission controls. In addition, EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. On August 16, 2012, EPA promulgated new CAA regulations addressing criteria pollutants, “Oil and Natural Gas Sector: New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”).” These new rules broadened the scope of EPA’s NSPS and NESHAP to include standards governing emissions from most operations associated with oil and natural gas production facilities and natural gas processing, transmission and storage facilities with a compliance deadline of January 1, 2015. EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In December 2014, EPA released final updates and clarifications to the Oil and Natural Gas Sector NSPS that, among other things, distinguished between multiple flowback stages during completion of hydraulically fractured wells and clarified that storage tanks removed from service are not affected by any requirements. On May 12, 2016, EPA issued additional rules, known as “NSPS Subpart OOOOa,” for the oil and gas industry to reduce emissions of methane, volatile organic compounds (“VOCs”) and other compounds. These rules apply to certain sources of air emissions that were constructed, reconstructed, or modified after September 18, 2015. Among other things, the new rules impose reduced emission (“green”) completion requirements on new hydraulically fractured or re-fractured oil wells (in addition to gas wells, for which green completions were already required under a prior NSPS rule) and leak detection and repair requirements at well sites. NSPS Subpart OOOOa and EPA’s subsequent actions to reconsider and propose stays of the rules have been heavily litigated. In September 2019, EPA proposed amendments to the new source performance standards for the oil and gas industry that would remove all sources in the transmission and storage segments of the industry from regulation under the NSPS and would rescind the methane requirements in the 2016 NSPS that apply to sources in the production and processing segments of the industry. Accordingly, the ultimate scope of these regulations is uncertain, and any future changes to these regulations could require us to incur additional costs and to reduce emissions associated with our operations

Endangered Species

The federal Endangered Species Act (“ESA”) and analogous state laws regulate a variety of activities that adversely affect species listed as threatened or endangered under the ESA or their habitats. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. For instance, the American Burying Beetle was listed as an endangered species by the U.S. Fish and Wildlife Service (“FWS”) in 1989. The FWS announced in November 2016 that it is considering listing the Lesser Prairie Chicken as threatened under the ESA. The FWS completed an assessment of the biological status of the species in August 2017 and entered into a stipulated settlement agreement with environmental groups in September 2019 that requires the FWS to make a final listing decision no later than May 26, 2021. 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

In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement, which became effective in November 2016, calls for participating nations to undertake efforts to limit the average global temperature and to reduce emissions of greenhouse gases. In November 2019, the United States submitted formal notification to the United Nations of its withdrawal from the Paris Agreement. The withdrawal will take effect on November 4, 2020. From time to time, legislation has been proposed in Congress directed at reducing greenhouse gas (“GHG”) emissions, and it would be reasonable to expect similar proposals in the future. Regulation of GHGs has support in various regions of the country, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future federal or state restrictions on such emissions could impact our future operations. In 2010, the EPA enacted final rules on mandatory reporting of GHGs. The EPA has also subsequently issued amendments

to the rules containing technical and clarifying changes to certain GHG reporting requirements. Under the GHG reporting rules, certain onshore oil and natural gas production, gathering and boosting, processing, transmission, storage and distribution facilities are required to report their GHG emissions on an annual basis. In June 2016, the EPA published final regulations (NSPS Subpart OOOOa) setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities. In September 2019, the EPA issued proposed amendments to the 2016 rule that would rescind methane emissions standards for the oil and gas industry. In November 2016, the BLM published a final version of its venting and flaring rule, which imposes stricter reporting obligations and limits venting and flaring of natural gas on public and Indian lands. Some provisions of the venting and flaring rule went into effect on January 17, 2017; implementation of other aspects of the venting and flaring rule was postponed until January 17, 2019. In September 2018, however, the BLM published a final rule that revises the 2016 rule. Not unexpectedly, this revised rule was immediately challenged and litigation is ongoing. Any rules regarding the reduction of GHGs that are applicable to our operations could require us to incur additional costs and to reduce emissions associated with our operations. In response to these regulations, or other future federal, state or regional legislation, our operating costs could increase due to requirements to (1) obtain permits; (2) operate and maintain equipment and facilities (e.g., through the reduction or elimination of venting and flaring of methane); (3) install new emission controls; (4) acquire allowances authorizing GHG emissions; (5) pay taxes related to our GHG emissions; and (6) administer and manage GHG emission programs. Although our operations are not adversely impacted by current state and local climate change initiatives, at this time it is not possible to accurately estimate how potential future laws or regulations limiting or otherwise addressing GHG emissions would impact our business.

OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the CAA, and similar state statutes require that we organize and/or disclose information about hazardous materials used, produced or otherwise managed in our operations. These laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. It is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at the federal, tribal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds, and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:


•	the location of wells;


•	the method of drilling and casing wells;


•	the timing of construction or drilling activities;


•	the rates of production or “allowables”;


•	the use of surface or subsurface waters;


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


•	the plugging and abandoning of wells;


•	the transportation of production; and


•	notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our

interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands and some Indian lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major federal actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.

Natural Gas Sales

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. Sales of oil are not subject

to FERC jurisdiction.

Pipeline Transportation

FERC regulates interstate natural gas pipeline transportation rates and terms and conditions of service under the NGA. We rely on pipelines to transport our natural gas and oil to markets. FERC regulation under the NGA and ICA thus affects the marketing of natural gas and oil that we produce, as well as the revenues we receive for sales of our production. FERC requires interstate pipeline companies to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. We currently have access to, or have contracted for, sufficient pipeline capacity necessary to market our production. However, there can be no assurance that we will have access to sufficient capacity indefinitely in the future.

Under the NGA, the rates for service on interstate pipelines must be just and reasonable and not unduly discriminatory. Generally, the maximum filed recourse (non-contract) rates for interstate natural gas 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. The NGA exempts natural gas gathering service, which occurs upstream of jurisdictional transmission services, from FERC jurisdiction. Natural gas gathering service is instead regulated by the states. The distinction between FERC-regulated transmission services and non-jurisdictional natural 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 the 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 and Hazardous Liquids Pipeline Safety

The Department of Transportation (“DOT”), and specifically the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), regulate transportation of natural gas and hazardous liquids, including oil, 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 10 mile, six (6) inch pipeline in Hockley County, TX is subject to this regulation. We believe we are in compliance with all applicable regulations imposed by the DOT and PHMSA regarding our natural gas and hazardous liquids pipelines. However, significant expenses could be incurred in the future if additional safety measures are required, or if safety standards are raised and exceed the degree of our current

natural gas pipeline operations. The DOT may also assess fines and penalties for violations of these and other requirements imposed by its regulations.

Natural Gas Gathering Regulations

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements and complaint-based rate regulation. The regulations generally require gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. Such regulations can have the effect of imposing restrictions on a pipeline’s ability to decide with whom it contracts to gather natural gas. In addition, natural gas gathering is included in EPA’s greenhouse gas monitoring and reporting rule, is subject to air permitting requirements where applicable, and may receive greater regulatory scrutiny in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.

Other State Regulation

The various states regulate the drilling for, and the production, gathering, transportation, 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 natural gas and oil industries are 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, 2019, we had 121 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.

Facilities

Our corporate headquarters are located in Oklahoma City, Oklahoma, and we lease small field offices on short term bases. We believe that our facilities are adequate for our current operations.

Recent Developments

Amended and Restated Support Agreement with SVP; Board and Chief Executive Officer Changes

On June 6, 2018, the Company entered into a Support Agreement (the “Original SVP Support Agreement”) with Strategic Value Partners, LLC (“SVP”). At the time the Original SVP Support Agreement was signed, SVP and its affiliated entities beneficially owned approximately 16.8% of the issued and outstanding shares of common stock of the Company. David Geenberg, co-head of SVP’s North American investment team, was originally designated as the SVP designee on the Board. Effective as of March 11, 2019, Mr. Geenberg resigned from the Board, and SVP appointed Marc Rowland, who was not an officer or employee of SVP, to serve as the SVP designee on the Board. Through a series of open market purchases of common stock from March 18, 2019 until July 17, 2019, SVP and its affiliated entities increased their ownership in the Company to approximately 30% of the issued and outstanding shares of common stock.

As a result of this increase in SVP’s ownership position in the Company, on December 20, 2019, the Company and SVP entered into an Amended and Restated Support Agreement (the “Amended SVP Agreement”), which, among other things, increased the number of SVP designees on the Board from one to two. Furthermore, the Company agreed that Mr. Rowland would remain on the Board, even though he no longer serves an SVP designee. Additionally, each of the following actions was taken as a condition to SVP’s agreeing to the terms and obligations set forth in the Amended SVP Agreement:

•the authorized number of directors on the Board was increased from seven to eight;

•K. Earl Reynolds, the Company’s Chief Executive Officer, President and director, resigned from such positions;

•Matthew D. Cabell resigned as a director, as well as Chairman of the Compensation Committee of the Board (the “Compensation Committee”) and a member of the Nominating and Governance Committee of the Board (the “Nominating and Governance Committee”);

•Mr. Rowland ceased to be an SVP designee and became instead a mutually-designated independent director (the “Mutual Independent Director”);

•Mr. Rowland was appointed Chairman of the Board. (Mr. Rowland had been appointed Chairman of the Board on an interim basis in July 2019, but, as a result of the Board’s action at the Effective Time, Mr. Rowland no longer serves on an interim basis);

•SVP designated Michael Kuharski and Mark “Mac” McFarland as SVP Designees, and those two SVP designees were appointed to the Board to fill the vacancies created by the resignations of Mr. Reynolds and Mr. Cabell;

•Mr. McFarland was appointed as a member of the Compensation Committee;

•Mr. Kuharski was appointed as a member of the Nominating and Governance Committee, filling the role that had been previously filled by Mr. Rowland; and

•Charles Duginski was appointed Chief Executive Officer and President of the Company and was also appointed as a director to fill the new directorship created by the increase in the number of authorized directors on the Board.

Conditions to SVP’s Right to Designate SVP Designees. If SVP and its affiliated entities cease to beneficially own at least 8% of the Company’s then outstanding shares of common stock (or, if less, 3,719,850 shares) (the “One Director Condition”), then SVP will no longer be entitled to designate any directors. In addition, if SVP or any of its affiliates materially breaches the Amended SVP Agreement and fails to cure such breach, SVP will no longer be entitled to designate any directors. In that circumstance, then the resignations described below for all SVP designees will become effective at that time, if accepted by the Board.

If SVP and its affiliated entities (i) cease to beneficially own at least 16% of the Company’s then outstanding shares of common stock (or, if less, 7,439,700 shares), but (ii) still satisfy the One Director Condition, then SVP will be entitled to designate one director, but not two directors. In that circumstance, then the resignation described below for one SVP designee (but not both) will become effective at that time, if accepted by the Board.

In accordance with the Amended SVP Agreement, Mr. Kuharski and Mr. McFarland each provided the Company with an irrevocable resignation letter that will become effective, subject to the Board’s acceptance, upon the occurrence of the events described above relating to SVP’s minimum ownership thresholds or a material breach of the Amended SVP Agreement and failure to cure such breach.

2020 Annual Meeting. Under the Amended SVP Agreement, the Company has agreed to hold the Company’s 2020 annual meeting of stockholders (the “2020 Annual Meeting”) no later than May 29, 2019.

Under the Amended SVP Agreement, if, prior to the 2020 Annual Meeting, any independent director who is not affiliated or associated with SVP and who has not ever been an SVP designee on the Board (each, a “Specified Independent Director”) resigns as a director or informs the Board that he or she will not stand for re-election at the 2020 Annual Meeting, then that director’s replacement must also meet the requirements to be a Specified Independent Director. That replacement will be recommended by the Nominating and Governance Committee for approval by the Board, and the only candidates that the Board may consider will be those candidates recommended by the Nominating and Governance Committee. The Amended SVP Agreement requires that a majority of the Nominating and Governance Committee and a majority of the Compensation Committee consist of Specified Independent Directors.

If, prior to the 2020 Annual Meeting, the Mutual Independent Director resigns as a director or informs the Board that he or she will not stand for re-election at the 2020 Annual Meeting, then that director’s replacement must meet the independence standards of the NYSE and the SEC (but not the Specified Independent Director requirements) and must be consented to by the SVP designees.

Subject to the procedures described above, the Amended SVP Agreement provides that the Specified Independent Directors and the Mutual Independent Director (including any replacements appointed as described above), will be nominated to stand for election at the 2020 Annual Meeting.

The Amended SVP Agreement provides that if (i) the Chairman of the Board resigns from that position or as a director and (ii) SVP and its affiliated entities satisfy the One Director Condition, then if the replacement Chairman of the Board must be appointed by a majority of the total number of authorized directors (regardless of how many vacancies then exist) (the “Whole Board”). Furthermore, if SVP and its affiliated entities satisfy the One Director Condition, then a vote of a majority of the Whole Board is required to remove the Chief Executive Officer or to appoint a new Chief Executive Officer.

Standstill and Voting Restrictions under the Amended SVP Agreement. Pursuant to the Amended SVP Agreement, SVP agreed, at least until end of the standstill period, not to acquire beneficial ownership in excess of 31% of the Company’s issued and outstanding shares of common stock. The Amended SVP Agreement also includes, among other provisions, certain additional standstill and voting commitments by SVP, including a voting commitment that SVP will vote in favor of (i) any director nominees recommended by the Board to the stockholders for election and (ii) other routine matters submitted by the Board to the stockholders for a vote. The standstill period generally expires upon the conclusion of the Company’s 2020 annual meeting (or, if earlier, 120 days after that each SVP Designee ceases to serve on the Board). However, SVP has agreed that it will not participate in a proxy contest or propose an alternative slate of directors at any time prior to the 90th day after the conclusion of the Company’s 2020 annual meeting. The Amended SVP Agreement also included a mutual release of certain claims by SVP and the Company.

Amended and Restated Support Agreement with Contrarian

On August 8, 2018, the Company entered into a Support Agreement (the “Original Contrarian Support Agreement”) with Contrarian Capital Management, L.L.C. (“Contrarian”), which permitted Contrarian to designate one individual to serve on the Board (the “Contrarian Designee”). At the time the Original Contrarian Support Agreement was signed, Contrarian and its affiliated entities beneficially owned a total of approximately 8.32% of the issued and outstanding shares of the Company’s common stock. Graham Morris was originally designated as the Contrarian designee on the Board. Effective as of March 11, 2019, Mr. Morris resigned from the Board, and Contrarian never subsequently named a replacement Contrarian designee on the Board.

On December 20, 2019, the Company entered into an Amended and Restated Support Agreement with Contrarian (the “Amended Contrarian Agreement”). At the Effective Time, Contrarian informed the Company that Contrarian and its affiliated entities beneficially owned a total of approximately 8.84% of the issued and outstanding shares of the Company’s common stock.

Termination of Contrarian’s Right to Designate Directors. Pursuant to the Amended Contrarian Agreement, Contrarian is no longer entitled to designate anyone to serve on the Board.

Standstill and Voting Restrictions under the Amended Contrarian Agreement. Pursuant to the Amended Contrarian Agreement, Contrarian has agreed, at least until the conclusion of the 2020 Annual Meeting, not to acquire beneficial ownership in excess of 15% of the Company’s issued and outstanding shares of common stock. The Amended Contrarian Agreement also includes,

among other provisions, certain additional standstill and voting commitments by Contrarian, including a voting commitment that Contrarian will vote in favor of (i) any director nominees recommended by the Board to the stockholders for election and (ii) other routine matters submitted by the Board to the stockholders for a vote. The standstill period generally expires upon the conclusion of the 2020 Annual Meeting. However, Contrarian has agreed that it will not participate in a proxy contest or propose an alternative slate of directors at any time prior to the 90th day after the conclusion of the 2020 Annual Meeting. The Amended Contrarian Agreement also included a mutual release of certain claims by Contrarian and the Company.

Second Amended and Restated Bylaws

In connection with the Amended SVP Agreement and the Amended Contrarian Agreement, on December 20, 2019, the Board amended and restated the Company’s Amended and Restated Bylaws (the “Existing Bylaws”) to create a position of Designated Independent Director and appointed Kenneth W. Moore, an existing director, to serve in that role. The amendment and restatement also modified the process for calling special meetings of stockholders. The Existing Bylaws provided that a special meeting of stockholders could be called by the Board (by a vote of a majority of the directors at a meeting at which a quorum was present), the Chairman of the Board or the holders of a majority of the total voting power of all the shares of the Company entitled to vote generally in the election of directors. Under the Second Amended and Restated Bylaws, a special meeting of stockholders can be called by the Chairman of the Board, the Board (by a vote of a majority of the whole Board, or half of the whole Board if the whole Board is an even number) or the holders of a majority of the total voting power of all the shares of the Company entitled to vote generally in the election of directors.

Available Information

Our website is available at www.chaparralenergy.com. On our website, you can access, free of charge, electronic copies of our governance documents, including our Board’s Corporate Governance Guidelines and the charters of the committees of our Board, along with all of the documents that we electronically file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports, as soon as reasonably practicable after they are filed or furnished with the SEC. Information contained on, accessible through, or connected to our website is not incorporated by reference into this Annual Report and should not be considered part of this report or any other filing we make with the SEC.

We file or furnish annual, quarterly and current reports and other documents with the SEC. Our reports filed with the SEC are made available to the public to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Filings made with the SEC electronically are also publicly available through the SEC’s website at www.sec.gov.

ITEM 1A. RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.

Risks Related to the Oil and Gas Industry and Our Business

Our development, acquisition and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves.

Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of securities and borrowings under our bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including:


•	our proved reserves;


•	the volume of oil and natural gas we are able to produce from existing wells;


•	the prices at which oil and natural gas are sold;


•	our ability to acquire, locate and produce economically new reserves; and


•	our ability to borrow under our credit facility.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, may precipitate an economic slowdown. Concerns about global economic growth may have an adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

A decline in oil and gas prices may adversely affect our financial condition, financial results, liquidity, cash flows, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the cash flow we will have available for capital expenditures as well as our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to, the following:


•	the level of consumer demand for oil and natural gas;


•	the domestic and foreign supply of oil, NGLs and natural gas;


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


•	the price and level of foreign imports and exports of oil, NGLs and natural gas;


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


•	domestic and foreign governmental regulations and taxes;


•	the supply of other inputs necessary to our production;


•	the price and availability of alternative fuel sources;


•	technological advances affecting energy consumption and supply;


•	weather conditions, seasonal trends and natural disasters and other extraordinary events;


•	financial and commercial market uncertainty;


•	energy conservation and environmental measures;


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


•	worldwide economic conditions; and


•	global or national health concerns, including the outbreak of pandemic or contagious disease, such as the coronavirus.

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. During the past five years, the posted price for West Texas Intermediate light sweet crude oil, which we refer to as WTI, has ranged from a low of $26.19 per Bbl in February 2016 to a high of $77.41 per Bbl in June 2018. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $6.24 per MMBtu in January 2018. During 2019, WTI prices ranged from $46.31 to $66.24 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 per MMBtu. Up to the time of this filing, in March 2020, spot prices for WTI ranged from a high of

$48.66 to a low of $27.34 per Bbl. If the prices of oil and natural gas remain at current levels or decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.

Extended periods of lower oil and natural gas prices will reduce our revenue but also will reduce the amount of oil and natural gas we can produce economically, and as a result, would have a material adverse effect on our financial condition, results of operations, and reserves. During periods of low commodity prices we may shut in or curtail production from additional wells and defer drilling new wells, challenging our ability to produce at commercially paying quantities required to hold our leases. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

A decline in prices from current levels may lead to additional write-downs of the carrying values of our oil and natural gas properties in the future which could negatively impact results of operations.

We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the units-of-production method. However, these capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of estimated future net revenues attributable to proved oil and natural gas reserves discounted at 10% net of tax considerations, plus the market value of unproved properties not being amortized. The full cost ceiling is evaluated at the end of each quarter using the SEC prices for oil and natural gas in effect at that date. A write-down of oil and natural gas properties does not impact cash flow from operating activities, but does reduce net income. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date. We recorded ceiling test write-downs of $431 million, $20 million and $42 million in 2019, 2018 and 2017, respectively. The volatility of oil and natural gas prices 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.

On December 20, 2019, two directors resigned from our Board and three new directors were appointed, and we had a change in our CEO position. The transition in our new board composition and CEO position will be critical to our success.

In connection with the Amended SVP Agreement, on December 20, 2019, the authorized number of directors on the Board was increased from seven to eight, K. Earl Reynolds and Matthew D. Cabell resigned as directors, and Charles Duginski, Michael Kuharski and Mark “Mac” McFarland were appointed as directors. Additionally, Mr. Reynolds resigned as the Company’s Chief Executive Officer and President and Mr. Duginski was appointed to that role. The ability of these new directors and this new CEO to quickly expand their knowledge of our business plans, operations and strategies and our technologies will be critical to their ability to make informed decisions about our strategy and operations. If such persons are not sufficiently informed to make such decisions, our ability to compete effectively and profitably could be adversely affected. Further, if our Board and new CEO formulate different or changed views, the future strategy and plans of the Company may differ materially from those of the past.

The ability to attract and retain key personnel is critical to the success of our business. Any difficulty we experience replacing or adding personnel could adversely affect our business.

The success of our business depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

Our producing properties are predominantly located in Oklahoma where our development opportunities, consisting 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 a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

At December 31, 2019, 82% of our proved reserves and 82% of our total equivalent production for 2019 were attributable our properties located in the STACK. As a result of this concentration, we may be disproportionately exposed to the risk and 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 or other natural disasters, water shortages or other conditions or interruption of the processing or transportation of oil, natural gas or NGLs in the region. These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more diversified.

In addition to the geographic concentration of our producing properties described above, as of December 31, 2019, 70% of all of our proved reserves were attributable to the Meramec and Osage formations in the STACK. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut in all of our wells within a field.

A significant portion of total proved reserves as of December 31, 2019 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2019, 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 $259.3 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.

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:


•	unexpected drilling conditions;


•	title problems;


•	surface access restrictions;


•	pressure or lost circulation in formations;


•	fires, blowouts and explosions;


•	equipment failures or accidents;


•	decline in commodity prices;


•	limited availability of financing on acceptable terms;


•	political events, public protests, civil disturbances, regional or global health pandemics, terrorist acts or cyber-attacks;


•	adverse weather conditions and natural disasters;


•	naturally occurring or induced seismic activity;


•	compliance with environmental and other governmental requirements; and


•	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.

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, which in turn could have a negative effect on the value of our assets. 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. In addition, from time to time in the future, we will adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development, changes in oil and natural gas prices and other factors, many of which are beyond our control.

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, 2019 reserve report used SEC pricing of $2.58 per Mcf for natural gas and $55.69 per Bbl for oil.

The present value of future net cash flows from our proved reserves calculated in accordance with SEC guidelines are not the same as the current market value of our estimated reserves.

We base the estimated discounted future net cash flows from our proved reserves on 12-month average index prices and costs, as is required by SEC rules and regulations. Actual future net cash flows from our oil and natural gas properties will be affected by actual prices we receive for oil, natural gas and NGLs, as well as other factors such as:

•the accuracy of our reserve estimates;

•the actual cost of development and production expenditures;

•the amount and timing of actual production;

•supply of and demand for oil and natural gas; and

•changes in governmental regulation or taxation.

The timing of both our production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, we use a 10% discount factor when calculating discounted future net cash flows, which may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

The predictability of our operating results and our future development plans may be affected by the results of multi-well pad drilling.

We drill multi-well spacing test patterns in the STACK play. These projects, which are capital intensive, involve horizontal multi-well pad drilling, tighter drill spacing and completions techniques that evolve over time as lessons learned are captured and applied. The use of this technique may increase the risk of unintentional communication with other adjacent wells and the potential to reduce total recoverable reserves from the reservoir. Problems affecting a single well could adversely affect production from all of the wells on the pad or in the entire project. Furthermore, additional time is required to drill and complete multiple wells before any such wells begin producing. As a result, multi-well pad drilling and project development can cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results due to timing. Any of these factors could reduce our revenues and could result in a material adverse effect on our financial condition or results of operations.

Further, we may, after consolidating lessons learned regarding the variability and complexity of relevant geology as well as spacing within a reservoir, elect to sacrifice a portion of our drilling locations to both mitigate near term operational risk and address financial goals. For example, we may not co-develop certain locations within a drilling unit at the same time other locations are drilled because those we are forgoing do not meet our return on investment criteria in today’s pricing environment. Locations not simultaneously developed within the same drilling unit may not be economic to drill in the future absent significant improvement in commodity prices. In this regard, it is important to note that oil and NGL prices have a direct impact on which wells we drill and which locations we target at any given time.

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 efficiently develop and exploit our current estimated reserves and find 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 proved undeveloped reserves will require significant capital expenditures and successful drilling operations. Our December 31, 2019, reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 29%, 18%, and 14% 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.

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

We do not operate all of the properties in which we have an interest. For example, as of December 31, 2019, properties representing approximately 26% of our proved developed reserves are operated by third parties. 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:

•timing and amount of capital expenditures;

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

•financial resources;

•inclusion of other participants in drilling wells; and

•use of technology.

Further, it is possible that an operator of a nearby property may perform stimulation operations that negatively affect properties in which we have an interest. 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.

Shortages of oil field equipment and services 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. During future periods where there may be increased demand for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel, 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.

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.

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 we face intense competition from both major and other independent oil and natural gas companies:

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

•seeking to acquire similar equipment and expertise that we deem necessary to operate and develop our properties.

Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment.

We can also be affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel that 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.

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.

Chaparral Energy, Inc. - FORM 10-K - March 11, 2020

Attached files