Annual Report (10-k)

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

OR

 

☐	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)

[phone]

(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.

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CHAPARRAL ENERGY, INC.

Index to Form 10-K

 

Part I
Items 1. and 2.	Business and Properties	7
Item 1A.	Risk Factors	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

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CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

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

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

•	the amount, nature and timing of capital expenditures;

•	drilling, completion and performance of wells;

•	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;

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•	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.

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GLOSSARY OF CERTAIN DEFINED TERMS

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

Bankruptcy Court	United States Bankruptcy Court for the District of Delaware
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.

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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.

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PV-10 value	When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.
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.

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PART I

Unless the context requires otherwise, references in this annual report to the “Company,” “Chaparral,” “we,” “our” and “us” refer to Chaparral Energy, Inc. and its subsidiaries on a consolidated basis. We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of Certain Defined Terms” at the beginning of this annual report.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Overview

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.

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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.

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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.

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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

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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.”

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		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.

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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.

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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

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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.

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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.

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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.

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The following table provides a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows for the periods shown:

		As of December 31,
(in thousands)		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:

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						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.

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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

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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

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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.

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Disposal Wells

The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. EPA directly administers the UIC program in some states and in others administration is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. Because some states have become concerned that the disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding such disposal methods. For example, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division and the Oklahoma Geologic Survey continues to release well completion seismicity guidance, which most recently directs operators to adopt a seismicity response plan and take certain prescriptive actions, including mitigation, following anomalous seismic activity within 3.1 miles of hydraulic fracturing operations. In addition, since 2015, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has issued a number of directives restricting the future volume of wastewater disposed of via subsurface injection and directing the shut in of certain injection wells, including in areas where we operate.

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the Clean Water Act if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. 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

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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

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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

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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

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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.

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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.

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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,

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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.

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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

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$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.

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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.

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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.

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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.

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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.

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

•the uncertainties in estimating cleanup costs;

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

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

•new listing of species as “threatened” or “endangered”;

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

•future changes to environmental laws and regulations and their enforcement.

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

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

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

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

•injury or loss of life;

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

•pollution or other environmental damage;

•remediation and cleanup responsibilities;

•regulatory investigations and administrative, civil and criminal penalties;

•damage to our reputation; and

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

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

Resolution of litigation could materially affect our financial position and results of operations or result in dilution to existing stockholders.

We have been named as a defendant in certain lawsuits. See Item 3. Legal Proceedings. In some of these suits, our liability for potential loss upon resolution may be mitigated by insurance coverage. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we could incur losses that could be material to our financial position or results of operations in future periods. Additionally, we are parties to certain litigation initiated prior to our emergence from bankruptcy, and pursuant to the Reorganization Plan, liability arising under judgment or settlement related to certain of these claims would be satisfied through the issuance of stock which could result in dilution to existing stockholders. We may also become involved in litigation over certain issues related to the Reorganization Plan, including the proposed treatment of certain claims thereunder. The outcome of such litigation could have a material impact on our financial position or results of operations in future periods.

We may be subject to risks in connection with acquisitions and divestitures.

The successful acquisition of producing properties requires an assessment of several factors, including recoverable reserves, future oil and natural gas prices, operating costs and liabilities. The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

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No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Any inability to effectively manage the integration of acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth.

In addition, we may sell non-core assets in order to increase capital resources available for other core assets and to create organizational and operational efficiencies. We may also occasionally sell interests in core assets for the purpose of accelerating the development and increasing efficiencies in such core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets with terms we deem acceptable.

Any inability to maintain our current derivative positions in the future specifically could result in financial losses or could reduce our income and cash flows.

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. While the use of derivative contracts may limit or reduce the downside risk of adverse price movements, their use also may limit future benefits from favorable price movements and expose us to the risk of financial loss in certain circumstances.

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

Our commodity hedges currently consist of fixed price swaps, basis swaps and collars with financial institutions. The volumes and average notional prices of these hedges are disclosed in in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this report.

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

•our production is less than expected;

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

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

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

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

We are exposed to counterparty credit risk as a result of our receivables, including receivables from commodity derivative contracts and purchasers of production, as well as joint interest receivables from joint interest owners in the wells we operate.

In addition to credit risk related to receivables from commodity derivative contracts, we are exposed to risk of financial loss in connection with our receivables from oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. However, there is a possibility that some of our purchasers may experience credit downgrades or liquidity problems and may not be able to meet their financial obligations to us. Additionally, we are exposed to credit risk in connection with receivables arising from joint interest owners that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

The inability or failure of our oil and natural gas purchasers or our joint interest owners to meet their obligations to us or their insolvency of liquidation may materially adversely affect our financial results.

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

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

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

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

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.

We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

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

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology.

Our technologies, systems networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the disruption of our business operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations. To date we have not experienced any material losses relating to cyber-attacks, however there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance their protective measures or to investigate and remediate any cyber vulnerabilities. A cyber incident could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations or cash flows.

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

Although we take the steps customary in the oil and natural gas industry to review title and perform any curative work with respect to any title defects, our failure to completely cure any title defects may invalidate our title to the subject property and adversely impact our ability in the future to increase production and reserves. Any title defects or defects in assignment of leasehold rights in properties in which we hold an interest can render a lease worthless and may have an adverse impact on our financial condition, results of operations, and growth prospects.

Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves.

Risks Related to Our Indebtedness

Our level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our Credit Agreement and Senior Notes.

As of December 31, 2019, we had total indebtedness of $422.0 million. Our current and future indebtedness could have important consequences, including the following:

•	our high level of indebtedness could make it more difficult for us to satisfy our obligations;

•	the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;

•	the restrictions imposed on the operation of our business by the terms of our debt agreements may limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•	our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets;

•	we must use a material portion of our cash flow from operations to pay interest on our Senior Notes, borrowings under our Credit Agreement and our other indebtedness, which will reduce the funds available to us for operations and other purposes;

•	our high level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt;

•	our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited;

•	our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business;

•	we may be vulnerable to interest rate increases, as our borrowings under our Credit Agreement are at variable rates; and

•	our substantial level of indebtedness may limit our ability to obtain additional debt or equity financing due to applicable financial and restrictive covenants in our debt arrangements.

Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, prospects and ability to satisfy our obligations under our Credit Agreement.

We may incur substantially more debt. This could exacerbate the risks associated with our indebtedness.

We may incur substantial additional indebtedness in the future, subject to the terms of our Credit Agreement and the Indenture governing our Senior Notes, including under our Credit Agreement, through the issuance of additional notes or otherwise. As of December 31, 2019, the maximum facility amount under the Credit Agreement was $750 million, the borrowing base was $325 million and we had $194.4 million of available borrowing capacity thereunder. Our borrowing base is redetermined by the banks semi-annually effective May 1 and November 1 of each year. In addition, both we and the banks may request a borrowing base redetermination once between each scheduled redetermination.

If new debt is added to our current debt levels, the related risks that we face could intensify. Our level of indebtedness may prevent us from engaging in certain transactions that might otherwise be beneficial to us by limiting our ability to obtain additional financing, limiting our flexibility in operating our business or otherwise. In addition, we could be at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their business. Additionally, interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly.

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Restrictive covenants in our Credit Agreement and Senior Notes could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our Credit Agreement and our Indenture for our Senior Notes impose operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:

•	incur additional indebtedness;

•	make investments or loans;

•	create liens;

•	consummate mergers and similar fundamental changes;

•	make restricted payments;

•	make investments in unrestricted subsidiaries; and

•	enter into transactions with affiliates.

These restrictions could:

•	limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and

•	adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.

Our Credit Agreement includes provisions that require mandatory prepayment of outstanding borrowings and/or a borrowing base redetermination when we make asset dispositions over a certain threshold, which could limit our ability to generate liquidity from asset sales. Also, our Credit Agreement and Senior Notes require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general, or otherwise conduct necessary corporate activities. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. Our potential inability to meet financial covenants could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our Credit Agreement or Senior Notes. A default under our Credit Agreement or Senior Notes, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder, which in turn would trigger cross-acceleration and cross-default rights under our other debt.

If our debt is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us, or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies that are not subject to such restrictions.

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

Although our financial projections represent our view based on current known facts and assumptions about the future operations of the Company, there is no guarantee that the financial projections will be realized. Our financial performance is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to meet the projected financial results or achieve projected revenues and cash flows assumed in projecting future business prospects. To the extent we do not meet the projected financial results or achieve projected revenues and cash flows, we may lack sufficient liquidity to continue operating as planned or may be unable to service our debt obligations as they come due or may not be able to meet our operational needs. Any one of these failures may preclude us from, among other things: (a) taking advantage of future opportunities; (b) growing our businesses; or (c) responding to future changes in the oil and gas industry. Further, our failure to meet the projected financial results or achieve projected revenues and cash flows could lead to cash flow and working capital constraints, which constraints may require us to seek additional working capital. We may not be able to obtain such working capital when it is required.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or seek to restructure or refinance our indebtedness. If we cannot make scheduled payments on our long-term indebtedness, we will be in default and, as a result:

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•	debt holders, including the holders of our Senior Notes, could declare all outstanding principal and interest to be due and payable;

•	we may be in default under our master derivative contracts and counter-parties could demand early termination;

•	the lenders under our Credit Agreement could terminate their commitments to loan us money and foreclose against the assets securing their borrowings;

•	our credit rating could be lowered, which could inhibit our ability to incur additional indebtedness; and

•	we could be forced into bankruptcy or liquidation.

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

Availability under our Credit Agreement is subject to a borrowing base, set at $325.0 million as of December 2019, and which is redetermined by the banks semi-annually on May 1 and November 1 of each year. In addition, the banks may request a borrowing base redetermination once between each scheduled redetermination. Dispositions of our oil and natural gas assets, early terminations of our derivative contracts, or incurrence of permitted senior additional debt may also trigger automatic reductions in our borrowing base.  If the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days or (2) commencing within 30 days to repay the deficiency in equal monthly installments over a six -month period or (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency or (4) any combination of repayment as provided in the preceding three elections. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Asset sales may also reduce available collateral and availability under the Credit Agreement and could have a material adverse effect on our business and financial results. In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations.

We are subject to financing and interest rate exposure risks.

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

•	our credit ratings;

•	interest rates;

•	the structured and commercial financial markets;

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

•	tax burden due to new tax laws.

Assuming a constant debt level of $325.0 million, equal to our borrowing base as of December 7, 2019 under our Credit Agreement, the cash flow impact for a 12-month period resulting from a 100 basis point movement in interest rates, regardless of whether the spread widens or tightens, would be $3.3 million. As a result, any increases in our interest rates, or our inability to access the equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations, and growth prospects. The interest rate on our Senior Notes is fixed.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Credit Agreement are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash flows, including cash available for servicing our indebtedness, would correspondingly decrease. Assuming a constant debt level under our Credit Agreement of $325.0 million, equal to our borrowing base at December 31, 2019, the cash flow impact for a 12-month period resulting from a 100 basis point change in the variable component of our interest rate would be $3.3 million.

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Risks Related to Legislative and Regulatory Developments

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

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

Potential legislative and regulatory actions could negatively affect our business.

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

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

Our hydraulic fracturing operations are a significant component of our business, and it is an important and common practice that is used to stimulate production of hydrocarbons, particularly oil and natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, although no rule was ever finalized, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Beginning in August 2012, the EPA issued a series of rules under the CAA that establish new emission control requirements for emissions of volatile organic compounds and methane from certain oil and natural gas production and natural gas processing operations and equipment, and EPA has proposed amendments to these regulations as recently as September 2019. In March 2015 and November 2016, the BLM finalized rules governing hydraulic fracturing and venting and flaring on federal lands. Several of the EPA’s and the BLM’s recently promulgated rules concerning regulation of hydraulic fracturing, including BLM’s hydraulic fracturing and venting and flaring rules, are in various stages of suspension, repeal, implementation delay, and court challenges and, thus, the future of these rules is uncertain. Further, legislation to amend the SDWA to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in Congress from time to time. Several states and local jurisdictions in which we operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, such as requiring certain setback distances from residences or other sensitive areas, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

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More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells (and to a lesser extent, hydraulic fracturing) has caused increased seismic activity in certain areas. In response, some states, including states in which we operate, have imposed additional requirements on the construction and operation of underground disposal wells.  For example, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division and the Oklahoma Geologic Survey continue to release well completion seismicity guidance, discussed in more detail below, which most recently directs operators to adopt seismicity response plans and take certain prescriptive actions, including mitigation, following anomalous seismic activity within 3.1 miles of hydraulic fracturing operations.

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

Studies by both state and federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens.

In recent years, Oklahoma has experienced a significant increase in earthquakes and other seismic activity. On April 21, 2015, the Oklahoma Geologic Survey (“OGS”) issued a document entitled “Statement of Oklahoma Seismicity,” in which the agency states “the OGS considers it very likely that the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells.” The Oklahoma Corporation Commission (“OCC”) has issued directives restricting injection of high volumes of water into the Arbuckle formation and into the crystalline basement below within a specified area of interest (“AOI”) in Central and Western Oklahoma.  The AOI now includes more than 10,000 square miles and more than 600 Arbuckle disposal wells, resulting in a reduction of more than 800,000 barrels per day from the 2015 average injection volumes.  The OCC has adopted a “traffic light” system for disposal operators to review disposal well permits for proximity to faults seismicity in the area and other factors, and adopted rules requiring well pressure recording and reporting, and mechanical integrity tests on certain wells. In addition, the OCC has issued directives aimed at limiting the future growth of disposal rates into the Arbuckle by capping disposal volumes in the AOI, even those not operating under currently permitted volumes, to the thirty day disposal average. We operate 10 wells in the AOI and are fully compliant with all regulations relating to the disposal of produced water, and at this time our operations have not been affected.

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

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

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

The EPA has determined that GHGs present an endangerment to public health and the environment because such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented, and continues to adopt and implement, regulations that restrict emissions of greenhouse gases (“GHGs”) under existing provisions of the Clean Air Act (“CAA”). The EPA also requires the annual reporting of GHG emissions from certain large sources of GHG emissions in the United States, including certain oil and gas production facilities and oil and natural gas gathering and boosting operations. The EPA has also taken steps to limit methane emissions from oil and gas production facilities. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. And in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement entered into force in November 2016. However, in November 2019,

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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. Restrictions on emissions of GHGs that may be imposed could adversely affect the natural gas industry by reducing demand for hydrocarbons and by making it more expensive to develop and produce hydrocarbons, either of which could have a material adverse effect on future demand for our services. Moreover, climate change may cause more extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured. For a more detailed discussion of climate change, please see Environmental Matters and Regulation - Climate Change.

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

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

•	delay or denial of drilling permits;

•	shortening of lease terms or reduction in lease size;

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

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

•	increased severance and/or other taxes;

•	cyber-attacks;

•	legal challenges or lawsuits;

•	negative publicity about our business or the industry in general;

•	increased costs of doing business; and

•	reduction in demand for our products.

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

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

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

Changes in U.S. federal or state tax laws and regulations, including the 2017 Tax Act, may have a material adverse effect on our net revenues, financial condition, and results of operations.

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

Future legislative changes may increase the gross production tax charged on our oil and natural gas production.

Oklahoma imposes a gross production tax, or severance tax, on the value of oil, NGLs and natural gas produced within the state. Under recent changes to Oklahoma law, the gross production tax rate on the first three years of a horizontal well’s production was increased from 2% to 5%, effective July 1, 2018. As a result, production from new Oklahoma wells are now taxed at a 5% rate for the first 36 months of production and at 7% thereafter. The passage of any further legislation or ballot initiatives that would increase

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the tax burden on all of our oil and gas production occurring in the State of Oklahoma would negatively affect our net revenues, our financial condition, and results of operations.

Our ability to utilize our net operating loss carryforwards (“NOLs”) may be limited as a result of our emergence from bankruptcy and new limitations under the 2017 Tax Cuts and Jobs Act (the “2017 Tax Act”).

In general, Section 382 of the Internal Revenue Code (“IRC”) of 1986, as amended, provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future taxable income in the event of a change in ownership. Our emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of the IRC Section 382. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the ownership change and cancellation of indebtedness income on its tax attributes. Upon filing its 2017 U.S. Federal income tax return, the Company elected an available alternative which would likely result in the Company experiencing a limitation that subjects existing tax attributes at emergence to an IRC Section 382 limitation that could result in some or all of the remaining net operating loss carryforwards expiring unused. Upon final determination of tax return amounts for the year ended December 31, 2017, including attribute reduction that occurred on January 1, 2018, the Company had total federal net operating loss carryforwards of $1.01 billion including $760.1 million which are subject to limitation due to the ownership change that occurred upon emergence from bankruptcy and $251.3 million of post-change net operating loss carryforwards not subject to this limitation. Because of the limitations that apply to these NOL amounts, it is possible that some portion of the Company’s NOLs could expire unused.

In addition to the above, there are new limitations that apply to NOLs that arise in a taxable year ending after December 31, 2017.  Unlike the law in effect prior to the 2017 Tax Act, the amendments to Section 172 disallow the carryback of NOLs but allow for the indefinite carryforward of those NOLs.  In addition to the carryover and carryback changes, the 2017 Tax Act also introduces a limitation on the amount of post-2017 NOLs that a corporation may deduct in a single tax year under section 172(a) equal to the lesser of the available NOL carryover or 80 percent of a taxpayer’s pre-NOL deduction taxable income.

Limitations imposed on our ability to use NOLs to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.

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

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

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

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

Certain of our pipeline assets are natural gas gathering facilities.  Unlike interstate natural gas transportation facilities, natural gas gathering facilities are exempt from the jurisdiction of FERC under the Natural Gas Act of 1938 (“NGA”).  Although FERC has not made a formal determination with respect to all of our facilities we believe to be gathering facilities, we believe that these pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction.  The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress.  If FERC were to consider the status of an individual facility and determine that the facility and/or services

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provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act of 1978 (“NGPA”).  Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, results of operations and cash flows.  In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.

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

 

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

Risks Related to Our Common Stock

The market price of our common stock is volatile.

The trading price of our common stock and the price at which we may sell common stock in the future are subject to fluctuations in response to various factors, many of which are beyond our control, including:

•	limited trading volume in our common stock;

•	the concentration of holdings of our common stock;

•	variations in operating results;

•	changes in production levels;

•	our involvement in litigation;

•	general U.S. or worldwide financial market conditions;

•	conditions impacting the prices of oil and gas;

•	our liquidity and access to capital;

•	our ability to raise additional funds;

•	events impacting the energy industry;

•	lack of trading market;

•	changes in government regulations; and

•	other events.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

Trading of our common stock in the public market has been limited. Therefore, the holders of our common stock may be unable to liquidate their investment in our common stock.

Upon our emergence from bankruptcy, our old common stock was canceled and we issued new common stock.  From May 18, 2017, through May 25, 2017, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP”. From May 26, 2017, through July 23, 2018, our Class A common stock was quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. On July 24, 2018, we transferred our stock exchange listing for our Class A common stock from the OTCQB market to the New York Stock Exchange and began trading under the new ticker symbol “CHAP.” On December 19, 2018, all outstanding shares of our Class B common stock, converted into the same number of shares of Class A common stock pursuant to the terms of our Third Amended and Restated Certificate of Incorporation (the “Certificate of Incorporation”).

Although our common stock is listed on a U.S. national securities exchange, no assurance can be given that an active market will develop for our Class A common stock or as to the liquidity of the trading market for the common stock.

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Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock. As a result, investors in our securities may not be able to resell their shares at or above the purchase price paid by them or may not be able to resell them at all.

We may not be able to maintain our listing on the NYSE, which could have a material adverse effect on us and our stockholders.

Our common stock is listed on the New York Stock Exchange (the “NYSE”). There are a number of continued listing requirements that we must satisfy in order to maintain our listing on the NYSE. If we fail to maintain compliance with all applicable continued listing requirements and the NYSE determines to delist our common stock, the delisting could adversely affect the market liquidity of our common stock, our ability to obtain financing and our ability to fund our operations.

The NYSE’s standards for continued listing include, among other things, that the average closing price of a security as reported on the NYSE consolidated tape be $1.00 or greater over a consecutive 30 trading-day period. On February 28, 2020, we were notified by the NYSE that, for the last 30 trading days, the closing price for our common stock had closed below the minimum $1.00 per share requirement. In accordance with the NYSE’s listed company manual rules, we have been provided a period of six months, or until August 28, 2020 (the “Compliance Date”), to regain compliance with the closing price requirement.

If, at any time before the Compliance Date, we have a closing share price of at least $1.00 on the last trading day of any calendar month and an average closing share price of at least $1.00 over the 30 trading-day period ending on the last trading day of that month, then we would regain compliance with the closing price requirement. One action we may consider in order to regain compliance prior to the Compliance Date would be to implement a reverse stock split.

If we do not regain compliance with the closing price requirement by the Compliance Date, and are not eligible for an additional compliance period at that time, the NYSE’s staff will provide written notification to us that our common stock may be delisted. At that time, we may appeal the NYSE’s staff’s delisting determination to a committee of the NYSE’s board of directors. Any such delisting could result in our stock becoming ineligible to be included in one or more or held in or by one or more funds and otherwise adversely affect the market liquidity of our common shares, and, accordingly, the market price of our common shares could decrease. A delisting could adversely affect our ability to obtain financing for our operations or result in a loss of confidence by investors, customers, suppliers or employees.

There may be circumstances in which the interests of our significant stockholders may not align with the interests of our other stockholders, and concentrated share ownership may affect the market for the Company’s Class A common shares.

On December 20, 2019, as a result of the Company and SVP entering into the Amended SVP Agreement: (i) the authorized number of directors on the Board was increased from seven to eight, (ii) K. Earl Reynolds resigned from his positions as Chief Executive Officer, president and a director of the Company and Charles Duginski was appointed CEO, president and director of the Company and (iii) two SVP designees were appointed to the Board. As a result, the Board now consists of eight directors, two of which are SVP designees.

While the SVP designees’ fiduciary duties are to all Company stockholders, nothing obliges SVP, as a stockholder, to support initiatives that are supported by the Board as a whole. Likewise, nothing prevents SVP from pursuing transactions or financial arrangements that are in its, but not the Company’s or the Company’s other stockholders’, best interests. Furthermore, our significant concentration of share ownership may adversely affect the trading price of our Class A common shares because of decreased liquidity in the market for the shares or the potential perception by others in the investing community of disadvantages in owning shares in companies with significant stockholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See Item 1. Business and Properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See our additional disclosures in “Liquidity and Capital Resources—Contractual Obligations” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as “Note 18: Commitments and contingencies” in Item 8. Financial Statements and Supplementary Data. Such information is incorporated herein by reference.

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ITEM 3. LEGAL PROCEEDINGS

Chapter 11 Proceedings. Commencement of the Chapter 11 Cases in 2016 automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016 (“Petition Date”), and the claims remain subject to Bankruptcy Court jurisdiction. With respect to the proofs of claim asserted in the Chapter 11 Cases arising from the proceedings or actions below that were initiated prior to the Petition Date, we are unable to estimate the amount of such claims that will be allowed by the Bankruptcy Court due to, among other things, the complexity and number of legal and factual issues which are necessary to determine the amount of such claims and uncertainties related to the nature of defenses asserted in connection with the claims, the potential size of the putative classes, and the types of the properties and scope of agreements related to such claims. As a result, no reserves were established in respect of such proofs of claims or any of the proceedings or actions described below. To the extent that any of the legal proceedings were filed that relate to one or more claims accruing prior to the Petition Date and that result in a claim being allowed against us, pursuant to the terms of the Reorganization Plan, such claims will be satisfied through the issuance of new stock in the Company or, if the amount of such claim is below the convenience class threshold, through cash settlement. If the Bankruptcy Court were to allow the remaining unresolved proofs of claims from any of these cases in the full amount asserted therein, the Company, pursuant to the Plan of Reorganization, would be required to issue additional shares to the holders of such allowed proofs of claim that are in excess of a convenience class threshold, which could result in dilution to existing stockholders.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C (the “Naylor Farms case”). On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Trial Court”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other non-governmental Royalty Interest owners from crude oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. Plaintiffs indicated they seek damages in excess of $5.0 million, the majority of which consist of interest and may increase with the passage of time. We responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the Naylor Trial Court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court. Subsequently the bankruptcy stay was lifted for the limited purpose of determining the class certification issue.

On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the plaintiffs originally sought to certify. After additional briefing on the subject, on April 18, 2017, the Naylor Trial Court issued an order certifying the class to include only claims relating back to June 1, 2006. On May 3, 2019, our appeal of that class certification was denied by the Tenth Circuit Court of Appeals.

In addition to filing claims on behalf of the named and putative plaintiffs, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of $150.0 million in our Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90.0 million inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims, to which we will also object. The Bankruptcy Court order was affirmed by the United States District Court for the District of Delaware on September 24, 2019. On October 24, 2019, the Company filed its notice of appeal to the United States Court of Appeals for the Third Circuit.

We continue to dispute the plaintiffs’ allegations and are objecting to the claims both individually and on a class-wide basis.

W.H. Davis Family Limited Partnership Claims in the Company’s Chapter 11 Bankruptcy Cases (the “W.H. Davis case”). The W. H. Davis Family Limited Partnership and affiliates (collectively, “Davis”) filed Proofs of Claim in the Company’s Chapter 11 Cases. Davis claimed that Chaparral owed Davis $17.3 million as the result of Chaparral’s alleged diversion of CO₂ from the Camrick Unit and the North Perryton Unit to the Farnsworth Unit. All these units were divested by the Company as part of its EOR asset sale in November 2017. While the Company denies all claims asserted by Davis, the Company determined it was prudent to explore settlement of the claims. Accordingly, the Company and Davis agreed at mediation to settle Davis’ claims for an allowed claim of $2.7 million in Class 6 under the Reorganization Plan, which agreement was memorialized in a settlement term sheet executed by both parties on the day of the mediation, a settlement agreement executed by both parties thereafter, and a settlement stipulation executed by both parties that was filed with the Bankruptcy Court. Davis is now contesting the enforcement of the settlement under its terms, which resulted in the issuance of 84,347 shares of Class A common stock to Davis, claiming that he was mistaken in his understanding of the terms of the Reorganization Plan as relate to Class 6 claims. The Company is vigorously pursuing enforcement of the settlement in the Bankruptcy Court.

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

Holders of Record

As of March 6, 2020, there were 181 record holders of 47,938,374 outstanding shares of Class A common stock.

Market Information

Our Class A common stock began trading on the NYSE under the symbol “CHAP” starting July 24, 2018. Prior to being listed on the NYSE, our Class A common stock was quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE” from May 26, 2017 through July 23, 2018. Our previously outstanding Class B common stock was not listed or quoted on the OTCQB or any other stock exchange or quotation system, and has since been converted to Class A common stock on December 19, 2018. The following table sets forth the high and low last reported sales prices per share of our Class A common stock, as reported on the NYSE or OTCQB, as applicable. Based on information available to us, we believe transactions in our Class A common stock can be fairly summarized as follows for the period indicated:

		High				Low
2019
Fourth Quarter		$	1.76			$	0.70
Third Quarter		$	5.93			$	1.15
Second Quarter		$	8.18			$	3.00
First Quarter		$	8.40			$	4.13
2018
Fourth Quarter		$	18.30			$	4.48
Third Quarter		$	20.00			$	15.55
Second Quarter		$	21.25			$	16.75
First Quarter		$	25.85			$	16.65

Dividend Policy

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

Securities authorized for issuance under equity compensation plans

The Chaparral Energy, Inc. 2019 Long-Term Incentive Plan (the “LTIP”), was adopted by our Board of Directors on May 2, 2019, and become effective upon approval by stockholders at our annual stockholders meeting on June 28, 2019. The LTIP replaced

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the Chaparral Energy, Inc. Management Incentive Plan, adopted effective August 16, 2017 (the “MIP”), which was frozen as of the effective date of the LTIP so that no further awards will be granted under the MIP.

The LTIP authorizes us to issue up to 3,500,000 shares of common stock. The number of authorized shares available for issuance under the LTIP will be increased by any shares of the Common Stock subject to awards under the MIP that, following the approval of the LTIP, would have become available for re-grant under the terms of the MIP as a result of a grant’s cancellation or forfeiture, termination of a participant’s association with the Company, or using shares to fund an exercise price or withholding taxes due upon vest. The remaining shares available for issuance under the LTIP as of December 31, 2019 are disclosed below:

Plan category		Number of securities to be issued upon exercise of outstanding options, warrants and rights			Weighted-average exercise price of outstanding options, warrants and rights			Number of securities remaining available for future issuance under equity compensation plans (1)
Equity compensation plans approved by stockholders		—			—			2,674,391
Equity compensation plans not approved by stockholders		—			—			—

________________________________

(1)	Available for issuance under the LTIP. In addition, shares that are canceled, forfeited, terminated, expire or lapse shall again be available for grant under the LTIP. If shares of common stock subject to an award that may be settled with shares are, instead, settled for cash in lieu of shares, such shares shall again be available for grant under the LTIP.

Sales of Unregistered Securities

None.

Repurchases of Equity Securities

The following table provides information regarding Class A common stock repurchases made by the Company during the three months ended December 31, 2019.

Period		Total number of shares purchased (1)			Average price paid per share				Total number of shares purchased as part of publicly announced plans or programs		Maximum number of shares that may yet be purchased under the plans or programs
October 1-31, 2019		3,199			$	0.97			N/A		N/A
November 1-30, 2019		—			$	—			N/A		N/A
December 1-31, 2019		—			$	—			N/A		N/A
Total		3,199			$	0.97			N/A		N/A

_________________________________________

(1)	All shares purchases relate to tax withholding in connection with vesting of restricted shares issued under equity compensation plan. We expect to purchase approximately 4,000 shares during the first quarter of 2020 for similar tax withholding.

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ITEM 6. SELECTED FINANCIAL DATA

You should read the following historical financial data in connection with the financial statements and related notes and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this report. The financial data as of and for each of the five years ended December 31, 2019 was derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods. 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				For the Year Ended December 31,
(in thousands)		2019				2018				December 31, 2017					March 21, 2017				2016				2015
Statements of Operations Data:
Revenues		$	236,345			$	247,362			$	227,079				$	66,531			$	252,152			$	324,315
Operating (loss) income (1)		(409,351		)		30,177				(45,266		)			9,752				(295,464		)		(1,577,865		)
Net (loss) income (2)		(468,948		)		33,442				(118,902		)			1,041,959				(415,720		)		(1,333,844		)
Earnings (loss) per share:
Basic for Class A and Class B		$	(10.28	)		$	0.74			$	(2.64	)			*				*				*
Diluted for Class A and Class B		$	(10.28	)		$	0.73			$	(2.64	)			*				*				*
Statements of Cash Flows Data:
Net cash provided by operating activities		$	113,657			$	146,241			$	84,969				$	14,385			$	47,167			$	19,608
Expenditures for property, plant, and equipment and oil and natural gas properties		(267,068		)		(324,063		)		(157,718		)			(31,179		)		(146,296		)		(313,481		)
Other Data:
Production (MBoe)		9,593				7,490				6,603					1,796				8,926				10,200

________________________________

(1)	Operating income (loss) for 2019, 2018, the Successor period of 2017 and the Predecessor periods of 2017, 2016, and 2015 included oil and natural gas impairment charges of $430.7 million, $20.1 million, $42.1 million, nil, $282.5 million, and $1.5 billion, respectively.

(2)	Net income (loss) for 2019, 2018, the Successor period of 2017, the Predecessor period of 2017 and 2016 included reorganization items (expense) income attributable to our bankruptcy proceedings of $(1.8) million, $(2.4) million, $(3.1) million, $988.7 million, and $(16.7) million, respectively.

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

		Successor													Predecessor
		December 31,													December 31,
(in thousands)		2019				2018				2017					2016				2015
Balance Sheet Data:
Total oil and natural gas properties		$	892,886			$	1,160,518			$	992,353				$	555,184			$	798,837
Total assets		988,432				1,340,669				1,139,306					845,987				1,181,313
Total debt (1)		421,986				307,471				144,659					469,112				1,583,701
Total stockholders’ equity (deficit)		417,141				884,687				842,766					(1,042,153		)		(620,357		)
Other Data:
Proved reserves as of December 31, (MBoe)		96,558				94,807				76,287					131,301				155,541

________________________________

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

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report. In addition to historical financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

As permitted by Item 303(a) of Regulation S-K, we have omitted a discussion of the results for 2017. A discussion of those results can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation in our Annual Report on Form 10-K for the year ended December 31, 2018.

Executive Overview

Chaparral Energy, Inc. (NYSE: CHAP) is an independent oil and natural gas exploration and production company headquartered in Oklahoma City where it is focused on 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 Pennsylvanian-age Oswego formation, as well as Devonian-age Woodford Shale formation.

As of December 31, 2019, we had estimated proved reserves of 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 our STACK play which represents a 7% increase from the prior year. Our total reserves were 67% proved developed, 28% crude oil, 34% natural gas liquids and 38% natural gas.

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.  Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

2019 Financial and Operating Highlights

The following are material events in 2019 that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods:

•	Income. We incurred a net loss of $468.9 million and loss per share of $10.28. The loss was due to a ceiling test write-down of $430.7 million and non-cash mark to market losses on our derivatives of $40.8 million

•

Decreased LOE. LOE declined 9% from the prior year to $49.6 million in 2019, and on a per Boe basis, declined 29% to $5.17. The dollar decrease in LOE is due to our sole development focus in recent years in the STACK where operating costs are lower compared to our legacy properties. In conjunction with our development, production volumes have also increased in the STACK, leading to lower per Boe costs.

•	Production. Production in our STACK play increased 50% from the prior year to 7,907 MBoe in 2019. Total Company production was 9,593 MBoe in 2019 which was 28% higher than the prior year.

•	Decreased G&A. G&A declined $4.6 million or 12% from the prior year to $34.2 million. The decrease was due in part to a reduction in salaries and benefits corresponding to our reduction in headcount, which included a reduction from 123 corporate employees at the end of 2018 to 78 corporate employees at the end of 2019.

•

Disposition of Certain Non-Oil and Gas Assets. In August 2019, we sold the building housing our headquarters along with adjacent land, furniture and fixtures for net proceeds of $11.5 million, which we utilized to pay off the outstanding balance of the real estate mortgage note on the property. In September 2019, we terminated our financing lease obligations related to certain CO2 compressors, which resulted in a further reduction in our debt of $9.8 million.

•	Reserves. We had modest growth in our STACK proved reserves of 79,324 MBoe, which increased 7% from year-end 2018. Our total proved reserves of 96,558 MBoe increased approximately 2% from the prior year as additions through our drilling program were offset by price-related downward revisions.

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Capital Program

Our 2019 oil and natural gas capital expenditure was $269.8 million compared to 2018 where we incurred $341.0 million. The decrease in capital expenditure was primarily driven by a decrease in our leasehold acquisitions partially offset by an increase in drilling activity. The table below discloses our actual costs incurred, including costs that we have accrued for 2019.

		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)	For 2019, includes non-monetary acreage trades of $1.4 million and $0.8 million for seismic data.

(2)	For 2019, includes $7.0 million on development of wells operated by others and $12.6 million for wells drilled under the JDA. Of the $12.6 million incurred under the JDA, $4.1 million was for costs in excess of the well cost caps specified under the JDA (largely as a result of inflation) and $8.6 million was incurred to acquire additional working interests.

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

Excluding wells under the JDA and third party operated wells, we drilled and completed 49 gross wells, completed seven gross wells which were drilled in 2018 and drilled six gross wells to be completed in 2020, all within our STACK play. Our net capital to drill and complete the 49 gross wells which had an average working interest of approximately 90% was $177.9 million. Our 2019 capital expenditures included $11.3 million on acquisitions, which consisted of leasing and pooling of acreage, $1.4 million in non-monetary acreage trades and $0.8 million on seismic data.

Activity under the JDA in 2019 included three gross wells that were both drilled and completed during the year and four gross wells that were drilled in 2018 and completed in 2019. 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 the JDA.

Contractual Obligations to Drill Wells in Connection with Asset Acquisition. Under the terms of agreements pursuant to which the company acquired 7,000 acres of leasehold in Kingfisher County in early 2018, the company is required to drill and complete 10 wells on such leasehold in each of 2019, 2020, and 2021 and 15 wells in 2022. To the extent the company does not drill and complete the minimum number of wells in a given year, it is required to pay the sellers of the acreage $0.25 million for each deficient well. In 2019, the company drilled and completed six wells on the subject acreage and recorded a payable of $1.0 million for additional acquisition costs due to the sellers for four deficient wells. Taking into account current commodity price conditions, the company does

not intend to drill wells on the subject acreage in 2020 as it focuses on higher return opportunities. No determination has been made

with respect to 2021 or 2022; however, if the company fails to drill the prescribed number of wells in either year, it would be obligated

to make additional payments to the sellers.

2020 Outlook

In recent years, the landscape of domestic energy production has changed dramatically. Domestic energy production capabilities have increased the nation’s supply of both crude oil and natural gas, primarily driven by advances in technology, horizontal drilling and hydraulic fracture stimulation techniques. The increase in domestic supply of crude oil and natural gas has resulted in commodity prices that are meaningfully lower than they were a decade ago, and may remain volatile for the foreseeable future. We believe the prolonged lower commodity price environment has fundamentally changed the expectations of capital markets, resulting in new capital being both more difficult and more expensive to obtain.

As NGLs have become a more significant part of our production mix in recent years, we are also impacted by swings in NGL pricing. Our realized price on NGLs has fallen from 38% of crude oil in 2018 to 27% of crude oil in 2019. Of course, since crude oil and natural gas prices have also fallen during that period, there is a compound effect. For instance, the average daily spot price of West Texas Intermediate (“WTI”) crude oil has fallen from an average of $65.23/barrel during 2018 to $56.98/barrel during 2019 while the average daily Henry Hub spot price of natural gas has fallen from $3.15/MMBtu to $2.56/MMBtu over the same period.

Looking ahead, crude oil has experienced near term downward pressure as a result of softer demand from the growing impact of the coronavirus related crisis. Compounding the impact from the coronavirus, at a meeting in Vienna on March 6, 2020, the alliance between Russia and OPEC on production cuts broke down as both sides were unable to reach an agreement over how much to restrict

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production in order to stabilize crude oil prices. As a result, Saudi Arabia subsequently announced that it would significantly increase production and cut the prices at which it sells crude oil. Those actions and the potential reactions by other oil exporting countries contributed to a sudden and precipitous drop in global crude prices. At the time of this filing, spot prices for WTI were less than $35 per barrel. We continue to evaluate this rapidly developing situation as we plan our activities for the remainder of 2020.

Results of Operations

Overview

Total production increased from 2018 to 2019 as a result of our development activities in the STACK. Despite production growth from all three commodities, our gross commodity sales were approximately flat from 2018 to 2019 due to a decline in realized prices on those commodities. Our net loss of $468.9 million for the year was primarily the result of a ceiling test impairment of $430.7 million and a $40.8 million non-cash mark to market loss on our derivatives.

		For the Year Ended December 31,
(dollars in thousands)		2019				2018
Production (MBoe)		9,593				7,490
Gross commodity sales (1)		$	256,199			$	258,845
Net (loss) income		$	(468,948	)		$	33,442
Cash flow from operations		$	113,657			$	146,241

_____________________

(1) Amounts disclosed do not include deductions from transportation and processing costs.

 

Production

Production volumes by area were as follows (MBoe):

		For the Year Ended December 31,
		2019			2018
STACK
Kingfisher County		2,821			2,194
Canadian County		3,703			1,648
Garfield County		1,192			1,183
Other		191			254
Total STACK		7,907			5,279
Other Areas		1,686			2,211
Total		9,593			7,490

 

The table above reflects an increasing production trend in the STACK and a decreasing trend in our Other Areas. The pattern is a result of (i) our continued focus and capital investment in the higher-return STACK, (ii) divestitures of non-core assets in Other Areas at various times during 2018, including certain properties in the Oklahoma/Texas Panhandle in 2018, and (iii) the natural decline in production and lower capital investment in areas outside the STACK. See “Note 6: Acquisitions and divestitures” in Item 8 of this report for further detail on our divestitures.

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Commodity Sales

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

		For the Year Ended December 31,
		2019				2018
Commodity sales (in thousands)
Oil		$	173,555			$	171,749
Natural gas		40,543				41,506
Natural gas liquids		42,101				45,590
Gross commodity sales		$	256,199			$	258,845
Transportation and processing		(23,049		)		(16,276		)
Net commodity sales		233,150				242,569
Production
Oil (MBbls)		3,111				2,684
Natural gas (MMcf)		22,095				17,549
Natural gas liquids (MBbls)		2,799				1,881
MBoe		9,593				7,490
Average sales prices (excluding derivative settlements)
Oil per Bbl		$	55.79			$	63.99
Natural gas per Mcf		$	1.83			$	2.37
Natural gas liquids per Bbl		$	15.04			$	24.24
Transportation and processing per Boe		$	(2.40	)		$	(2.17	)
Average sales price per Boe		$	24.31			$	32.39

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

		2019 vs. 2018
(dollars in thousands)		Sales change				Percentage change in sales
Change in oil sales due to:
Prices		$	(25,518	)		(14.9	)%
Production		27,324				15.9	%
Total change in oil sales		$	1,806			1.1	%
Change in natural gas sales due to:
Prices		$	(11,718	)		(28.2	)%
Production		10,755				25.9	%
Total change in natural gas sales		$	(963	)		(2.3	)%
Change in natural gas liquids sales due to:
Prices		$	(25,739	)		(56.5	)%
Production		22,250				48.8	%
Total change in natural gas liquid sales		$	(3,489	)		(7.7	)%

Our gross commodity sales (before transportation and processing deductions) for the year ended December 31, 2019, of $256.2 million, decreased approximately 1% compared to gross commodity sales for the prior year ended December 31, 2018. The change is due to a decrease in realized prices across all commodity types, offset by the increases in overall production volumes.

Transportation and processing revenue deductions principally consist of deductions by our customers for costs to prepare and transport production from the wellhead to a specified sales point and processing costs of gas into natural gas liquids. Transportation and processing deductions were $23.0 million for 2019, representing an increase of 42% compared to the year ended 2018. Transportation and processing deductions were higher on a dollar basis as a result of increased production of natural gas and natural gas liquids as well as higher rates. Production growth during the year was primarily related to development in the STACK where we have experienced higher transportation and processing costs. As we continued to experience natural production declines in our other

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operating areas, the increase in natural gas and natural gas liquids production in the STACK resulted in slightly higher costs on a per Boe basis.

		For the Year Ended December 31,
		2019				2018
Transportation and processing charges deducted from revenue (in thousands)		$	23,049			$	16,276
Transportation and processing charges per Boe		$	2.40			$	2.17

Derivative Activities

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, collars and basis protection swaps.

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

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

		For the Year Ended December 31,
		2019				2018
Oil (per Bbl): (1)
Before derivative settlements		$	55.79			$	63.99
After derivative settlements		$	55.17			$	57.93
Post-settlement to pre-settlement price		98.9		%		90.5		%
Natural gas liquids (per Bbl):
Before derivative settlements		$	15.04			$	24.24
After derivative settlements		$	16.73			$	24.47
Post-settlement to pre-settlement price		111.2		%		100.9		%
Natural gas (per Mcf):
Before derivative settlements		$	1.83			$	2.37
After derivative settlements		$	2.05			$	2.21
Post-settlement to pre-settlement price		112.0		%		93.2		%

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

		As of December 31,
(in thousands)		2019				2018
Derivative assets (liabilities):
Crude oil derivatives		$	(21,805	)		$	19,756
Natural gas derivatives		3,551				345
NGL derivatives		2,169				4,581
Net derivative (liabilities) assets		$	(16,085	)		$	24,682

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

		For the Year Ended December 31,
(in thousands)		2019				2018
Derivative (losses) gains		$	(33,198	)		$	19,297

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		2019								2018
(in thousands)		Non-cash fair value adjustment				Settlement gains (losses)				Non-cash fair value adjustment				Settlement gains (losses)
Derivative (losses) gains:
Crude oil derivatives		$	(41,559	)		$	(1,935	)		$	33,159			$	(16,278	)
Natural gas derivatives		$	3,206			$	4,763			$	67			$	(2,662	)
NGL derivatives		$	(2,412	)		$	4,739			$	4,581			$	430
Derivative (losses) gains		$	(40,765	)		$	7,567			$	37,807			$	(18,510	)

Lease Operating Expenses 

		For the Year Ended December 31,
(in thousands, except per Boe data)		2019				2018
Lease operating expenses:
STACK		$	30,438			$	25,670
Other		19,167				28,549
Total lease operating expenses		$	49,605			$	54,219
Lease operating expenses per Boe:
STACK		$	3.85			$	4.86
Other		$	11.37			$	12.91
Lease operating expenses per Boe		$	5.17			$	7.24

LOE is sensitive to changes in demand for field equipment, services, and qualified operational personnel, which are driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices.

LOE for 2019 was $49.6 million, or $5.17 per Boe, a decrease of 9% on a dollar basis, or 29% on a per Boe basis, compared to 2018. The decrease was largely due to the divestiture of high-cost non-core assets during 2018, partially offset by LOE increases in the STACK where we are growing production. LOE for 2018, was $54.2 million or $7.24 per Boe.

Production Taxes (which include ad valorem taxes)

		For the Year Ended December 31,
(in thousands, except per Boe data)		2019				2018
Production taxes		$	13,290			$	13,150
Production taxes per Boe		$	1.39			$	1.76

Production taxes generally change in proportion to commodity sales. Some states offer exemptions or reduced production tax rates for horizontal drilling, enhanced recovery projects and high cost gas wells.

Production taxes for the twelve months ended December 31, 2019 were 1% higher than aggregate production taxes for the twelve months ended December 31, 2018. The increase was a result of an increase in overall production volumes partially offset by decreases in realized prices across all commodity types. Production taxes on a per Boe basis were lower due to the increase in overall production volumes, while overall revenues and corresponding production taxes remained relatively flat.

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

		For the Year Ended December 31,
(in thousands, except per Boe data)		2019				2018
DD&A:
Oil and natural gas properties		$	103,732			$	79,070
Property and equipment		5,901				8,818
Total DD&A		$	109,633			$	87,888
DD&A per Boe:
Oil and natural gas properties		$	10.81			$	10.56
Other fixed assets		0.62				1.18
Total DD&A per Boe		$	11.43			$	11.74

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

The increase in oil and gas DD&A between 2019 and 2018 was primarily the result of increased production during the period. The decrease in property and equipment DD&A is related to the discharge and removal of compressors under financing lease obligations and the sale of our headquarters building.

Full-Cost Ceiling Impairment

Energy commodity prices are volatile and a decline in commodity prices negatively impacts our revenues, profitability, cash flows, liquidity (including our borrowing base availability), and reserves, which could lead us to consider reductions in our capital program, asset sales or organizational changes. Prices we receive are determined by prevailing market conditions, regional and worldwide economic and geopolitical activity, supply versus demand, weather, seasonality and other factors that influence market conditions and often result in significant volatility in commodity prices. We mitigate the effects of volatility in commodity prices primarily by hedging a substantial portion of our expected production, focusing on a competitive cost structure and maintaining flexibility in our capital investment program with limited long-term commitments.

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

We recorded a ceiling test impairment on our oil and natural gas properties of $430.7 million in 2019 primarily due to a decrease in the price used to estimate our reserves, as disclosed in the table below, and due to impairments of unevaluated non-producing leasehold. We have previously and may in the future impair and/or relinquish certain undeveloped leases due to expirations or prior to expiration based upon changes in exploration plans, timing and extent of development activity, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors. Such impairments result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base. Impairments of non-producing leasehold of $80.1 million, which include expirations, were recorded in 2019, which directly increased the amount of ceiling test impairment. Substantially all of the non-producing leasehold impairment recorded in 2019 was related to our STACK acreage in Garfield County, Oklahoma as a result of our decision to suspend development of the area pending additional analysis of recent results. The non-producing leasehold impairment recognized in 2019 includes impairment of our fresh start step-up adjustments recorded upon our exit from bankruptcy. At the time of our bankruptcy emergence in March 2017, the carrying value of our non-producing leasehold was increased to reflect fair value in accordance with fresh start accounting (See “Note 4: Fresh start accounting” in Item 8. Financial Statements and Supplementary Data in this report for a discussion of our fresh start adjustments). Included in the leasehold impairment amount in 2019 disclosed above was $48.3 million associated with these fresh start step up adjustments.

Benchmark prices utilized in ceiling test		2019				2018
Oil (per Bbl)		$	55.69			$	65.56
Natural gas (per Mcf)		$	2.58			$	3.10
Natural gas liquids (per Bbl)		$	16.21			$	25.56

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Our ceiling test write-downs are as follows:

		For the Year Ended December 31,
(in thousands)		2019				2018
Ceiling test impairment		$	430,695			$	20,065

Our ceiling test impairment in 2018 was primarily due to the write-off of the value of non-producing acreage recorded during implementation of fresh start accounting attributable to our non-core leasehold outside of the STACK that we do not intend to develop. As noted above, impairments of leasehold result in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base and may adversely impact the ceiling test. In 2018, impairments of non-producing leasehold, which include expirations, were $102.5 million. During 2018, we had determined that given the commodity price environment, drilling returns in our acreage areas outside the STACK were not as attractive as those experienced in our STACK acreage. The company had focused all its drilling operations within the STACK to maximize returns and had no current plans to develop areas outside the STACK. As such, the value of those acreage areas was written-off in 2018.

The amount of any future impairment is difficult to predict. Changes in factors that impact our estimated ceiling limitation calculation, including, but not limited to, incremental proved reserves that may be added, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense, and further decreases in average commodity pricing may result in ceiling cost impairments in future periods.

Impairment of Other Assets

Our impairment loss in 2019 consists of a $6.4 million impairment on our headquarters building prior to its sale in August 2019 and $0.8 million to impair certain assets held for sale at the end of 2019. See “Note 7: Property and equipment” in Item 8. Financial Statements and Supplementary Data in this report for a discussion of these transactions.

General and Administrative Expenses (“G&A”)  

		For the Year Ended December 31,
(in thousands, except per Boe data)		2019				2018
G&A and cost reduction initiatives
Gross G&A expenses		$	42,682			$	49,499
Capitalized exploration and development costs		(8,472		)		(10,706		)
Net G&A expenses		$	34,210			$	38,793
Cost reduction initiatives		—				1,034
Net G&A, cost reduction initiatives and liability management expense		$	34,210			$	39,827
Net G&A expenses per Boe		$	3.57			$	5.18
Net G&A expenses and cost reduction initiatives expenses per Boe		$	3.57			$	5.32

The comparability of gross G&A expenses between 2019 and 2018 is materially impacted by severance charges and stock compensation.

These material adjustments affecting comparability are disclosed in the table below:

		For the Year Ended December 31,
(in thousands)		2019				2018
Severance		$	7,534			$	362
Stock compensation, gross		2,208				13,402
		$	9,742			$	13,764

The severance costs disclosed in the table above for 2019 are associated with the departure of certain company officers in addition to an overall workforce reduction.

Stock compensation expense, as disclosed in the table above, was substantially lower in 2019 compared to 2018 due to forfeitures, a decrease, as measured by the grant date fair value, of awards granted in 2019, and a decline in amount expensed due to the accelerated recognition method for our graded vesting awards.

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Absent the adjustments noted above, gross G&A expenses were slightly lower in 2019 compared to 2018 due to decreased salaries and benefits as a result of decreased headcount, partially offset by an increase in professional fees related to third party legal and professional services we have engaged to assist in governance matters and our cost savings initiatives.

Capitalized G&A decreased in 2019 compared to 2018 due to a decrease in gross G&A costs, primarily related to the decrease in stock compensation discussed above.

Other Costs and Expenses

Other costs and expenses consisted of the following:

		For the Year Ended December 31,
(in thousands)		2019				2018
Restructuring		$	—			$	425
Subleases		1,075				1,611
Total other expense		$	1,075			$	2,036

Restructuring. We previously incurred exit costs in conjunction with our EOR asset divestiture, which predominantly consisted of one-time severance and termination benefits for the affected employees. The expense recorded in 2018 is a result of termination benefits for the final slate of employees terminated as a result of the divestiture.  

Subleases. Our subleases consisted of CO₂ compressors that were previously utilized in our EOR operations and leased as financing and operating leases from U.S. Bank but were subsequently subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases were equal to the original leases. Subsequent to the execution of the subleases, all payments received from the Sublessee were reflected as revenues on our statement of operations. The amounts in the table above reflect payments we made to U.S. Bank on the original operating leases while payments on the original financing leases were a reduction of debt and recognition of interest expense. In September 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to the originating leases and to the subleases.

Loss (Gain) on Asset Sales

The amounts reflected on our statement of operations are primarily related to gains or losses from the sale of plant, property and equipment. Other than our EOR asset sale, our divestitures of oil and natural gas assets are generally below the threshold of reserve volumes sold that would trigger a requirement to recognize a gain or loss under full cost accounting rules, and hence gains or losses are generally not recorded.

Reorganization Items

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

		For the Year Ended December 31,
(in thousands)		2019				2018
Loss on the settlement of liabilities subject to compromise		$	—			$	48
Professional fees		1,753				2,344
Total reorganization items		$	1,753			$	2,392

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Other Income and Expenses

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

		For the Year Ended December 31,
(in thousands)		2019				2018
Credit facility and Exit Revolver		$	3,305			$	5,118
Senior Notes		26,250				13,271
Bank fees, other interest and amortization of issuance costs		4,907				3,919
Gross interest expense		34,462				22,308
Capitalized interest		(11,796		)		(10,925		)
Total interest expense		$	22,666			$	11,383
Average long-term borrowings (including amounts subject to compromise)		$	391,338			$	275,978

Gross interest expense was higher in 2019 compared to 2018 due to an increase in the average debt balance that we carried throughout the year. Our capitalized interest is based on the carrying value of our unevaluated non-producing leasehold multiplied by a weighted average effective interest rate. Capitalized interest for 2019 increased marginally over 2018 as a result of a higher weighted average interest rate. As a result of applying fresh start accounting upon our emergence from bankruptcy, the carrying value of our unevaluated non-producing leasehold was significantly increased to reflect the fair value of our acreage in the STACK. However, we do not record capitalized interest on the portion of our unevaluated non-producing leasehold that resulted from the fresh start fair value adjustment

Loss on extinguishment of debt. The $1.6 million loss incurred in 2019 was a result of our early payoff of the real estate mortgage on our headquarters building when we sold the property.

Income Taxes

		For the Year Ended December 31,
(dollars in thousands)		2019				2018
Current income tax benefit		$	—			$	(77	)
Deferred income tax expense		—				—
Total income tax benefit		$	—			$	(77	)
Effective tax rate		—				(0.2		)%
Total net deferred tax liability		$	—			$	—

We recorded a net loss for the years ended December 31, 2019 and 2018. Since we maintain a full valuation allowance on our deferred tax assets, we have recorded no income tax provision or benefit during those two years, except for a $0.1 million provision recorded in 2018. That provision related to the reversal of the valuation allowance against the existing AMT credit carryforward as it is refundable under the 2017 Tax Act.

Our effective tax rate is affected by changes in valuation allowances, recurring permanent differences and discrete items that may occur in any given year but are not consistent from year to year. At December 31, 2019 and December 31, 2018, we have a full valuation allowance for the amounts by which our deferred tax assets exceed our deferred tax liabilities due to uncertainty regarding their realization. We intend to maintain a valuation allowance on our net deferred tax assets until there is sufficient evidence to support the reversal of these allowances. As long as we conclude that the valuation allowance against our net deferred tax assets is necessary, we likely will not have any additional deferred income tax expense or benefit. For further discussion of our valuation allowance, see “Note 12: Income taxes” in Item 8. Financial Statements and Supplementary Data in this report.

In 2017, upon emergence from bankruptcy, as described in “Note 3: Chapter 11 reorganization,” we experienced an ownership change as defined in Section 382 of the IRC, that imposes an annual limitation of the amount of our taxable income that can be offset by our federal loss carryforwards in future years.  Upon final determination of tax return amounts for the year ended December 31, 2017, including attribute reduction that occurred on January 1, 2018, we have total federal net operating loss carryforwards of $1.0 billion, which will expire between 2028 and 2037 if not utilized in earlier periods, including $760.1 million which are subject to limitation due to ownership change that occurred upon emergence from bankruptcy and $251.3 million of post-change net operating loss carryforwards not subject to limitation. The Company has incurred additional net operating losses for the years ended December 31, 2018 and December 31, 2019 that are currently not subject to an IRC Section 382 limitation. Due to the 2017 Tax Act, the estimated federal net operating loss generated in tax years after 2017 does not expire but may only offset 80% of taxable income in

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any given year. The limitations on net operating loss utilization did not result in a current tax liability for the tax years ended December 31, 2019 or December 31, 2018. For further discussion of the impact of our emergence from bankruptcy on the amount and availability of our loss carryforwards, see “Note 12: Income taxes” in Item 8. Financial Statements and Supplementary Data in this report. Future equity transactions involving us or our stockholders (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes, further limiting the availability of our loss carryforwards to reduce future taxable income.

As of December 31, 2019, our state net operating loss carryforwards were approximately $1.5 billion, which will expire between 2020 and 2039 if not utilized in earlier periods.

Liquidity and Capital Resources

Our industry requires that we continuously commit substantial investment to drill and develop our oil and natural gas properties such that production from new wells can offset the natural production decline from existing wells. During the past three years, cash flows provided by operating activities have been insufficient to fully fund our capital programs and instead were augmented by derivative receipts, asset sales and debt. Our internal sources of liquidity in 2019 consisted primarily of cash flows provided by operating activities, and to a lesser extent, from divestitures of property and equipment and derivative receipts. Our external sources of liquidity in 2019 consisted primarily of debt financing as we drew $130.0 million from our credit facility during the year. At year end, our outstanding Senior Notes totaled $300.0 million, the outstanding balance on our credit facility was $130.0 million and our cash balance was $22.6 million. As of February 29, 2020, our outstanding Senior Notes remained unchanged, the balance on our credit facility was $145.0 million and our cash balance was $22.6 million.

With sustained deterioration in the commodity market, our goal for 2020 is to approximate cash flow neutrality by aligning our capital spending with our revenues and focusing on improving the profitability of the business, generally. Because a large proportion of the our acreage is held by production and we do not have long-term rig contracts nor minimum volume commitments, we have a high degree of operational flexibility to adjust to fluctuation commodity prices.

In the event of a reduction in the bank price deck utilized in our upcoming spring borrowing base redetermination, absent other developments, we would likely face a reduction in our borrowing base from its current level. However, we do not expect a reduction in our borrowing base to impact our planned capital expenditures or day to day operations for at least the next 12 months, and we believe our current liquidity level and balance sheet provide flexibility and position us to fund our business throughout the commodity price cycle.

  

Because our cash flows and liquidity are highly dependent on the prices we receive for oil, natural gas and NGLs, we will continue to evaluate the volatile commodity price environment and our level of capital spending throughout 2020. Prices we receive are determined by prevailing market conditions, regional and worldwide economic and geopolitical activity, supply versus demand, weather, seasonality and other factors that influence market conditions and often result in significant volatility in commodity prices. In addition to reducing revenue from commodity sales, low prices can adversely affect our liquidity through the impact on the borrowing base under our credit facilities. When commodity prices decline, as has been the case over the last year, the borrowing base price deck approved by our lenders decreases, which, absent other developments, leads to a reduction in our borrowing base and the available amount we can borrow.

We mitigate the impact of volatility in commodity prices, in part through the use of derivative instruments which help stabilize our cash flow. We currently have derivative contracts in place for oil and natural gas production from 2020 through 2021(see Item 7A. Quantitative and Qualitative Disclosures About Market Risk).

Sources and Uses of Cash

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

		For the Year Ended December 31,
(dollars in thousands)		2019				2018
Cash flows provided by operating activities		$	113,657			$	146,241
Cash flows used in investing activities		(244,834		)		(292,050		)
Cash flows provided by financing activities		116,326				155,523
Net (decrease) increase in cash during the period		$	(14,851	)		$	9,714

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

Our cash flows provided by operating activities were lower in 2019 compared to 2018 primarily due to higher cash interest payments and lower revenues. Our Senior Notes were issued in June 2018 with the first coupon payment not due until January 2019. As a result, we had two coupon payments on our Senior Notes in 2019 compared to none in 2018, which resulted in the increase in cash interest paid. As discussed previously, revenues were lower in 2019 due to a decrease in realized prices across all commodity types.

Net cash used in investing activities during 2019 consisted of cash outflows for capital expenditure of $267.1 million partially offset by cash inflows from asset sales of $14.7 million and derivative settlement receipts of $7.6 million. Our asset sales in 2019 included proceeds of $11.5 million from the sale of our headquarters building.

Net cash used in investing activities during 2018 consisted of cash outflows for capital expenditure of $324.1 million and derivative settlement payments of $18.5 million partially offset by cash inflows from asset sales of $50.5 million.

Cash flows provided by financing activities in 2019 included proceeds of $130.0 million from borrowings under our credit facility partially offset by debt and financing lease repayments of $10.8 million, debt extinguishment costs of $1.6 million and treasury stock repurchases of $1.2 million. Our debt repayments in 2019 included a repayment of $8.2 million representing the remaining balance on our real estate mortgage note, which also resulted in our incurring the aforementioned debt extinguishment costs in connection with the note being paid off early. The mortgage note repayment was funded by proceeds from the sale of our headquarters building. Our treasury stock purchases were made in connection with the satisfaction of income tax withholding obligations that matured when restricted stock awards vested during the year.

Cash flows provided by financing activities in 2018 included proceeds from our issuance of $300.0 million in Senior Notes in June 2018 and $116.0 million in borrowings under our credit facility occurring in the first half of the year partially offset by debt repayments of $243.7 million which included payment of the entire outstanding balance of our credit facility with the proceeds from the offering of our Senior Notes. Cash was also utilized in 2018 for $9.1 million in debt issuance costs, $4.9 million in treasury stock purchases and $2.7 million in financing lease payments. Our debt issuance costs were primarily incurred in connection with our Senior Note issuance. Our treasury stock purchases were made in connection with the satisfaction of income tax withholding obligations that matured when restricted stock awards vested during the year.

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

Capital Expenditures

Our actual costs incurred, including costs that we have accrued for 2019 and for oil and natural gas properties are summarized in the following table:

		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 non-monetary acreage trades of $1.4 million and $0.8 million for seismic data.

(2)	Includes $7.0 million on development of wells operated by others and $12.6 million under the JDA.

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

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Please see “Capital Program” above for our discussion of 2019 capital activities.

We continually evaluate our capital needs and compare them to our capital resources. Our level of exploration and development expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors. We will continue to monitor our capital spending in 2020 closely and may adjust our spending accordingly based on actual and projected cash flows, our liquidity and our capital requirements.

Indebtedness

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

(in thousands)		December 31, 2019				December 31, 2018
Credit facility		$	130,000			$	—
Senior Notes		300,000				300,000
Real estate mortgage note		—				8,588
Installment notes payable collateralized by personal property		371				354
Capital lease obligations		1,653				11,677
Unamortized issuance costs		(10,038		)		(13,148		)
Total debt, net		421,986				307,471

Senior Notes

On June 29, 2018, we completed the issuance and sale at par of $300.0 million in aggregate principal amount of our Senior Notes in a private placement under Rule 144A and Regulation S of the Securities Act of 1933, as amended. The offering costs were $7.3 million resulting in net proceeds of $292.7 million, which we used to repay the entire outstanding balance of our credit facility and for general corporate purposes.

The Senior Notes bear interest at a rate of 8.75% per year beginning June 29, 2018 (payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2019) and will mature on July 15, 2023.

The Senior Notes are the Company’s senior unsecured obligations and rank equal in right of payment with all of the Company’s existing and future senior indebtedness, senior to all of the Company’s existing and future subordinated indebtedness and effectively subordinated to all of the Company’s existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries.

See “Note 8: Debt” in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the provisions under our Senior Notes.

Credit Agreement

The Credit Agreement is a $750 million facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our Credit Agreement is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on or around May 1 and November 1 of each year as well as limits imposed by financial covenants (see below). In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. Our borrowing base under our Credit Agreement as of December 31, 2018, was $325.0 million with the unused portion amounting to $195.0 million.

Interest on the outstanding amounts under the credit facility will accrue at an interest rate equal to either (i) the Alternate Base Rate (as defined in the Credit Agreement) plus an Applicable Margin (as defined in the Credit Agreement) that ranges between 1.00% to 2.00% depending on utilization or (ii) the Adjusted LIBO Rate (as defined in the New Credit Facility) applicable to one, two, three, or six month borrowings plus an Applicable Margin that ranges between 2.00% to 3.00% depending on utilization. In the case that an Event of Default (as defined under the Credit Agreement) occurs, the outstanding amounts will bear an additional 2.00% interest plus the applicable Alternate Base Rate or Adjusted LIBO Rate and corresponding Applicable Margin.

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Commitment fees that ranges between 0.375% and 0.500%, depending on utilization, accrue on the average daily amount of the unused portion of the borrowing base and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the Applicable Margin used to determine the interest rate applicable to borrowings that are based on Adjusted LIBO Rate.

The Credit Agreement contains covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our Credit Agreement specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others. See “Note 8: Debt” in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the provisions under our Credit Agreement.

 

The financial covenants require, for each fiscal quarter ending on and after December 31, 2018, that we maintain: (1) a Current Ratio (as defined in the Credit Agreement) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the Credit Agreement) of no greater than 4.0 to 1.0 calculated on a trailing four-quarter basis. We were in compliance with these financial covenants as of December 31, 2019.

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

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

(in thousands)		December 31, 2019				December 31, 2018
Current assets per GAAP		$	80,390			$	134,431
Plus—Availability under the credit facility		194,406				208,355
Less—Short term derivative instruments		(947		)		(24,025		)
Current assets as adjusted		$	273,849			$	318,761
Current liabilities per GAAP		$	122,669			$	136,710
Less—Short term derivative instruments		(11,957		)		—
Less—Short-term asset retirement obligations		(2,083		)		(1,057		)
Less—Current operating lease obligation		(1,259		)		—
Less—Current maturities of long term debt		(594		)		(12,371		)
Current liabilities as adjusted		$	106,776			$	123,282
Current ratio per GAAP		0.66				0.98
Current ratio for loan compliance		2.56				2.59

Financing Leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million through the sale and subsequent leaseback of existing compressors owned by us. The lease financing obligations were for 84 month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. In conjunction with the sale of our EOR assets, these compressors were subleased to the buyer of those assets although we remained the primary obligor in relation to U.S. Bank National Association. In August 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to these compressor leases and the removal of the associated debt and property balances from our balance sheet. Our remaining financing leases consist primarily of leases on our fleet vehicles. See “Note 17: Leases” in Item 8. Financial Statements and Supplementary Data in this report for an additional discussion of our leases.

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Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2019 :

(in thousands)		Less than 1 year				1-3 years				3-5 years				More than 5 years				Total
Debt:
Senior Notes including interest		$	26,250			$	52,500			$	326,250			$	—			$	405,000
Credit Facility, including estimated interest and other fees		5,970				141,775				—				—				147,745
Other long-term notes, including estimated interest		182				179				45				—				406
Capital leases, including estimated interest		530				1,060				281				—				1,871
Asset retirement obligations (1)		2,083				—				—				21,073				23,156
Purchase obligations		253				—				—				—				253
Operating lease obligations		1,389				941				—				—				2,330
Derivative obligations (2)		17,821				5,075				—				—				22,896
Total		$	54,478			$	201,530			$	326,576			$	21,073			$	603,657

________________________________

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

(2)	Represents gross liabilities prior to any master netting provisions.

Our rent expense for the years ended December 31, 2019, 2018 and 2017 was $5.5 million, $3.7 million and $5.0 million, respectively. Our operating lease currently consists of a two year lease on office space which commenced in August 2019. Our financing leases currently consist of four-year leases on fleet vehicles and a five-year lease on office equipment. We also rent wellhead compressors which typically have initial terms of six months and are subsequently renewable on a month-to month basis. See “Note 17: Leases” in Item 8. Financial Statements and Supplementary Data in this report for an additional discussion of our leases.

Under the terms of agreements pursuant to which the company acquired 7,000 acres of leasehold in Kingfisher County in early 2018, the company is required to drill and complete 10 wells on such leasehold in each of 2019, 2020, and 2021 and 15 wells in 2022. To the extent the company does not drill and complete the minimum number of wells in a given year, it is required to pay the sellers of the acreage $0.25 million for each deficient well. In 2019, the company drilled and completed six wells on the subject acreage and recorded a payable of $1.0 million for additional acquisition costs due to the sellers for four deficient wells. Taking into account current commodity price conditions, the company does not intend to drill wells on the subject acreage in 2020 as it focuses on higher return opportunities. No determination has been made with respect to 2021 or 2022; however, if the company fails to drill the prescribed number of wells in either year, it would be obligated to make additional payments to the sellers.

Off-Balance Sheet Arrangements

At December 31, 2019, we did not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

 

Revenue recognition. See “Note 16: Revenue recognition” in Item 8. Financial Statements and Supplementary Data for a description of our revenue recognition policies and the impact of adopting Accounting Standards Codification 606: Revenue from Contracts with Customers (“ASC 606”).

Leases. We adopted Accounting Standards Codification (“ASC”) Topic 842, Leases (“ASC 842”) at the beginning of 2019. ASC 842 requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability on the balance

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sheet for all leases except those with a term of 12 months or less. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. As a result of our adoption of ASC 842, operating leases which were previously “off balance sheet” are now reflected on the balance sheet resulting in an increase in assets and associated liabilities. Our business is capital intensive requiring the use of tangible equipment such as drilling rigs, separators, pumps and generators to drill and complete wells. We generally utilize third-party vendors to provide drilling and completion services and we do not own the equipment to perform these activities. The term and provisions of these agreements, which are negotiated to suit the business needs of the Company and may constitute leases under ASC 842, may result in recognition of assets and liabilities on our balance sheet and fluctuations in the associated amounts. See “Note 17: Leases” in Item 8. Financial Statements and Supplementary Data in this report for an additional discussion of our leases.

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

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

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

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

Proved oil and natural gas reserves quantities. Proved oil and natural gas reserves are the quantities of crude oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Our proved reserve information included in this report is based on estimates prepared by Cawley. Cawley evaluated 100% of the estimated future net revenues of our proved reserves as of December 31, 2019. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

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

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

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

Future development and abandonment costs.  Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and natural gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis. We record a liability for the estimated fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. Significant assumptions used in estimating such obligations include estimates of the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments, all of which are Level 3 inputs in the fair value hierarchy. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required for the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our estimated future cash flows.

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

•	taxable income in prior carryback years;

•	future reversals of existing taxable temporary differences;

•	tax planning strategies; and

•	future taxable income exclusive of reversing temporary differences.

As of December 31, 2019, the Company had a full valuation allowance against its net deferred tax asset. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.

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

Bankruptcy proceedings. We have applied Accounting Standards Codification 852 “Reorganizations” (“ASC 852”) in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization items, net” in the accompanying Consolidated Statements of Operations. Upon emergence from bankruptcy, we qualified for and applied fresh start accounting to our financial statements in accordance with ASC 852 as (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Reorganization Plan was less than the post-petition liabilities and allowed claims. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Predecessor and Successor periods may lack comparability See “Note 3: Chapter 11 reorganization” and “Note 4: Fresh start accounting” in Item 8. Financial Statements and Supplementary Data of this report for more information.

Recent Accounting Pronouncements

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

Effects of inflation and pricing

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our New Credit Facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration, and development activities. Based on our production for the year ended December 31, 2019, our gross revenues from commodity sales would change approximately $5.9 million for each $1.00 change in oil and NGL prices and $2.2 million for each $0.10 change in natural gas prices.

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

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

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factors we consider in closing or restructuring a position before the settlement date are identical to those reviewed when deciding to enter into the original derivative position.

The fair value of our outstanding derivative instruments at December 31, 2019, was a net liability of $16.1 million. Based on our outstanding derivative instruments as of December 31, 2019, a 10% decrease in the December 31, 2019, forward curves used to mark-to-market our derivative instruments would have increased our position to a net asset of $3.6 million while a 10% increase would have resulted in a net liability position of $36.7 million.

Our outstanding oil derivative instruments as of December 31, 2019, are summarized below:

					Weighted average fixed price per Bbl
Period and type of contract		Volume MBbls			Swaps				Purchase puts				Sold calls
January - March 2020
Oil swaps		504			$	50.47
Oil collars		195			$	—			$	55.00			$	66.42
Oil roll swaps		120			$	0.46
April - June 2020
Oil swaps		744			$	51.99
Oil roll swaps		110			$	0.42
July - September 2020
Oil swaps		495			$	50.63
Oil roll swaps		90			$	0.30
October - December 2020
Oil swaps		531			$	50.49
Oil roll swaps		90			$	0.30
January - March 2021
Oil swaps		170			$	46.24
Oil roll swaps		90			$	0.30
April - June 2021
Oil swaps		165			$	45.97
Oil roll swaps		60			$	0.30
July - September 2021
Oil swaps		183			$	46.64
October - December 2021
Oil swaps		171			$	46.07

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Our outstanding natural gas derivative instruments as of December 31, 2019, are summarized below:

Period and type of contract		Volume BBtu			Weighted average fixed price per MMBtu
January - March 2020
Natural gas swaps		2,340			$	2.67
Natural gas basis swaps		2,040			$	(0.46	)
April - June 2020
Natural gas swaps		2,340			$	2.67
Natural gas basis swaps		2,040			$	(0.46	)
July - September 2020
Natural gas swaps		1,500			$	2.75
Natural gas basis swaps		1,500			$	(0.46	)
October - December 2020
Natural gas swaps		1,500			$	2.75
Natural gas basis swaps		1,500			$	(0.46	)

Our outstanding natural gas liquid derivative instruments as of December 31, 2019 are summarized below:

Period and type of contract		Volume Thousands of Gallons			Weighted average fixed price per gallon
January - March 2020
Butane swaps		2,352			$	0.71
Natural gasoline swaps		4,032			$	1.13
Propane swaps		8,988			$	0.61
April - June 2020
Butane swaps		497			$	0.53
Natural gasoline swaps		2,476			$	1.17
Propane swaps		5,884			$	0.51

Interest rates 

At December 31, 2019, borrowings under our credit facility totaled $130.0 million. Those borrowings are subject to market rates of interest as determined from time to time by the banks. As of December 31, 2019, our outstanding borrowings were accruing interest at the Adjusted LIBO Rate (as defined in the Credit Agreement, as defined below), plus the Applicable Margin (as defined in the Credit Agreement), which resulted in a weighted average interest rate of 4.03% on the amount outstanding. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level under our Credit Agreement of $325.0 million, equal to our borrowing base at December 31, 2019, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $3.3 million.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to financial statements  

	Page
Chaparral Energy, Inc. consolidated financial statements:
Report of Independent Registered Public Accounting Firm	74
Consolidated Balance Sheets	75
Consolidated Statements of Operations	76
Consolidated Statements of Stockholders’ Equity (Deficit)	77
Consolidated Statements of Cash Flows	78
Notes to Consolidated Financial Statements	79

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Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Chaparral Energy, Inc.

 

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. (a Delaware corporation) and subsidiaries (the Company) as of December 31, 2019 and 2018 (Successor), the related consolidated statements of operations, shareholders’ equity (deficit), and cash flows for the years ended December 31, 2019 and 2018 (Successor), the period from March 22, 2017 through December 31, 2017 (Successor) and the period from January 1, 2017 through March 21, 2017 (Predecessor), and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018 (Successor), and the results of its operations and its cash flows for the years ended December 31, 2019 and 2018 (Successor), the period from March 22, 2017 through December 31, 2017 (Successor), and the period from January 1, 2017 through March 21, 2017 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 11, 2020 expressed an unqualified opinion.

Emergence from bankruptcy

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

Basis for opinion

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

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

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

Oklahoma City, Oklahoma

March 11, 2020

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Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

		December 31,
(in thousands, except share data)		2019				2018
Assets
Current assets:
Cash and cash equivalents		$	22,595			$	37,446
Accounts receivable, net		49,647				66,087
Inventories, net		3,730				4,059
Prepaid expenses		3,471				2,814
Derivative instruments		947				24,025
Total current assets		80,390				134,431
Property and equipment, net		9,217				43,096
Right of use assets from operating leases		2,444				—
Oil and natural gas properties, using the full cost method:
Proved		1,276,036				915,333
Unevaluated (excluded from the amortization base)		371,229				466,616
Accumulated depreciation, depletion, amortization and impairment		(754,379		)		(221,431		)
Total oil and natural gas properties		892,886				1,160,518
Held for sale assets		2,860				—
Derivative instruments		—				2,199
Other assets		635				425
Total assets		$	988,432			$	1,340,669
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities		$	64,558			$	73,779
Accrued payroll and benefits payable		10,963				10,976
Accrued interest payable		12,227				13,359
Revenue distribution payable		22,370				26,225
Long-term debt and capital leases, classified as current		594				12,371
Derivative instruments		11,957				—
Total current liabilities		122,669				136,710
Long-term debt and capital leases, less current maturities		421,392				295,100
Derivative instruments		5,075				1,542
Noncurrent operating lease obligations		917				—
Deferred compensation		165				540
Asset retirement obligation		21,073				22,090
Commitments and contingencies (See Note 18)
Stockholders’ equity:
Preferred stock, 5,000,000 shares authorized, none issued and outstanding as of December 31, 2019 and 2018		—				—
Common stock, $0.01 par value, 192,130,071 shares authorized; 48,413,185 issued and 47,942,230 outstanding at December 31, 2019 and 46,651,616 issued and 46,390,513 outstanding at December 31, 2018		485				467
Additional paid in capital		977,174				974,616
Treasury stock, at cost, 470,955 and 261,103 shares at December 31, 2019 and 2018		(6,110		)		(4,936		)
Accumulated deficit		(554,408		)		(85,460		)
Total stockholders’ equity		417,141				884,687
Total liabilities and stockholders’ equity		$	988,432			$	1,340,669

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

						Successor									Predecessor
										Period from					Period from
										March 22, 2017					January 1, 2017
		For the Year Ended December 31,								through					through
(in thousands, except share and per share data)		2019				2018				December 31, 2017					March 21, 2017
Revenues:
Commodity sales		$	233,150			$	242,569			$	226,493				$	66,531
Sublease revenue		3,195				4,793				586					—
Total revenues		236,345				247,362				227,079					66,531
Costs and expenses:
Lease operating		49,605				54,219				72,132					19,941
Transportation and processing		—				—				9,503					2,034
Production taxes		13,290				13,150				11,750					2,417
Depreciation, depletion and amortization		109,633				87,888				92,599					24,915
Impairment of oil and gas assets		430,695				20,065				42,146					—
Impairment of other assets		7,188				—				179					—
General and administrative		34,210				38,793				39,617					6,843
Cost reduction initiatives		—				1,034				691					629
Other		1,075				2,036				3,728					—
Total costs and expenses		645,696				217,185				272,345					56,779
Operating (loss) income		(409,351		)		30,177				(45,266		)			9,752
Non-operating (expense) income:
Interest expense		(22,666		)		(11,383		)		(14,147		)			(5,862		)
Loss on extinguishment of debt		(1,624		)		—				(635		)			—
Derivative (losses) gains		(33,198		)		19,297				(30,802		)			48,006
(Loss) gain on sale of assets		(6		)		(2,582		)		(25,996		)			206
Other (loss) income, net		(350		)		248				686					1,167
Net non-operating (expense) income		(57,844		)		5,580				(70,894		)			43,517
Reorganization items, net		(1,753		)		(2,392		)		(3,091		)			988,727
(Loss) income before income taxes		(468,948		)		33,365				(119,251		)			1,041,996
Income tax (benefit) expense		—				(77		)		(349		)			37
Net (loss) income		$	(468,948	)		$	33,442			$	(118,902	)			$	1,041,959
Earnings per share:
Basic for Class A and Class B (1)		$	(10.28	)		$	0.74			$	(2.64	)			*
Diluted for Class A and Class B (1)		$	(10.28	)		$	0.73			$	(2.64	)			*
Weighted average shares used to compute earnings per share:
Basic for Class A and Class B (1)		45,637,338				45,288,980				44,984,046					*
Diluted for Class A and Class B (1)		45,637,338				45,730,171				44,984,046					*

 ____________________________________________________________

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

 (1) See “Note 2: Earnings per share.”

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity (deficit)

		Common stock outstanding							Additional paid in capital				Treasury stock				Accumulated deficit				Total
(in thousands, except share data)		Shares			Amount
Balance at January 1, 2017 - Predecessor		1,392,706			14				425,231				—				(1,467,398		)		(1,042,153		)
Restricted stock forfeited		(1,454	)		—				—				—				—				—
Restricted stock canceled		(8,964	)		—				—				—				—				—
Stock-based compensation		—			—				194				—				—				194
Net income		—			—				—				—				1,041,959				1,041,959
Balance at March 21, 2017 - Predecessor		1,382,288			14				425,425				—				(425,439		)		—
Cancellation of Predecessor equity		(1,382,288	)		(14		)		(425,425		)		—				425,439				—
Balance at March 21, 2017 - Predecessor		—			$	—			$	—			$	—			$	—			$	—
Issuance of Successor common stock - rights offering		4,197,210			$	42			$	49,985			$	—			$	—			$	50,027
Issuance of Successor common stock - backstop premium		367,030			4				—				—				—				4
Issuance of Successor common stock - settlement of claims		40,417,902			404				898,510				—				—				898,914
Issuance of Successor warrants		—			—				118				—				—				118
Balance at March 21, 2017 - Successor		44,982,142			450				948,613				—				—				949,063
Stock-based compensation		1,853,236			18				12,587				—				—				12,605
Restricted stock canceled		(7,616	)		—				—				—				—				—
Net loss		—			—				—				—				(118,902		)		(118,902		)
Balance at December 31, 2017 - Successor		46,827,762			$	468			$	961,200			$	—			$	(118,902	)		$	842,766
Stock-based compensation		55,600			1				13,416				—				—				13,417
Restricted stock forfeited		(231,746	)		(2		)		—				—				—				(2		)
Repurchase of common stock		(261,103	)		—				—				(4,936		)		—				(4,936		)
Net income		—			—				—				—				33,442				33,442
Balance at December 31, 2018 - Successor		46,390,513			$	467			$	974,616			$	(4,936	)		$	(85,460	)		$	884,687
Stock-based compensation		2,002,173			20				2,245				—				—				2,265
Restricted stock forfeited		(316,821	)		(3		)		—				—				—				(3		)
Repurchase of common stock		(209,852	)		—				—				(1,174		)		—				(1,174		)
Issuance of common stock - litigation settlement		76,217			1				323				—				—				324
Cash settlement of stock based awards		—			—				(10		)		—				—				(10		)
Net loss		—			—				—				—				(468,948		)		(468,948		)
Balance at December 31, 2019 - Successor		47,942,230			$	485			$	977,174			$	(6,110	)		$	(554,408	)		$	417,141

 

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

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Consolidated statements of cash flows

						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
Cash flows from operating activities
Net (loss) income		$	(468,948	)		$	33,442			$	(118,902	)			$	1,041,959
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Non-cash reorganization items		—				—				—					(1,012,090		)
Depreciation, depletion and amortization		109,633				87,888				92,599					24,915
Impairment of oil and gas assets		430,695				20,065				42,146
Impairment of other assets		7,188				—				179					—
Derivative losses (gains)		33,198				(19,297		)		30,802					(48,006		)
Loss (gain) on sale of assets		6				2,582				25,996					(206		)
Loss on extinguishment of debt		1,624				—				635					—
Other		2,850				5,470				1,573					645
Change in assets and liabilities:
Accounts receivable		14,040				(6,337		)		(12,092		)			198
Inventories		393				236				(489		)			466
Prepaid expenses and other assets		(867		)		(160		)		3,245					(497		)
Accounts payable and accrued liabilities		(13,114		)		3,441				2,622					8,733
Revenue distribution payable		(3,855		)		8,649				6,941					(1,875		)
Deferred compensation		814				10,262				9,714					143
Net cash provided by operating activities		113,657				146,241				84,969					14,385
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties		(267,068		)		(324,063		)		(157,718		)			(31,179		)
Proceeds from asset dispositions		14,667				50,523				189,735					1,884
Proceeds from (payments for) derivative instruments		7,567				(18,510		)		15,676					1,285
Cash in escrow		—				—				42					—
Net cash (used in) provided by investing activities		(244,834		)		(292,050		)		47,735					(28,010		)
Cash flows from financing activities
Proceeds from long-term debt		130,000				116,000				33,000					270,000
Repayment of long-term debt		(8,744		)		(243,722		)		(176,407		)			(444,785		)
Issuance of Senior Notes		—				300,000				—					—
Proceeds from rights offering, net		—				—				—					50,031
Principal payments under financing lease obligations		(2,102		)		(2,683		)		(2,017		)			(568		)
Debt extinguishment costs		(1,624		)		—				—					—
Cash settlement of stock based awards		(10		)		—				—					—
Payment of debt issuance costs and other financing fees		(20		)		(9,136		)		(4,671		)			—
Treasury stock purchased		(1,174		)		(4,936		)		—					(2,410		)
Net cash provided by (used in) financing activities		116,326				155,523				(150,095		)			(127,732		)
Net (decrease) increase in cash and cash equivalents		(14,851		)		9,714				(17,391		)			(141,357		)
Cash and cash equivalents at beginning of period		37,446				27,732				45,123					186,480
Cash and cash equivalents at end of period		$	22,595			$	37,446			$	27,732				$	45,123

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

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

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

Principles of consolidation

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

Use of estimates

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

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

Reclassifications

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

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2019, cash with a recorded balance totaling $22,057 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

 

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Accounts receivable

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

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

		December 31, 2019				December 31, 2018
Joint interests		$	16,664			$	31,573
Accrued commodity sales		30,819				30,287
Derivative settlements		717				2,092
Other		2,544				3,375
Allowance for doubtful accounts		(1,097		)		(1,240		)
		$	49,647			$	66,087

Inventories

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

		December 31, 2019				December 31, 2018
Equipment inventory		$	3,435			$	3,663
Commodities		474				574
Inventory valuation allowance		(179		)		(178		)
		$	3,730			$	4,059

We recorded lower of cost or net realizable value adjustments of $179 for the period from March 22, 2017 to December 31, 2017 due to depressed industry conditions which resulted in lower demand for such equipment and hence lower market prices, as well as obsolescence. These adjustments are reflected in “Impairment of other assets” in our consolidated statements of operations.

Oil and natural gas properties

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

Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. Quarterly, unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of a dry or uneconomic

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

well. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. The impairment assessment is conducted at least once annually and whenever there are indicators that impairment has occurred. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase or we may incur ceiling test write-downs if costs are transferred to the amortization base without any associated reserves.

In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of the application of fresh start accounting on the Effective Date, a substantial portion of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our STACK play (see “Note 4: Fresh start accounting”). See “Note 19: Oil and natural gas activities (unaudited)” for further details of our unevaluated oil and natural gas properties.

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

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

Our estimates of oil and natural gas reserves as of December 31, 2019, 2018 and 2017 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC. As discussed in “Note 4: Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the carrying value of our oil and natural gas properties being restated based on their estimated fair value at the time.

We recorded ceiling adjustments to the oil and natural gas properties, for the periods disclosed below. The loss is reflected in “Impairment of oil and gas assets” in our consolidated statements of operations.

		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
Ceiling test impairment		$	430,695			$	20,065			$	42,146				$	—

Impairment of long-lived assets

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

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

During 2019, we recognized an impairment loss of $6,407 on the building and adjacent land housing our headquarters prior to its sale during the third quarter of 2019. See “Note 7: Property and equipment” for a discussion of the building sale.

Held for sale. In an effort to further streamline operations, during the fourth quarter of 2019, the Company began transitioning from an internally staffed and resourced oilfield services function to a third party provider solution. As a result, it began to actively market all related company-owned oilfield services machinery and equipment for eventual disposal. Accounting guidance requires us to reflect the disposal group on the balance sheet as “Assets held for sale” at carrying value or fair value less cost to sell, whichever is less. As a result of determining fair value on the assets held for sale, an impairment loss was recorded for the year ended December 31, 2019 in the amount of $781 which was included in the “Impairment of other assets” in the Statements of Operations.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Income taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in results of operations in the period the rate change is enacted.

We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at December 31, 2019, or December 31, 2018.

We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2011 through 2019 tax years generally remain subject to examination by federal and state tax authorities.

Derivative transactions

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

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

Fair value measurements

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

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

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Asset retirement obligations

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

Environmental liabilities

We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2019 and 2018, we have not accrued for or been fined or cited for any environmental violations that would have a material adverse effect upon our financial position, operating results, or cash flows.

Revenue recognition

Beginning in 2018, we adopted new authoritative guidance that supersedes previous revenue recognition requirements. The guidance requires that we identify the performance obligations, under our sales agreements, which is for the delivery of crude oil, natural gas or NGLs, and to recognize revenue when those obligations are satisfied, which occurs when control of the commodity is transferred to the purchaser. Furthermore, any costs and fees levied by the customer subsequent to the transfer of control will be recognized as a reduction in revenue. See “Note 16: Revenue recognition” for additional information regarding our revenue recognition.

Stock-based compensation

Our deferred compensation plan currently consists of restricted stock awards (“RSAs”) or restricted stock units (“RSUs”). Currently outstanding RSAs and RSUs are subject to either service-based vesting conditions or market-based vesting conditions. The RSAs and RSUs are generally classified as equity-based awards with the exception of awards that contractually specify settlement in cash or have a prior history of cash settlement, which are classified as liability-based awards. Compensation cost for service-based awards is recognized and measured based on fair value as determined by the market price of our publicly traded common stock, while the fair value computation used to determine compensation cost for market-based awards incorporates the probability of vesting.

Service-based awards either vest in one year and are expensed over that time frame or are subject to a graded vesting schedule over three annual installments where expense is recognized under the accelerated method. Market-based awards vest in three tranches over three annual measurement periods according to our stock price performance relative to a group of peer companies. The market conditions for a given year are unique to that year, and vesting with respect to conditions for a given year is independent of the vesting with respect to other years. As a result, the requisite service period for each of the three tranches of the market-based awards relate to the individual annual period for which stock return performance is measured and do not overlap. Market-based awards are expensed based on the fair value of the award that incorporates the probability of vesting and estimated by Monte Carlo simulation. Since the probability of vesting an award with a market condition is embedded in its fair value, expense is recognized on the entire grant regardless of the number of shares that actually vest so long as the participant remains employed as of the vesting date. Market conditions have not been established for tranches with stock return measurement periods that begin in 2020 and 2021, hence a grant date for purposes of determining a measurement value had not been established and expense recognition has not commenced. As permitted by a recent accounting update, we do not recognize expense based on an estimate of forfeitures but rather recognize the impact of forfeitures only as they occur.

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Other expense

Other expense consisted of the following:

		Successor
										Period from
										March 22, 2017
		For the Year Ended December 31,								through
		2019				2018				December 31, 2017
Restructuring		$	—			$	425			$	3,531
Subleases		1,075				1,611				197
Total other expense		$	1,075			$	2,036			$	3,728

Restructuring. We consider our EOR asset divestiture in November 2017 (see “Note 6: Acquisitions and divestitures”) to be an exit activity that qualifies as a restructuring in that it materially changed the scope and manner in which our business is conducted.  The restructuring expense related to the divestiture predominantly consist of one-time severance and termination benefits for the affected employees. The expense recorded in 2018 is a result of termination benefits for the final slate of employees terminated as a result of the divestiture.  

Subleases. Our subleases consisted of CO₂ compressors that were utilized in our former EOR operations and leased as both financing and operating leases from U.S. Bank but subsequently subleased to the purchaser of our EOR assets. Minimum payments under the subleases were equal to the original leases. Prior to the EOR divestiture, the financing leases were included in our full cost amortization base and hence subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating” expense on our statement of operations. Subsequent to the execution of the subleases, all payments received from the Sublessee were reflected as “Sublease revenue” on our statement of operations. Minimum payments made to U.S. Bank on the original operating leases were reflected as “Other” expense on our statement of operations, which we disclose in the table above. With respect to the financing leases, upon executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and amortized the asset on a straight line basis prospectively while continuing to incur interest expense. Please see “Note 17: Leases” for our disclosure on leases. In September 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to the originating leases and to the subleases including a $9,832 reduction in debt.

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, ranging from $3,400 to $4,000 per gross well. 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. In exchange, BCE received 85% of our original working interest in each well (on a wellbore-only basis), with the Company retaining 15% of our original interests until the program reaches a 14% internal rate of return. If this 14% threshold is achieved, ownership interest in all wells would shift such that we would own 75% of our original working interests and BCE would retain 25% of our original working interests. 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 under the JDA.

Our drilling and completion costs exceeded the well cost caps specified under the JDA primarily due to inflation in the cost of oilfield services since entering into the JDA. We have therefore recorded additions to oil and natural gas properties of $4,061 and $13,212 during the years ended December 31, 2019 and 2018, respectively, in cumulative drilling and completion costs on JDA wells that have exceeded the well cost caps specified under the JDA. Since we have achieved our goals to utilize the JDA as a means to delineate our acreage in Garfield and Canadian counties, Oklahoma, we do not currently plan to extend or expand the JDA.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Cost reduction initiatives

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

		Successor									Predecessor
						Period from					Period from
		For the Year				March 22, 2017					January 1, 2017
		Ended December 31,				through					through
		2018				December 31, 2017					March 21, 2017
One-time severance and termination benefits		$	1,034			$	678				$	608
Professional fees		$	—			13					21
Total cost reduction initiatives expense		$	1,034			$	691				$	629

Recently adopted accounting pronouncements

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Please see “Note 16: Revenue recognition” for our disclosure regarding adoption of this update.

In January 2017, the FASB issued authoritative guidance that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described under updated revenue recognition guidance. The guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. We adopted this update effective January 1, 2018, without a material impact to our financial statements. We expect that the new guidance, when applied to the facts and circumstances of a future transaction, may impact the likelihood whether a future transaction would be accounted for as a business combination.

In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations.

In August 2016, the FASB issued authoritative guidance that provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable. We adopted this update effective January 1, 2018, without a material impact on our financial statements or results of operations.

In November 2016, the FASB issued authoritative guidance requiring that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and should be

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

applied using a retrospective transition method to each period presented. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations.

In May 2017, the FASB issued authoritative guidance that provides clarification on determining which changes to the terms and conditions of share-based payment awards require an entity to apply modification accounting. The guidance is effective for fiscal years, including interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted in any interim period. The guidance should be applied prospectively to an award modified on or after the adoption date. We adopted this guidance effective January 1, 2018, with no material impact to our financial statements or results of operations.

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

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

In February 2016, the FASB established ASC Topic 842, Leases (“ASC 842”) that requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 was subsequently amended by Accounting Standards Update (“ASU”) No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. Please see “Note 17: Leases” for our disclosure regarding adoption of this update.

Recently issued accounting pronouncements

In June 2016, the FASB issued authoritative guidance that modifies the measurement of expected credit losses of certain financial instruments. The guidance is effective for fiscal years beginning after December 15, 2019 for public business entities with the exception of small reporting companies, which have a later adoption date. Early adoption is permitted for fiscal years beginning after December 15, 2018. The updated guidance impacts our financial statements primarily due to its effect on our accounts receivables. Our history of accounts receivable credit losses almost entirely relates to receivables from joint interest owners in our operated oil and natural gas wells. Based on this history and on mitigating actions, we are permitted to take to offset potential losses such as netting past due amounts against revenue and assuming title to the working interest. We do not expect this guidance to materially impact our financial statements or results of operations.

In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminates certain exceptions in the existing guidance related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard is effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company is in the process of evaluating the new standard and is unable to estimate its financial impact, if any, at this time.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 2: Earnings per share

Prior to our emergence from bankruptcy, we did not present earnings per share (“EPS”) in our financial statements because our common stock did not previously trade on a public market, either on a stock exchange or in the over-the-counter (“OTC”) market. Accordingly, we were permitted under accounting guidance to omit such disclosure. Subsequent to our emergence from bankruptcy, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP” from May 18, 2017, through May 25, 2017. From May 26, 2017, through July 23, 2018, our Class A common stock was quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. Our Class A common stock is currently trading on the NYSE under the symbol “CHAP” upon our listing on that exchange on July 24, 2018. Our Class B common stock was not listed or quoted on the OTCQB or any other national exchange; however, on December 19, 2018, all outstanding shares of our Class B common stock converted into the same number of shares of Class A common stock. With the conversion, all our common stock is now traded on the NYSE. Our Class A and previous Class B common stock shared equally in dividends and undistributed earnings. We are presenting basic and diluted EPS for all Successor periods subsequent to our emergence from bankruptcy but are not presenting EPS for any Predecessor period.

We are required under accounting guidance to compute EPS using the two-class method that considers multiple classes of common stock and participating securities. All securities that meet the definition of a participating security are to be included in the computation of basic EPS under the two-class method.

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

						Successor
										Period from
										March 22, 2017
		For the Year Ended December 31,								through
(in thousands, except share and per share data)		2019				2018				December 31, 2017
Numerator for basic and diluted earnings per share
Net (loss) income		$	(468,948	)		$	33,442			$	(118,902	)
Denominator for basic earnings per share
Weighted average common shares - Basic for Class A and Class B (1)		45,637,338				45,288,980				44,984,046
Effect of dilutive securities
Dilutive shares from equity compensation awards		—				441,191				—
Denominator for diluted earnings per share
Weighted average common shares - Diluted for Class A and Class B (1)		45,637,338				45,730,171				44,984,046
Earnings (loss) per share
Basic for Class A and Class B (1)		$	(10.28	)		$	0.74			$	(2.64	)
Diluted for Class A and Class B (1)		$	(10.28	)		$	0.73			$	(2.64	)
Securities excluded from earnings per share calculations
Unvested restricted stock awards or units at period end		3,187,231				125,323				1,833,136
Warrants (2)		—				—				140,023

____________________________________________________________

(1)	Effective December 19, 2018, Class B shares were converted to Class A shares.

(2)

The warrants to purchase shares of our Class A common stock are antidilutive for the period from March 22 to December 31, 2017, due to the exercise price exceeding the average price of our Class A shares and due to the net loss we incurred. These warrants expired on June 30, 2018. They were antidilutive during the first and second quarter of 2018 due to the exercise price exceeding the average price of our Class A shares and hence are omitted from diluted earnings per share for the year ended December 31, 2018.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 3: Chapter 11 reorganization

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

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

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

•

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

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

•

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

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

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

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

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

•

Pursuant to our Reorganization Plan, on January 5, 2017, we entered into the Retirement Agreement and General Release (the “Retirement Agreement”) with Mr. Fischer, whereupon Mr. Fischer terminated his employment with the Company on that date. The Retirement Agreement included severance consisting of cash and certain tangible assets in the amount of $4,038. Mr. Fisher provided consulting services to the Company during the period subsequent to his termination until the Effective Date for which he received the warrants disclosed above. The expense for Mr. Fischer’s severance and consulting services are reflected in “Reorganization items, net” and “General and administrative” expense, respectively, in our consolidated statement of operations during the 2017 Predecessor period. All amounts due to Mr. Fischer pursuant to the Retirement Agreement were paid as of December 31, 2017.

•

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

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

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

•	Plaintiffs to one of our royalty owner litigation cases, which were identified as a separate class of creditors (Class 8) in our bankruptcy case, rejected the Reorganization Plan. If the claimants under Class 8 are permitted to file a class of proof claim on

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

behalf of the putative class, certified on a class basis, and the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgement or settlement of the claims that relate to the pre-petition period would be satisfied through issuance of Successor common shares.

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

		Predecessor
		March 21, 2017
Accounts payable and accrued liabilities		$	6,687
Accrued payroll and benefits payable		3,949
Revenue distribution payable		3,050
Prior Senior Notes and associated accrued interest		1,267,410
Liabilities subject to compromise		$	1,281,096

 

Note 4: Fresh start accounting

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

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

Enterprise Value and Reorganization Value

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

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

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

____________________________________________________________

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

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

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

Valuation of oil and gas properties

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

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

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

Other valuations

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

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

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

Consolidated balance sheet

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

 

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Reorganization adjustments

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

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

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

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

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

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

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

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

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

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

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

 

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

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

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

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

Fresh start adjustments

(i)

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

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

Reorganization items

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

						Successor									Predecessor
										Period from					Period from
										March 22, 2017					January 1, 2017
		For the Year Ended December 31,								through					through
		2019				2018				December 31, 2017					March 21, 2017
Loss (gain) on the settlement of liabilities subject to compromise		$	—			$	48			$	—				$	(372,093	)
Fresh start accounting adjustments		—				—				—					(641,684		)
Professional fees		1,753				2,344				3,091					18,790
Rejection of employment contracts		—				—				—					4,573
Write off unamortized issuance costs on Prior Credit Facility		—				—				—					1,687
Total reorganization items		$	1,753			$	2,392			$	3,091				$	(988,727	)

 

94

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

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

						Successor									Predecessor
										Period from					Period from
										March 22, 2017					January 1, 2017
		For the Year Ended December 31,								through					through
		2019				2018				December 31, 2017					March 21, 2017
Net cash provided by operating activities included:
Cash payments for interest		$	32,465			$	6,266			$	17,195				$	4,105
Interest capitalized		(11,796		)		(10,925		)		(2,142		)			(248		)
Cash payments for income taxes		—				—				150					—
Cash payments for reorganization items		1,395				2,506				18,006					11,405
Non-cash investing activities included:
Asset retirement obligation additions and revisions		836				3,141				6,746					716
Oil and gas leasehold exchanges		1,399				10,913				816					—
Change in accrued oil and gas capital expenditures		3,630				6,559				9,534					5,387
Non-cash financing activities included:
Discharge of financing lease obligations (See Note 17)		9,832				—				—					—

 

Note 6: Acquisitions and divestitures

2019 Acquisitions and divestitures

For 2019, we did not enter into any material divestitures of oil and gas assets. During the year, we incurred $23,107 in acquisition costs, which consisted primarily of leasing and pooling of acreage and capitalized interest.

2018 Acquisitions and divestitures

For 2018, we received total cash proceeds of $50,523 on various non-core oil and gas assets, property and equipment disposals. Included in these disposals were:

•	A divestiture of certain properties in the Oklahoma/Texas Panhandle for gross cash proceeds before selling costs of $17,000 and the conveyance of $629 in liabilities to the buyer, all of which are subject to customary post-close adjustments. The purchaser of these assets is a company affiliated with Mark A. Fischer, our former Chief Executive Officer and former Chairman of the Board.

•	A divestiture of certain saltwater disposal infrastructure where we received proceeds of $11,841. In conjunction with this divestiture, we entered into a service agreement for salt water disposal with the purchaser of these assets, as discussed further below.

•	Disposals of various other non-core assets resulting in proceeds of approximately $22,637.

As the properties above did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, no gain or loss was recognized on these disposals and instead, we reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

In conjunction with our divestiture of saltwater disposal infrastructure discussed above, we entered into service agreements with two providers to dispose, via pipeline or truck, salt water produced by our wells within areas that encompass Kingfisher, Garfield and Canadian Counties, Oklahoma. The agreements covering Kingfisher and Garfield Counties, Oklahoma are for 15 years and specify fixed rates per barrel according to age of the well. The agreement covering Canadian County, Oklahoma is for 5 years and specifies per barrel rates that vary according to volume of water disposed.

During 2018, we incurred acquisition costs of $122,309. The amount includes costs to acquire approximately 24,600 acres of leasehold, capitalized interest of $10,925 and $10,913 in non-monetary acreage trades.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

2017 Acquisitions and divestitures

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

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

In December 2017, we entered into purchase and sale agreements to acquire acreage in the STACK play in Kingfisher County, Oklahoma. In early January 2018, immediately prior to closing the purchase, we amended the transaction to include additional acreage. The final purchase closed for $60,643 encompassing 7,000 acres. Under the terms of the agreements, the Company is required to drill and complete 10 wells on such leasehold in each of 2019, 2020, and 2021 and 15 wells in 2022. To the extent the company does not drill and complete the minimum number of wells in a given year, it is required to pay the sellers of the acreage $250 for each deficient well. Taking into account current commodity price conditions, the company does not intend to drill wells on the subject acreage in 2020 as it focuses on higher return opportunities. No determination has been made with respect to 2021 or 2022; however, if the company fails to drill the prescribed number of wells in either year, it would be obligated to make additional payments to the sellers.

Note 7: Property and equipment

Major classes of property and equipment are shown in the following table. As discussed in “Note 4: Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in restating our property and equipment to fair value, thus resetting the accumulated depreciation and amortization balance. Property acquired since that date is capitalized and stated at cost. Maintenance and repairs are expensed currently.

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

	Useful Life		December 31, 2019				December 31, 2018
Furniture and fixtures	10		$	8			$	520
Automobiles and trucks	5		3,071				3,548
Machinery and equipment	10 — 20 years		3,543				21,482
Office and computer equipment	5 — 10 years		3,363				6,183
Building and improvements	10 — 40 years		693				18,693
			10,678				50,426
Less accumulated depreciation and amortization			3,459				12,449
			7,219				37,977
Land			1,998				5,119
			$	9,217			$	43,096

 

Impairment of headquarters building and subsequent sales. During the second quarter of 2019, we commenced efforts to locate a buyer for our headquarters building. In conjunction with these efforts, we obtained a third party valuation on the fair value of the property. The valuation appraised the property at an amount lower than its net book value at the time. Based on this market appraisal and our expectations that, more likely than not, the headquarters building would be sold before the end of its useful life, we determined that the net book value of the property would not be recoverable. As a result, we recorded an impairment of $6,407 in June 2019 to write-down the net book value of the property to its fair value based on its market appraisal.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

On August 5, 2019, we entered into a real estate purchase and sale agreement for the sale of the building housing our headquarters along with adjacent land, furniture and fixtures. We closed the sale on August 29, 2019, for net proceeds of $11,494 while recognizing an immaterial loss on disposal. The proceeds from the sale were utilized to pay off the outstanding balance of the real estate mortgage note on the property. We incurred a prepayment penalty of $1,624 on the early payoff of the note, which we recorded as a “Loss on extinguishment of debt” on our consolidated statements of operations. Conditioned upon closing of this sale, we entered into a leaseback agreement with the buyer for a portion of the office space, which we discuss in “Note 17: Leases.”

Held for sale. In an effort to further streamline operations, during the fourth quarter of 2019, the Company began transitioning from an internally staffed and resourced oilfield services function to a third party provider solution. As a result, it began to actively market all related company-owned oilfield services machinery and equipment for eventual disposal. Accounting guidance requires us to reflect the disposal group separately on the balance sheet as “Assets held for sale” at carrying value or fair value less cost to sell, whichever is less. The carrying value of assets held for sale is not included in the table above. As a result of determining fair value on the assets held for sale, an impairment loss was recorded for the year ended December 31, 2019 in the amount of $781, which was included in the “Impairment of other assets” in the Statements of Operations. Our held for sale assets as of December 31, 2019 consisted of:

		Carrying value at
		December 31, 2019
Equipment		$	1,572
Vehicles		488
Real estate		800
Total held for sale		$	2,860

Leased compressors. Our property and equipment balance as of December 31, 2018, included CO₂ compressors that were held under finance leases and simultaneously subleased to the buyer of our former EOR oil and natural gas properties. In September 2019, U.S. Bank, the originating lessor, entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to these compressor leases and the removal of those assets and elimination of associated debt from our consolidated balance sheet. 

Note 8: Debt

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

		December 31, 2019				December 31, 2018
Credit facility		$	130,000			$	—
Senior Notes		300,000				300,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at 5.50%, due December 2028; collateralized by real property		—				8,588
Installment notes payable, principal and interest payable monthly collateralized by personal property		371				354
Financing lease obligations		1,653				11,677
Unamortized issuance costs		(10,038		)		(13,148		)
Total debt, net		421,986				307,471
Less current portion		594				12,371
Total long-term debt, net		$	421,392			$	295,100

 

Maturities of long-term debt and capital leases, excluding unamortized debt issuance costs, are as follows as of December 31, 2019: 

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

2020	$	594
2021	540
2022	130,577
2023	300,260
2024	53
2025 and thereafter	—
	$	432,024

As discussed in “Note 7: Property and equipment,” upon the divestiture of our headquarters building in August 2019, we utilized the sale proceeds to pay off the outstanding balance of our real estate mortgage note which was $8,176 at the time of the repayment.

Our financing lease obligations as of December 31, 2018, included leases on CO₂ compressors that were subleased to the buyer of our former EOR oil and natural gas properties. In August 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to these compressor leases and the removal of the associated debt from our consolidated balance sheet in the amount of $9,832. Our remaining finance leases consist primarily of leases on our fleet vehicles.

Credit Agreement

Pursuant to our Credit Agreement (the “Credit Agreement”) with Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto, we have a $750,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our Credit Agreement is subject to the financial covenants discussed below and a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. Our borrowing base under the Credit Agreement as of December 31, 2019, was $325,000 while the unused portion on that date was $195,000.

Interest on the outstanding amounts under the credit facility will accrue at an interest rate equal to either (i) the Alternate Base Rate (as defined in the Credit Agreement) plus an Applicable Margin (as defined in the Credit Agreement) that ranges between 1.00% to 2.00% depending on utilization or (ii) the Adjusted LIBO Rate (as defined in the Credit Agreement) applicable to one, two, three, or six month borrowings plus an Applicable Margin that ranges between 2.00% to 3.00% depending on utilization. In the case that an Event of Default (as defined under the Credit Agreement) occurs, the outstanding amounts will bear an additional 2.00% interest plus the applicable Alternate Base Rate or Adjusted LIBO Rate and corresponding Applicable Margin.

As of December 31, 2019, our outstanding borrowings were accruing interest at the Adjusted LIBO Rate (as defined in the Credit Agreement, as defined below), plus the Applicable Margin (as defined in the Credit Agreement), which resulted in a weighted average interest rate of 4.03% on the amount outstanding.

Commitment fees that range between 0.375% and 0.500%, depending on utilization, accrue on the average daily amount of the unused portion of the borrowing base and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the Applicable Margin used to determine the interest rate applicable to borrowings that are based on Adjusted LIBO Rate.

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

On May 2, 2019, we entered into the Third Amendment (the “Third Amendment”) to the Credit Agreement. The Third Amendment, which was effective March 31, 2019, among other things, (i) reaffirmed the borrowing base at $325,000 and (ii) amended the definition of EBITDAX to add back certain severance and retirement payments, consulting fees, and related charges paid

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

or incurred in connection with any retirement, severance or departure of officers or former officers in an aggregate amount not to exceed $4,000.

On September 27, 2019, we entered into the Fourth Amendment (the “Fourth Amendment”) to the Credit Agreement. The Fourth Amendment, among other things, (i) reaffirmed the borrowing base at $325,000; (ii) amended the definition of EBITDAX to, among other things, (a) added back losses related to or resulting from the full or partial extinguishment of debt, (b) expanded the add-back of amounts associated with retirements, severance or departure to apply to all employees or former employees, and (c) clarified that gains related to or resulting from the full or partial extinguishment of debt are excluded; and (iii) revised certain negative covenants to provide that the Company, under certain circumstances, may prepay or otherwise redeem certain Permitted Senior Additional Debt (as defined in the Credit Agreement) in an aggregate amount not to exceed $30,000.

Other Provisions

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

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

The financial covenants require, for each fiscal quarter, that we maintain: (1) a Current Ratio (as defined in the Credit Agreement) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the Credit Agreement) of no greater than 4.0 to 1.0 calculated on a trailing four-quarter basis. We were in compliance with these financial covenants as of December 31, 2019.

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

Senior Notes

On June 29, 2018, we completed the issuance and sale at par of $300,000 in aggregate principal amount of our Senior Notes in a private placement under Rule 144A and Regulation S of the Securities Act of 1933, as amended. The offering costs were $7,337 resulting in net proceeds of $292,663, which we used to repay the outstanding balance on our credit facility at that time and for general corporate purposes.

The Senior Notes bear interest at a rate of 8.75% per year beginning June 29, 2018 (payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2019) and will mature on July 15, 2023.

The Senior Notes are the Company’s senior unsecured obligations and rank equal in right of payment with all of the Company’s existing and future senior indebtedness, senior to all of the Company’s existing and future subordinated indebtedness and effectively subordinated to all of the Company’s existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The Indenture for our Senior Notes contains certain covenants, which limit our ability to:

•incur additional indebtedness or issue certain preferred stock;

•pay dividends or repurchase or redeem capital stock;

•make certain investments;

•incur certain liens;

•enter into certain types of transactions with affiliates;

•sell assets;

•enter into agreements restricting our ability to pay dividends or make other payments;

•consolidate, merge, sell, or otherwise dispose of all or substantially all of our assets; and

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

•create unrestricted subsidiaries.

These limitations are subject to a number of important qualifications and exceptions.

Prior to July 15, 2020, the Company may, at its option, redeem all or, from time to time, a part of the Senior Notes at a redemption price equal to 100% of the principal amount thereof, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. On or after July 15, 2020, the Company may, at its option, redeem all or, from time to time, a part of the Senior Notes at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest, if any, to the date of redemption.

Prior to July 15, 2020, the Company, at its option, may redeem up to 35% of the aggregate principal amount of the Senior Notes with proceeds of one or more qualified equity offerings at a redemption price of 108.75% of the principal amount of the Senior Notes redeemed, plus accrued and unpaid interest, if any, and liquidated damages provided that:

1.	at least 60% of the aggregate principal amount of the Senior Notes issued under the Indenture remains outstanding after each such redemption; and

2.	such redemption occurs within 180 days after the closing of any such qualified equity offering

Upon an Event of Default (as defined in the Indenture), the trustee under the Indenture or the holders of at least 25% in aggregate principal amount of the outstanding Senior Notes may declare the entire principal of, premium, if any, and accrued and unpaid interest, if any, on all the Senior Notes to be due and payable immediately.

If the Company experiences certain kinds of changes of control, holders of the Senior Notes will be entitled to require the Company to purchase all or a portion of the Senior Notes at 101% of their principal amount, plus accrued and unpaid interest.

Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries.

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

Note 9: Derivative instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas and natural gas liquids. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, which in the past have included commodity price swaps, collars, put options and basis protection swaps. During 2018, we also entered into additional derivative contracts to hedge our exposure to the WTI NYMEX calendar month average roll (“oil roll”), which is a contractual component of our crude oil sales prices.

As of December 31, 2019, our derivatives consisted of commodity price swaps (including basis and oil roll) and collars. See “Note 1: Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for derivative transactions.

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

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

100

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

The following table summarizes our crude oil derivatives outstanding as of December 31, 2019:

		Volume			Weighted average fixed price per Bbl
Period and type of contract		MBbls			Swaps				Purchase puts				Sold calls
2020
Oil swaps		2,274			$	51.01			$	—			$	—
Oil collars		195			$	—			$	55.00			$	66.42
Oil roll swaps		410			$	0.38			$	—			$	—
2021
Oil swaps		689			$	46.24			$	—			$	—
Oil roll swaps		150			$	0.30			$	—			$	—

    

The following table summarizes our natural gas derivative instruments outstanding as of December 31, 2019:

					Weighted average fixed price per MMBtu
Period and type of contract		Volume BBtu			Swaps
2020
Natural gas swaps		7,680			$	2.71
Natural gas basis swaps		7,080			$	(0.46	)

The following table summarizes our natural gas liquids derivative instruments outstanding as of December 31, 2019:

		Volume			Weighted average fixed price per gallon
Period and type of contract		Gallons			Swaps
2020
Butane		2,849			$	0.68
Natural gasoline swaps		6,508			$	1.15
Propane swaps		14,872			$	0.57

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

Effect of derivative instruments on the consolidated balance sheets

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

101

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

		As of December 31, 2019												As of December 31, 2018
		Assets				Liabilities				Net value				Assets				Liabilities				Net value
Natural gas derivative contracts		$	3,552			$	(1	)		$	3,551			$	833			$	(488	)		$	345
NGL derivative contracts		2,868				(699		)		2,169				4,581				—				4,581
Crude oil derivative contracts		391				(22,196		)		(21,805		)		24,208				(4,452		)		19,756
Total derivative instruments		6,811				(22,896		)		(16,085		)		29,622				(4,940		)		24,682
Less:
Netting adjustments (1)		(5,864		)		5,864				—				(3,398		)		3,398				—
Derivative instruments - current		947				(11,957		)		(11,010		)		24,025				—				24,025
Derivative instruments - long-term		$	—			$	(5,075	)		$	(5,075	)		$	2,199			$	(1,542	)		$	657

 ____________________________________________________________

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

Effect of derivative instruments on the consolidated statements of operations

We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Derivative (losses) gains” in the consolidated statements of operations.

“Derivative (losses) gains” in the consolidated statements of operations consists of the following:

		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
Change in fair value of commodity price derivatives		$	(40,765	)		$	37,807			$	(46,478	)			$	46,721
Settlement gains (losses) on commodity price derivatives		7,567				(18,510		)		15,676					1,285
Derivative (losses) gains		$	(33,198	)		$	19,297			$	(30,802	)			$	48,006

 

Note 10: Fair value measurements

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see “Note 9: Derivative instruments”). We had no Level 1 assets or liabilities as of December 31, 2019 or December 31, 2018. Our derivative contracts classified as Level 2 as of December 31, 2019 and 2018 consisted of commodity price swaps, including our oil roll contracts, which are valued using an income approach. Future cash flows from these derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at a rate that captures our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.

As of December 31, 2019 and 2018 our derivative contracts classified as Level 3 consisted of collars and gas basis swaps. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or our counterparty credit risk for derivative assets.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

		As of December 31, 2019												As of December 31, 2018
		Derivative assets				Derivative liabilities				Net assets (liabilities)				Derivative assets				Derivative liabilities				Net assets (liabilities)
Significant other observable inputs (Level 2)		$	6,576			$	(22,895	)		$	(16,319	)		$	29,370			$	(4,718	)		$	24,652
Significant unobservable inputs (Level 3)		235				(1		)		234				252				(222		)		30
Netting adjustments (1)		(5,864		)		5,864				—				(3,398		)		3,398				—
		$	947			$	(17,032	)		$	(16,085	)		$	26,224			$	(1,542	)		$	24,682

____________________________________________________________ 

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

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

		For the Year Ended December 31,
Net derivative assets (liabilities)		2019				2018
Beginning balance		$	30			$	(295	)
Realized and unrealized gains (losses) included in derivative (losses) gains		1,009				(1,101		)
Settlements (received) paid		(805		)		1,426
Ending balance		$	234			$	30
Gains relating to instruments still held at the reporting date included in derivative (losses) gains for the period		$	234			$	30

Nonrecurring fair value measurements

Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. See “Note 11: Asset retirement obligations” for additional information regarding our asset retirement obligations. The table below discloses the inflation and discount rate assumptions for the periods presented:

		Year ended December 31,
		2019						2018
		Low			High			Low			High
Inflation rate (1)		2.25	%		2.25	%		2.26	%		2.26	%
Credit adjusted risk-free discount rate		12.35	%		21.79	%		6.92	%		11.94	%

__________________________________________

(1) The inflation rate is measured as a single rate on an annual basis.

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

The carrying value and estimated fair value of our debt at December 31, 2019 and 2018 were as follows:

 

		December 31, 2019								December 31, 2018
Level 2		Carrying value (1)				Estimated fair value				Carrying value (1)				Estimated fair value
Credit facility		$	130,000			$	130,000			$	—			$	—
Other secured debt (2)		371				371				8,942				8,942
8.75% Senior Notes due 2023		300,000				133,050				300,000				213,618

 ____________________________________________________________

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

(2)	The balance on December 31, 2019, consisted of only equipment installment notes while the balance on December 31, 2018, consisted of real estate and equipment installment notes.

The carrying value of our credit facility and other secured long-term debt approximates fair value as the rates are comparable to those at which we could currently borrow under similar terms, are variable and incorporate a measure of our credit risk. The fair value of our Senior Notes was estimated based on quoted market prices.

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

Concentrations of credit risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our credit facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties that provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a Lender, or an affiliate of a Lender, under our credit facilities can be offset against amounts owed to such counterparty Lender. As of December 31, 2019, the counterparties to our open derivative contracts consisted of eight financial institutions.

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

		Offset in the consolidated balance sheets												Gross amounts not offset in the consolidated balance sheets
		Gross assets (liabilities)				Offsetting  assets (liabilities)				Net assets (liabilities)				Derivatives (1)				Amounts outstanding under credit facilities (2)				Net amount
December 31, 2019
Derivative assets		$	6,811			$	(5,864	)		$	947			$	—			$	(947	)		$	—
Derivative liabilities		(22,896		)		5,864				(17,032		)		—				947				(16,085		)
		$	(16,085	)		$	—			$	(16,085	)		$	—			$	—			$	(16,085	)
December 31, 2018
Derivative assets		$	29,622			$	(3,398	)		$	26,224			$	(1,542	)		$	—			$	24,682
Derivative liabilities		(4,940		)		3,398				(1,542		)		$	1,542			—				—
		$	24,682			$	—			$	24,682			$	—			$	—			$	24,682

 ____________________________________________________________

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

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our credit facilities. Payment on our derivative contracts could be accelerated in the event of a default on our Credit Agreement. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $22,896 at December 31, 2019.

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

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

		Successor
		2019			2018			2017
Coffeyville Resources LLC		*			*			20.9	%
Phillips 66 Company		21.4	%		26.0	%		14.6	%
Sunoco, Inc.		15.1	%		7.2	%		*
Alta Mesa Resources, Inc.		*			6.7	%		*
Tom Stack LLC.		10.0	%		*			*
Valero Energy Corporation		*			*			13.3	%

 

____________________________________________________________

*    Not disclosed as not a top three purchaser during the fiscal year.

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

 

Note 11: Asset retirement obligations

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

 

Liability for asset retirement obligations as of January 1, 2018	$	35,990
Liabilities incurred in current period	689
Liabilities settled and disposed in current period	(17,868		)
Revisions in estimated cash flows	2,452
Accretion expense	1,884
Liability for asset retirement obligations as of December 31, 2018	$	23,147
Liabilities incurred in current period	448
Liabilities settled and disposed in current period	(2,305		)
Revisions in estimated cash flows	388
Accretion expense	1,478
Liability for asset retirement obligations as of December 31, 2019	$	23,156
Less current portion included in accounts payable and accrued liabilities	2,083
Asset retirement obligations, long-term	$	21,073

 

Liabilities incurred include obligations related to new wells drilled and wells acquired during the period. Liabilities settled and disposed in 2018 primarily relate to our oil and natural gas property divestitures discussed in “Note 6: Acquisitions and divestitures.”

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

 

Note 12: Income taxes

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

		Successor													Predecessor
										Period from					Period from
										March 22, 2017					January 1, 2017
		For the Year Ended December 31,								through					through
		2019				2018				December 31, 2017					March 21, 2017
Current income taxes
Federal		$	—			$	(77	)		$	(162	)			$	—
State		—				—				(187		)			37
Total current income taxes		—				(77		)		(349		)			37
Deferred income taxes
Federal		—				—				—					—
State		—				—				—					—
Total deferred income taxes		—				—				—					—
Income tax (benefit) expense		$	—			$	(77	)		$	(349	)			$	37

 

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

		Successor										Predecessor
								Period from				Period from
								March 22, 2017				January 1, 2017
		For the Year Ended December 31,						through				through
		2019			2018			December 31, 2017				March 21, 2017
Federal statutory rate		21.0	%		21.0	%		35.0	%			35.0	%
Remeasurement of deferred taxes—U.S. tax reform legislation		—	%		—	%		(94.7	)%			—	%
State remeasurement of deferred taxes		0.3	%		—	%		—	%			—	%
State income taxes, net of federal benefit		4.5	%		(0.1	)%		5.8	%			2.2	%
Statutory depletion		—	%		(0.4	)%		0.4	%			—	%
Valuation allowance		(25.0	)%		2.8	%		54.1	%			(25.9	)%
EOR tax credit		—	%		(25.9	)%		(8.4	)%			—	%
Return to provision adjustment		(0.6	)%		(1.7	)%		10.2	%			—	%
Other, net		(0.2	)%		4.1	%		(2.4	)%			(11.3	)%
Effective tax rate		—	%		(0.2	)%		—	%			—	%

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

		December 31, 2019				December 31, 2018
Deferred tax assets related to
Asset retirement obligations		$	8,500			$	10,013
Accrued expenses, allowance and other		2,254				2,264
Derivative instruments		4,095				—
Net operating loss carryforwards
Federal		258,388				242,070
State		69,100				66,575
Statutory depletion carryforwards		2,351				2,383
Enhanced oil recovery credit		18,758				18,758
Interest limitation		4,153				5,771
		367,599				347,834
Less valuation allowance		(336,123		)		(216,109		)
Deferred tax asset		31,476				131,725
Deferred tax liabilities related to
Property and equipment		(31,355		)		(125,224		)
Derivative instruments		—				(6,353		)
Inventories		(121		)		(148		)
Deferred tax liability		(31,476		)		(131,725		)
Net deferred tax liability		$	—			$	—

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

Due to continued tax losses, we maintained our deferred tax asset position at December 31, 2019. We believe that it is more likely than not that these deferred tax assets will not be realized and as such we are maintaining the full valuation allowance against our net deferred tax assets.

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

Net operating loss carryforwards. We have federal net operating loss carryforwards of approximately $1,230,419 at December 31, 2019, of which $1,011,368 will expire at various times between 2028 and 2037 if not utilized in earlier periods. However, because of the 2017 Tax Act, the estimated federal net operating loss of $219,051 generated in 2018 and 2019 does not expire but may only offset 80% of taxable income in any given year. At December 31, 2019, we have state net operating loss carryforwards of approximately $1,498,363, which will expire between 2020 and 2039 if not utilized in earlier periods. In addition, at December 31, 2019, we had federal percentage depletion carryforwards of approximately $11,194, which are not subject to expiration.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

IRC Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on March 21, 2017. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the March 21, 2017 ownership change on its tax attributes. Upon filing the 2017 U.S. Federal income tax return, the Company elected an available alternative which subjects existing tax attributes at emergence to an IRC Section 382 limitation that could result in some or all of the remaining net operating loss carryforwards expiring unused. Upon final determination of tax return amounts for the year ended December 31, 2017, including attribute reduction that occurred on January 1, 2018, the Company has total federal net operating loss carryforwards of $1,011,368 including $760,067 which are subject to limitation due to the ownership change that occurred upon emergence from bankruptcy and $251,301 of post-change net operating loss carryforwards not subject to this limitation. The limitation did not result in a current tax liability for the tax years ended December 31, 2017, 2018 and 2019.The Company has incurred additional net operating losses for the years ended December 31, 2018 and December 31, 2019 that are currently not subject to an IRC Section 382 limitation.

Note 13: Deferred compensation

Our deferred compensation includes cash awards and equity-based awards which are either settled in cash or in stock.

Cash Awards

From time to time, we have granted cash awards with long term vesting requirements. Our cash awards, which are generally service-based, vest either in one year, in annual increments over a three year period or in annual increments over a four year period. We accrue for the cost of each annual increment over the period that service is required to vest. A summary of compensation expense for our cash awards is presented below:

	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
Cash LTIP expense (net of amounts capitalized)	$	200			$	543			$	1,192				$	5
Cash LTIP grants (1)	1,300				174				5,637					—
Cash LTIP payments	955				1,183				1,285					42

(1)	All grants are service-based except for a market-condition grant of $263 to our new chief executive officer in December 2019.

As of December 31, 2019, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $854.

Equity Awards

The Company’s outstanding equity based awards have generally been granted under the 2017 Chaparral Energy, Inc. Management Incentive Plan (the “MIP”) and the Chaparral Energy, Inc. 2019 Long-Term Incentive Plan (the “LTIP”), which replaced the MIP in June 2019. Our equity grants have been in the form or RSAs or RSUs. In December 2019, we also granted equity awards in the form of RSAs to our recently appointed chief executive officer under an inducement equity grant that is exempted from the general requirement of the NYSE rules that require equity-based compensation plans and arrangements to be approved by stockholders. Even though the inducement grant was made outside of the LTIP, except as expressly provided otherwise in the grant agreement, the grant will be governed in a manner consistent with the terms and conditions of the LTIP.

The LTIP provides for the following types of awards: options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other incentive awards. The aggregate number of shares of Class A common stock, par value $0.01 per share, reserved for issuance under the LTIP when it became effective was 3,500,000 shares. Generally, and to the extent not provided otherwise in an award agreement, (i) in the event of a Change in Control (as defined in the LTIP) in which the acquiring or surviving entity does not assume an outstanding award, the award will fully vest, and (ii) in the event of termination by the Company of a participant’s employment or service without cause or by the participant for Good Reason (as defined in the LTIP), in each case, within one year following the occurrence of a Change in Control, the award will fully vest. These accelerated vesting provisions, if triggered, take precedence over service, performance or market based vesting provisions described below.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Restricted Stock Awards (“RSAs”)

We have granted RSAs to our employees and members of our Board of Directors (the “Board”). Grants awarded to employees consist of shares subject to service vesting conditions (the “Time Shares”) and shares subject to performance or market-based vesting conditions (the “Performance Shares”). All grants to members of our Board are Time Shares. Since 2019, vesting conditions established for all Performance Shares have been linked exclusively to the performance of the Company’s stock price vis-à-vis a peer group and hence have a market-based vesting condition. Please see “Note 1: Nature of operations and summary of significant accounting policies” for our accounting policies for awards that are subject to service-based vesting conditions compared to awards that are subject to market-based vesting conditions. The Time Shares vest in equal annual installments over a three -year vesting period. The Performance Shares vest in three tranches annually according to conditions established each year by our Board of Directors.

A summary of our restricted stock activity is presented below:

		Time Shares											Performance Shares
		Weighted average grant date fair value				Restricted shares			Vest date fair value				Weighted average grant date fair value				Restricted shares			Vest date fair value
		($ per share)											($ per share)
Unvested and outstanding at March 21, 2017		$	—			—							$	—			—
Granted		20.11				1,403,626							20.12				429,510
Vested		—				—							20.05				(152,421	)		$	3,611
Cancelled		—				—							20.05				(7,616	)
Unvested and outstanding at December 31, 2017		$	20.11			1,403,626							$	20.15			269,473
Granted		18.75				41,250							18.75				13,750
Vested		20.12				(445,029	)		$	7,856			20.08				(107,590	)		$	529
Forfeited		20.05				(181,641	)						20.05				(50,105	)
Unvested and outstanding at December 31, 2018		$	20.06			818,206							$	20.12			125,528
Granted		2.40				886,451							1.38				1,087,110
Vested		20.08				(408,270	)		$	2,334			16.45				(33,359	)		$	59
Forfeited		20.05				(226,882	)						20.05				(89,936	)
Unvested and outstanding at December 31, 2019		$	5.41			1,069,505							$	1.53			1,089,343

Restricted Stock Units (“RSUs”)

We have granted RSUs to employees and members of our Board with the following provisions:

Executive employee awards: 50% of the RSUs granted during 2019 were subject only to service vesting conditions and the other 50% were subject to market-based vesting conditions. Service-based RSUs vest in equal annual installments over a three-year period. Market condition RSUs vest in three annual tranches – each year according to our stock return performance in such year relative to a group of peers identified prior to the beginning of such performance year. Both market-based and service-based awards were classified as equity awards.

Non-executive employee awards: Grants consisted of RSUs with service vesting conditions and vest in equal annual installments over a three-year period. Certain RSUs are to be settled in stock upon vesting while others are to be settled in cash. The stock-settled RSUs are classified as equity awards while the cash-settled RSUs are classified as liability awards.

Board awards: Grants consisted of RSUs with service vesting conditions and which vest in its entirety on the earlier of (a) the first anniversary of the grant date or (b) the date of the next Company ensuing annual meeting. These awards were classified as liability awards.

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

A summary of our RSU activity is presented below:

		Equity classified RSUs
		Service-condition RSUs											Market-condition RSUs
		Weighted average grant date fair value				Restricted units			Vest date fair value				Weighted average grant date fair value				Restricted units
		($ per unit)											($ per unit)
Unvested and outstanding at January 1, 2018		$	—			—							$	—			—
Granted		17.66				92,017							$	—			—
Forfeited		17.66				(2,384	)						$	—			—
Unvested and outstanding at December 31, 2018		$	17.66			89,633							$	—			—
Granted		1.33				788,323							$	1.36			565,000
Vested		17.66				(25,099	)		$	33			$	—			—
Forfeited		3.02				(214,474	)						$	1.36			(175,000	)
Unvested and outstanding at December 31, 2019		$	2.41			638,383							$	1.36			390,000

		Liability-classified RSUs
		Weighted average grant date fair value				Restricted units			Vest date fair value
		($ per unit)
Unvested and outstanding at January 1, 2018		$	—			—
Granted		17.66				37,991
Forfeited		17.66				(795	)
Unvested and outstanding at December 31, 2018		$	17.66			37,196
Granted		1.44				71,570
Vested		9.33				(20,302	)		$	25
Forfeited		17.66				(12,685	)
Unvested and outstanding at December 31, 2019		$	4.57			75,779

Companywide stock award

In the past, we have made grants of 100 shares to each new employee subsequent to being employed for a certain period of time which resulted in a total of 1,100, 600 and 20,100 shares being granted in 2019, 2018 and 2017, respectively. There were no vesting requirements for these awards and thus compensation was recognized in full on the award date based on the closing price of our common stock on that date. The compensation cost is included in the table below.

Stock-based compensation cost

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

110

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

						Successor									Predecessor
										Period from					Period from
										March 22, 2017					January 1, 2017
		For the Year Ended December 31,								through					through
		2019				2018				December 31, 2017					March 21, 2017
Stock-based compensation expense		$	2,303			$	13,444			$	12,606				$	194
Less: stock-based compensation cost capitalized		(722		)		(2,543		)		(2,773		)			(39		)
Total stock-based compensation expense, net		$	1,581			$	10,901			$	9,833				$	155
Payments for stock-based compensation		$	1,198			$	4,936			$	—				$	—
Recognized tax expense associated with stock-based compensation		$	—			$	22			$	—				$	—

 

Our payments for stock-based compensation are predominantly for tax withholding during vesting events although we also make an immaterial amount of payments for our cash settled RSUs. Payments for RSAs and the associated number of shares repurchased are reflected as treasury stock transactions in our consolidated statements of equity. As of December 31, 2019, and 2018, accrued payroll and benefits payable included $52 and $17, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized stock-based compensation cost of approximately $3,386 as of December 31, 2019 is expected to be recognized over a weighted-average period of 1.4 years. This amount does not include market-condition RSAs and RSUs scheduled to vest in 2020 and 2021 since requisite service for those shares had not commenced as of December 31, 2019. We expect to repurchase or settle in cash approximately 476,000 shares/units in 2020. Based on the market price of $1.76 per share, the aggregate intrinsic value of unvested RSAs and RSUs outstanding was $5,743 as of December 31, 2019.

Valuation of Awards

Compensation cost is generally recognized and measured according to the grant date fair value of the awards. For awards with service and performance conditions, the fair value is based on the market price of our Class A common stock on the grant date. For awards with a market condition, expense is based on a grant date fair value that incorporates the probability of vesting and the potential value of the award at vesting. We utilize Monte Carlo simulations to estimate the fair value our market based awards. The fair value and associated assumptions, which are considered to be Level 3 inputs within the fair value hierarchy, for our market condition RSAs and RSUs granted in 2019 are follows:

Valuation assumptions of market awards		Low				High
Risk free rate		1.75		%		2.52		%
Volatility (1)		64.1		%		90.0		%
Fair value per share/unit		$	0.94			$	8.59

_____________________________

(1) Based on daily log returns over a lookback period commensurate with the remaining term until vesting.

Note 14: Stockholders’ equity

Predecessor Common Stock

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

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

Successor Common Stock

On the Effective Date, we issued a total of 44,982,142 shares of Successor common stock consisting of 37,110,630 shares of Class A common stock and 7,871,512 shares Class B common stock pursuant to our Reorganization Plan and our new organizational documents.  The new Class A shares and Class B shares had identical economic and voting rights. However, Class B shares were subject to certain redemption provisions upon demand to the Company by certain stockholders undertaking an initial public offering, as described in our Third Amended and Restated Certificate of Organization. On December 19, 2018, all outstanding shares of Class B common stock converted into the same number of shares of Class A common stock. Each share of Class B Common Stock that was converted has been retired by the Company and is not available for reissuance. The conversion had no impact on the voting power of the holders of shares of Class B Common Stock. The conversion had no impact on the total number of the Company’s issued and outstanding shares of capital stock.

Summary of changes in common stock

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

		Common Stock
		Class A			Class B			Class C			Class E			Class F			Class G			Total
Shares outstanding at January 1, 2017 - Predecessor		333,686			344,859			209,882			504,276			1			2			1,392,706
Restricted stock forfeited		(1,454	)		—			—			—			—			—			(1,454	)
Restricted stock canceled		(8,964	)		—			—			—			—			—			(8,964	)
Shares outstanding at March 21, 2017 - Predecessor		323,268			344,859			209,882			504,276			1			2			1,382,288
Cancellation of Predecessor equity		(323,268	)		(344,859	)		(209,882	)		(504,276	)		(1	)		(2	)		(1,382,288	)
Shares outstanding at March 21, 2017 - Predecessor		—			—			—			—			—			—			—
Issuance of Successor common stock - rights offering		4,197,210			—			—			—			—			—			4,197,210
Issuance of Successor common stock - backstop premium		367,030			—			—			—			—			—			367,030
Issuance of Successor common stock - settlement of claims		32,546,390			7,871,512			—			—			—			—			40,417,902
Shares outstanding at March 21, 2017 - Successor		37,110,630			7,871,512			—			—			—			—			44,982,142
Stock-based compensation		1,853,236			—			—			—			—			—			1,853,236
Restricted stock canceled		(7,616	)		—			—			—			—			—			(7,616	)
Shares outstanding at December 31, 2017 - Successor		38,956,250			7,871,512			—			—			—			—			46,827,762
Issuance of restricted stock		55,600			—			—			—			—			—			55,600
Conversion of Class B shares		7,871,512			(7,871,512	)		—			—			—			—			—
Repurchase of common stock		(261,103	)		—			—			—			—			—			(261,103	)
Restricted stock forfeited		(231,746	)		—			—			—			—			—			(231,746	)
Shares outstanding at December 31, 2018 - Successor		46,390,513			—			—			—			—			—			46,390,513
Stock-based compensation		2,002,173			—			—			—			—			—			2,002,173
Restricted stock forfeited		(316,821	)		—			—			—			—			—			(316,821	)
Repurchase of common stock		(209,852	)		—			—			—			—			—			(209,852	)
Issuance of common stock - litigation settlement		76,217			—			—			—			—			—			76,217
Shares outstanding at December 31, 2019 - Successor		47,942,230			—			—			—			—			—			47,942,230

 

112

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 15: Retirement benefits

We provide a 401(k) retirement plan for all employees and matched 100% of employee contributions up to 7% of each employee’s gross wages during 2019, 2018 and 2017. At December 31, 2019, 2018, and 2017, there were 122, 173, and 210 employees, respectively, participating in the plan. Our contribution expense was as follows:

						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
401(k) contribution expense		$	1,509			$	1,543			$	1,267				$	396

 

Note 16: Revenue recognition

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements which has been codified as Accounting Standards Codification 606: Revenue from Contracts with Customers (“ASC 606”). ASC 606 requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

Description of products and revenue disaggregation

Our revenue is predominantly derived from the production and sale of oil, natural gas and NGLs which, prior to January 1, 2018, was reported in the aggregate as “Commodity sales” on our statement of operations. Substantially all our oil and natural gas properties are located in Oklahoma and Texas and are sold to midstream gas processing plants or crude oil refineries in the vicinity. We have disaggregated revenue based on the separate commodities being sold: crude oil, natural gas and NGLs. In selecting the disaggregation categories, we considered a number of factors such as those affecting supply and demand and thus market prices, storage and the ability to transport the product, industry specific disclosures required by the SEC and FASB, other external disclosures we typically make, and information we have historically presented in the management discussion and analysis section of our annual and quarterly reports. As such, we believe that disaggregating revenue by commodity type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.

The following table displays the revenue disaggregated and reconciles the disaggregated revenue to the revenue reported:

		For the Year Ended December 31,
		2019				2018
Revenues:
Oil		$	173,555			$	171,749
Natural gas		40,543				41,506
Natural gas liquids		42,101				45,590
Gross commodity sales		256,199				258,845
Transportation and processing		(23,049		)		(16,276		)
Net commodity sales		$	233,150			$	242,569

 

Performance Obligations

Our oil, natural gas and natural gas liquids contracts typically contain only one type of performance obligation, which is for the delivery of the underlying commodity, and which is satisfied at the point in time the commodity is transferred to the customer. We consider each commodity (ex. barrel of oil or MMBtu of natural gas) to be a separate performance obligation. For natural gas and natural gas liquids, all our sales are to midstream processing entities engaged in the processing of gas and marketing the resulting residue gas and NGLs to third party customers. We transfer control of the product to the midstream processing customer at the wellhead and recognize revenue upon such delivery.

113

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Under our oil sales contracts, we generally sell oil to the purchaser from storage tanks near the wellhead and collect a contractually agreed upon index price, net of pricing differentials. We transfer control of the product from the storage tanks to the purchaser and recognize revenue based on the contract price.

We do not engage in activities to purchase and sell third party natural gas and NGLs. As a result, the commodity revenues we recognize are only for our working interest share of the production.

Pricing and measurement

All of our contracts use market or index-based pricing resulting in the entire transaction price being variable. Since our sales transactions meet the variable allocation criteria in the standard, all consideration is allocated entirely to performance obligations satisfied by distinct commodity units delivered. We record revenue in the month production is delivered to the purchaser. However, settlement statements for our commodity sales are received one to three months after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. Historically, differences between our revenue estimates and actual revenue received have not been significant. We receive payment for a majority of our sales receivables in the month following delivery and substantially all within three months following delivery. For the year ended December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Transaction Price Allocated to Remaining Performance Obligations  

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Nature of gas contracts

All our natural gas and NGL production is sold to midstream processing entities and we do not elect to take our residue gas and/or NGLs in-kind at the tailgate of the processing plant. The midstream customer provides us with services such as compressing the gas, transporting the gas to the processing plant and processing it into the separate commodity streams for fees which are deducted from the revenue we receive. We previously reported fees for these services as “Transportation and processing” expenses in our statement of operations. Under ASC 606, since control and possession of the gas is transferred to the customer at the wellhead prior to the receipt of the aforementioned services, the customer is not deemed to be providing a distinct service and any fees paid to the customer are accounted for as a reduction in revenue. We have presented transportation and processing fees as a revenue deduction for the fiscal period beginning January 1, 2018, while our presentation for prior periods remains unchanged.

Contract assets and liabilities

We recognize a receivable for the unconditional right to receive consideration when the commodity is transferred to the customer, at which point the performance obligation is satisfied. All our contract assets are in the form of receivables which are presented as “Accrued commodity sales” in our tabular disclosure of accounts receivable in “Note 1: Nature of operations and summary of significant accounting policies.” Since we are not entitled to advance payments from our customers prior to the transfer of our commodities nor do we receive such payments, we do not have contract liabilities.

Method of adoption

We adopted ASC 606 effective January 1, 2018, using the modified retrospective approach. Based on an assessment of our contracts, the new guidance did not have a material impact on prior net income and therefore we did not record a cumulative effect adjustment to the opening balance of accumulated deficit.

114

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Reconciliation of Income Statement

In accordance with ASC 606, the disclosure of the impact of adoption on our income statement is as follows:

		Year ended December 31, 2018
		As reported				Balances without adoption of ASC 606				Effect of change
Revenues
Net commodity sales		$	242,569			$	258,845			$	16,276
Costs and expenses
Transportation and processing		$	—			$	(16,276	)		$	(16,276	)

Note 17: Leases

In February 2016, the FASB established ASC 842, which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Targeted Improvements and ASU No 2019-01, Codification Improvements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases except those with a term of 12 months or less. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. We adopted the new standard on its effective date of January 1, 2019, which is also our date of initial application. Consequently, we have not updated financial information nor provided disclosures required under the new standard for dates and periods before January 1, 2019. Our disclosures for dates and periods before January 1, 2019, are provided in accordance with the requirements of ASC Topic 840, Leases (“ASC 840”).

We have elected the package of transition practical expedients, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. Additionally, we have elected not to apply the recognition requirements of ASC Topic 842 to leases with durations of 12 months or less. Upon adoption of ASC 842, we carried over our existing capital lease obligations (now “financing leases” under ASC 842) and capital lease asset (now “right of use asset” under ASC 842) at their previous carrying value. In recognizing right of use assets and corresponding lease liabilities, the Company considers whether the lease agreements contain options to renew or purchase, and the likelihood that those options will be exercised.

Financing leases

We previously had lease financing agreements which were entered into during 2013 with U.S. Bank for $24,500 through the sale and subsequent leaseback of existing CO₂ compressors owned by us. The lease financing obligations were for terms of 84 months and included the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. There were no residual value guarantees and nonlease components under these leases. At the inception of the lease, our measurement of the lease liability assumed that the mid-term purchase option would be exercised. Since the lease contract had not been modified and there were no triggering events subsequent to our adoption of ASC 842, we did not perform any reassessment of the lease prior to its termination discussed below. Lease payments related to the equipment were recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments were approximately $3,181 annually. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets while we remained the primary obligor in relation to U.S. Bank. In September 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of the remaining obligations with respect to these compressor leases in the amount of $9,832.

During 2019, we entered into lease financing agreements for our fleet trucks and office copiers for $1,911. The fleet truck financing obligations are for 48-month terms with the option for us to purchase the vehicle at any time during the lease term by paying the lessor’s remaining unamortized cost in the vehicle. At the end of the lease term, the lessor’s remaining unamortized cost in the vehicle will be a de minimis amount and hence ownership of the vehicle can be transferred to us at minimal cost. There are no residual value guarantees or nonlease components under these leases. We also entered into a lease financing arrangement for a limited number of office copiers in 2019.

115

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Operating leases

We previously also had operating leases for CO₂ compressors deployed in our former EOR operations. The operating lease obligations, which we entered into in 2014 and 2016, were for terms of 84 months without any specified purchase options. There were no residual value guarantees or nonlease components under these leases. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets although we remained the primary obligor in relation to U.S. Bank. Similar to the financing leases discussed above, all our obligations under these compressor leases were discharged by U.S. Bank in September 2019.

During the fourth quarter of 2018, we entered into 15-month leasing arrangements for two drilling rigs. These agreements specify a minimum daily rate on the rigs that we utilize to measure the lease liability upon adoption of ASC 842. The actual daily rate may vary from the minimum rate depending on whether the rig is being mobilized, demobilized, engaged in drilling or on standby. The daily rate includes a non-lease labor component that we have elected not to separate from the lease component for this asset class. Our fixed commitment under those lease agreements terminated on December 31, 2019. Each of the two drilling rigs operating on our behalf during the first quarter of 2020 are contracted on a well-by-well basis.

On August 30, 2019, in conjunction with the sale of the building housing our headquarters, we entered into a leaseback agreement with the buyer for a portion of the office space in the building for a period of two years with a renewal option that includes one-year extensions for up to two years. The office space lease includes typical non-lease components such as utilities, maintenance and janitorial services for that we have elected not to separate from the lease component.

Short term leases

Our short term leases are those with lease terms of 12 months or less and generally consist of wellhead compressors, generators and drilling rigs with terms ranging from one month to six months. As discussed above, we have elected not to recognize right of use assets or lease liabilities for leases with durations of 12 months or less.

Subleases

As discussed above, we previously had subleases consisting of CO₂ compressors that were utilized in our former EOR operations and leased as both financing and operating leases from U.S. Bank but subsequently subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases were equal to the original leases and as such we did not record any losses upon initiation of the subleases. All the subleases were classified as operating leases from a lessor’s standpoint. All payments received from the Sublessee were reflected as “Sublease revenue” on our statement of operations. Minimum payments made to U.S. Bank on the original operating leases were reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet, amortized the asset on a straight line basis prospectively while continuing to incur interest expense. In September 2019, U.S. Bank entered into agreements with the Sublessee that resulted in the discharge of all our obligations with respect to the originating leases and to the subleases.

116

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Lease assets and liabilities

Our operating and financing lease assets and liabilities are recorded on our balance sheet as of December 31, 2019 as follows:

		As of December 31, 2019
		Operating leases				Financing leases
Right of use asset:
Right of use assets from operating leases (1)		$	2,444			$	—
Plant, property and equipment, net (2)		—				1,659
Total lease assets		$	2,444			$	1,659
Lease liability:
Account payable and accrued liabilities		$	1,259			$	—
Long-term debt and financing leases, classified as current		—				432
Long-term debt and financing leases, less current maturities		—				1,221
Noncurrent operating lease obligations		917				—
Total lease liabilities		$	2,176			$	1,653

________________________________

(1) Consisted of a lease of office space.

(2) Consisted of leased fleet vehicles and office equipment.

Our income, expenses and cash flows related to our leases is as follows for the year ended December 31, 2019:

		Year ended
		December 31, 2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets		$	2,073
Interest on lease liabilities		344
Operating lease cost		1,342
Short-term lease cost		780
Variable lease cost		253
Sublease income		(3,195		)
Total lease cost		$	1,597
Capitalized operating lease cost (1)		$	13,523
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases		$	(344	)
Operating cash flows for operating leases		(1,610		)
Investing cash flows for operating leases		(9,448		)
Financing cash flows for finance leases		(2,102		)
Right-of-use assets obtained in exchange for new finance lease liabilities		1,911

________________________________

(1)	The operating lease cost are related to drilling rigs and are capitalized as part of oil and natural gas properties on our balance sheets.

117

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

		As of
		December 31, 2019
Weighted-average remaining lease term - finance leases		3.6 years
Weighted-average remaining lease term - operating leases		1.7 years
Weighted-average discount rate - finance leases		6.67	%
Weighted-average discount rate - operating leases		8.72	%

Our rent expense for the years ended December 31, 2019, 2018 and 2017 was $5,542, $3,684 and $4,971, respectively.

Discount rate

Whenever possible, we utilize the implied rate in our lease agreements to measure our lease liabilities. In the absence of a readily available implied rate, we utilize our incremental borrowing rate. The incremental borrowing rate is the rate of interest that a lessee would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. The lease liabilities we recorded on our balance sheet on the effective date of ASC 842 were measured utilizing an incremental borrowing rate derived from the yield and/or credit rating on our unsecured Senior Notes and adjusted to a collateralized basis utilizing a recovery rate model that uses observed recovery rates on defaulted debt instruments.

Lease maturities

Our lease payments for each of the next five years and thereafter are as follows:

		As of December 31, 2019							As of December 31, 2018 (1)
		Operating leases			Financing leases				Operating leases			Financing leases
2019		$	1,389		$	530			$	13,890		$	12,332
2020		941			530				1,330			—
2021		—			531				1,297			—
2022		—			226				278			—
2023		—			55				205			—
Thereafter		—			—				—			—
Total minimum lease payments		2,330			1,872				17,000			12,332
Less: imputed interest		154			219				*			*
Total lease liability		2,176			1,653				*			*
Less: current maturities of lease obligations		1,259			432				*			*
Noncurrent lease obligations		$	917		$	1,221			*			*

________________________________

(1)	Represents undiscounted firm commitments as of December 31, 2018

* Disclosure not required under ASC 840.

Method of adoption

We adopted ASC 842 effective January 1, 2019, using the modified retrospective approach. Based on an assessment of our leasing contracts, we did not record a cumulative effect adjustment to the opening balance of accumulated deficit.

118

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Reconciliation of Balance Sheet Statement

In accordance with ASC 842, the disclosure of the impact of adoption on our balance statement is as follows:

		As of January 1, 2019
		Balances upon adoption				Balances without adoption of ASC 842				Effect of change
Assets
Right of use asset from operating leases, net		$	14,999			$	—			$	14,999
Liabilities
Accounts payable and accrued liabilities		12,467				—				12,467
Noncurrent operating lease obligation		2,532				—				2,532

Note 18: Commitments and contingencies

Letters of Credit. Standby letters of credit (“Letters”) available under our Credit Agreement are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. Our outstanding Letters, as of December 31, 2019 and 2018, totaled $0 and $869, respectively. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters; therefore, we paid no interest on the Letters during the years ended December 31, 2019, 2018, or 2017.

Leases. Our leases currently consist of an operating lease for the office space housing our headquarters and financing leases for fleet vehicles and office equipment. Please see “Note 17: Leases” for a detailed discussion of these contracts.

Litigation and Claims

Chapter 11 Proceedings. Commencement of the Chapter 11 Cases in 2016 automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to the Petition Date, and the claims remain subject to Bankruptcy Court jurisdiction. With respect to the proofs of claim asserted in the Chapter 11 Cases arising from the proceedings or actions below that were initiated prior to the Petition Date, we are unable to estimate the amount of such claims that will be allowed by the Bankruptcy Court due to, among other things, the complexity and number of legal and factual issues which are necessary to determine the amount of such claims and uncertainties related to the nature of defenses asserted in connection with the claims, the potential size of the putative classes, and the types of the properties and scope of agreements related to such claims. As a result, no reserves were established in respect of such proofs of claims or any of the proceedings or actions described below. To the extent that any of the legal proceedings were filed that relate to one or more claims accruing prior to the Petition Date and that result in a claim being allowed against us, pursuant to the terms of the Reorganization Plan, such claims will be satisfied through the issuance of new stock in the Company or, if the amount of such claim is below the convenience class threshold, through cash settlement. If the Bankruptcy Court were to allow the remaining unresolved proofs of claims from any of these cases in the full amount asserted therein, the Company, pursuant to the Plan of Reorganization, would be required to issue additional shares to the holders of such allowed proofs of claim that are in excess of a convenience class threshold, which could result in dilution to existing stockholders.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C (the “Naylor Farms case”). On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Trial Court”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other non-governmental Royalty Interest owners from crude oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. Plaintiffs indicated they seek damages in excess of $5,000, the majority of which consist of interest and may increase with the passage of time. We responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the Naylor Trial Court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court. Subsequently the bankruptcy stay was lifted for the limited purpose of determining the class certification issue.

119

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the plaintiffs originally sought to certify. After additional briefing on the subject, on April 18, 2017, the Naylor Trial Court issued an order certifying the class to include only claims relating back to June 1, 2006. On May 3, 2019, our appeal of that class certification was denied by the Tenth Circuit Court of Appeals.

In addition to filing claims on behalf of the named and putative plaintiffs, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of $150,000 in our Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90,000 inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims, to which we will also object. The Bankruptcy Court order was affirmed by the United States District Court for the District of Delaware on September 24, 2019. On October 24, 2019, the Company filed its notice of appeal to the United States Court of Appeals for the Third Circuit.

We continue to dispute the plaintiffs’ allegations and are objecting to the claims both individually and on a class-wide basis.

W.H. Davis Family Limited Partnership Claims in the Company’s Chapter 11 Bankruptcy Cases (the “W.H. Davis case”). The W. H. Davis Family Limited Partnership and affiliates (collectively, “Davis”) filed Proofs of Claim in the Company’s Chapter 11 Cases. Davis claimed that Chaparral owed Davis $17,262 as the result of Chaparral’s alleged diversion of CO₂ from the Camrick Unit and the North Perryton Unit to the Farnsworth Unit. All these units were divested by the Company as part of its EOR asset sale in November 2017. While the Company denies all claims asserted by Davis, the Company determined it was prudent to explore settlement of the claims. Accordingly, the Company and Davis agreed at mediation to settle Davis’ claims for an allowed claim of $2,650 in Class 6 under the Reorganization Plan, which agreement was memorialized in a settlement term sheet executed by both parties on the day of the mediation, a settlement agreement executed by both parties thereafter, and a settlement stipulation executed by both parties that was filed with the Bankruptcy Court. Davis is now contesting the enforcement of the settlement under its terms, which resulted in the issuance of 84,347 shares of Class A common stock to Davis, claiming that he was mistaken in his understanding of the terms of the Reorganization Plan as relate to Class 6 claims. The Company is vigorously pursuing the enforcement of the settlement in the Bankruptcy Court.

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

Note 19: Oil and natural gas activities (unaudited)

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

		Successor													Predecessor
										Period from					Period from
										March 22, 2017					January 1, 2017
		For the Year Ended December 31,								through					through
		2019				2018				December 31, 2017					March 21, 2017
Property acquisition costs
Proved properties		$	179			$	1,699			$	179				$	527
Unproved properties		22,928				120,610				33,901					2,904
Total acquisition costs		23,107				122,309				34,080					3,431
Development costs		238,664				199,833				140,180					32,657
Exploration costs		8,055				18,876				916					1,241
Total		$	269,826			$	341,018			$	175,176				$	37,329

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

		Successor													Predecessor
										Period from					Period from
										March 22, 2017					January 1, 2017
		For the Year Ended December 31,								through					through
		2019				2018				December 31, 2017					March 21, 2017
DD&A (1)		$	103,732			$	79,070			$	84,899				$	23,442
DD&A per BOE:		$	10.81			$	10.56			$	12.86				$	13.05

________________________________

(1)	Includes accretion of asset retirement obligations.

Oil and natural gas properties not subject to amortization consists of unevaluated leasehold acquisition costs, capitalized interest related to the leasehold costs and wells or facilities for which reserve volumes are not classified as proved until completed. The costs of unevaluated oil and natural gas properties, by year incurred, consisted of the following:

 

		Year Cost Incurred												Total as of
		2019				2018				2017				December 31, 2019
Leasehold acreage (1)		$	5,223			$	70,017			$	258,843			$	334,083
Capitalized interest (2)		7,091				9,694				—				16,785
Wells in progress of completion		20,361				—				—				20,361
Total unevaluated oil and natural gas properties excluded from amortization		$	32,675			$	79,711			$	258,843			$	371,229

________________________________

(1)	In the past, the costs associated with unevaluated properties typically related to historical acquisition costs of leasehold acreage. However, the total balance as December 31, 2019 includes an increase in carrying value to fair value of $235,723 as a result of the application of fresh start accounting upon emergence from bankruptcy. See “Note 4: Fresh start accounting.”

(2)	As of December 31, 2019, this amount reflects the cumulative interest capitalized on the historical acquisition cost of leasehold acreage subsequent to our establishing opening balances under fresh start accounting. Interest is not capitalized on amounts related to the fair value gross up discussed above.

The carrying value of wells in progress of completion will be transferred to the amortization base upon completion in 2020. With respect to leasehold acreage, the carrying value of undeveloped leasehold acreage will be evaluated and transferred to the amortization base within the next two to five years. Leasehold acreage also includes value assigned to held-by-production leasehold upon adoption of fresh start accounting; the carrying value of such leasehold will be transferred to the amortization base as those locations are evaluated. 

Note 20: Disclosures about oil and natural gas activities (unaudited)

The estimate of proved reserves and related valuations at the end of each period presented were based upon the reports of Cawley, Gillespie & Associates, Inc., an independent petroleum and geological engineering firm, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.  

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2019 are as follows:

 

		Oil (MBbls)			Natural gas (MMcf)			Natural gas liquids (MBbls)			Total (MBoe)
Proved developed and undeveloped reserves
As of January 1, 2017		96,621			135,449			12,105			131,301
Sales of minerals in place		(74,918	)		(1,663	)		(46	)		(75,241	)
Extensions and discoveries		8,957			39,843			5,442			21,040
Revisions (1)		3,515			11,135			2,216			7,586
Production		(4,571	)		(14,598	)		(1,395	)		(8,399	)
Balance at December 31, 2017		29,604			170,166			18,322			76,287
Sales of minerals in place		(2,422	)		(14,184	)		(1,374	)		(6,160	)
Extensions and discoveries		6,545			69,189			9,329			27,406
Revisions (1)		1,254			12,596			1,411			4,764
Production		(2,684	)		(17,549	)		(1,881	)		(7,490	)
Balance at December 31, 2018		32,297			220,218			25,807			94,807
Sales of minerals in place		—			—			—			—
Extensions and discoveries		4,766			48,967			8,343			21,271
Revisions (1)		(6,703	)		(26,340	)		1,166			(9,927	)
Production		(3,111	)		(22,095	)		(2,799	)		(9,593	)
Balance at December 31, 2019		27,249			220,750			32,517			96,558
Proved developed reserves:
January 1, 2017		28,590			108,800			9,352			56,076
December 31, 2017		18,301			123,451			11,858			50,734
December 31, 2018		18,051			135,425			14,846			55,468
December 31, 2019		18,447			152,187			20,949			64,761
Proved undeveloped reserves:
January 1, 2017		68,031			26,649			2,753			75,225
December 31, 2017		11,303			46,715			6,464			25,553
December 31, 2018		14,246			84,793			10,961			39,339
December 31, 2019		8,802			68,563			11,568			31,797

(1)	The revisions in 2019 and 2018 were primarily due to changes in pricing during the respective periods. The upward revision in 2017 was primarily due to changes in pricing and costs.

 

The following information was developed using procedures prescribed by U.S. GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

We believe that, in reviewing the information that follows, the following factors should be taken into account:

•	future costs and sales prices will probably differ from those required to be used in these calculations;

•	actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

•	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

•	future net revenues may be subject to different rates of income taxation.

Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 9: Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

		December 31,
		2019				2018				2017
Future cash flows		$	2,424,620			$	3,255,771			$	2,331,940
Future production costs		(1,040,314		)		(1,187,071		)		(899,380		)
Future development and abandonment costs		(304,229		)		(450,220		)		(336,828		)
Future income tax provisions		—				—				—
Net future cash flows		1,080,077				1,618,480				1,095,732
Less effect of 10% discount factor		(565,874		)		(932,114		)		(597,859		)
Standardized measure of discounted future net cash flows		$	514,203			$	686,366			$	497,873

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

		For the year ended December 31,
		2019				2018				2017
Beginning of year		$	686,366			$	497,873			$	528,781
Sale of oil and natural gas produced, net of production costs		(170,255		)		(175,199		)		(175,246		)
Net changes in prices and production costs		(332,546		)		95,430				125,795
Extensions and discoveries		114,199				192,105				136,887
Improved recoveries		—				—				—
Changes in future development costs		116,677				(2,424		)		(4,879		)
Development costs incurred during the period that reduced future development costs		38,270				6,277				37,912
Revisions of previous quantity estimates (1)		(8,152		)		79,192				68,428
Purchases and sales of reserves in place, net		—				(45,222		)		(238,445		)
Accretion of discount		58,668				36,386				24,267
Net change in income taxes		—				—				—
Changes in production rates and other		10,976				1,948				(5,627		)
End of year		$	514,203			$	686,366			$	497,873

(1)	Amounts in 2019 and 2018 are primarily the result of changes in pricing. Amounts in 2017 are primarily the result of increased volumes due to changes in pricing and costs.

The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.

		2019				2018				2017
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

 

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Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 21: Supplemental quarterly financial information (unaudited)

The following tables present a summary of our unaudited interim results of operations:

		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
2019
Total revenues		$	49,817			$	67,905			$	52,637			$	65,986
Operating loss		$	(47,510	)		$	(57,268	)		$	(146,445	)		$	(158,128	)
Net loss		$	(103,540	)		$	(45,229	)		$	(130,935	)		$	(189,244	)
Earnings per share:
Basic for Class A and Class B		(2.28		)		$	(0.99	)		$	(2.86	)		$	(4.14	)
Diluted for Class A and Class B		(2.28		)		$	(0.99	)		$	(2.86	)		$	(4.14	)

____________________________________________________________

(1)	Includes loss on impairment of oil and natural gas properties of $49,722, $63,593, $147,686 and $169,694 for the first, second, third and fourth quarter of 2019, respectively.

		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
2018
Total revenues		$	59,087			$	59,625			$	66,718			$	61,932
Operating income (loss) (1)		$	8,426			$	12,024			$	18,312			$	(8,585	)
Net (loss) income		$	(11,442	)		$	(21,993	)		$	(12,068	)		$	78,945
Earnings per share:
Basic for Class A and Class B (2)		(0.25		)		$	(0.49	)		$	(0.27	)		$	1.74
Diluted for Class A and Class B (2)		(0.25		)		$	(0.49	)		$	(0.27	)		$	1.73

____________________________________________________________

(1)	Includes loss on impairment of oil and natural gas properties of $20,065 for the fourth quarter.

(2)	On December 19, 2018, all outstanding shares of Class B common stock converted into the same number of shares of Class A common stock.

 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at December 31, 2019, at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.  

Management’s Report on Internal Control over Financial Reporting

Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers, or persons performing similar functions, and effected by our Board, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

•pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions relating to and the dispositions of our assets;

•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

•provide reasonable assurance regarding prevention or the timely detection of unauthorized acquisition, or the use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in the 2013 Internal Control-Integrated Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2019.

The effectiveness of our internal control over financial reporting as of December 31, 2019, has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report that follows.

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Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Chaparral Energy, Inc.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Chaparral Energy, Inc. (a Delaware corporation) and subsidiaries (the Company) as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated March 11, 2020 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 11, 2020

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information relating to this item will be included in an amendment to this report to be filed no later than April 29, 2020 and is incorporated by reference in this report.

ITEM 11. EXECUTIVE COMPENSATION

Information relating to this item will be included in an amendment to this report to be filed no later than April 29, 2020 and is incorporated by reference in this report.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information relating to this item will be included in an amendment to this report to be filed no later than April 29, 2020 and is incorporated by reference in this report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information relating to this item will be included in an amendment to this report to be filed no later than April 29, 2020 and is incorporated by reference in this report.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information relating to this item will be included in an amendment to this report to be filed no later than April 29, 2020 and is incorporated by reference in this report.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements, Schedules and Exhibits

(1)	Financial Statements-Chaparral Energy, Inc. and Subsidiaries:

The Financial Statements listed in the Index to Consolidated Financial Statements are filed as part of this report on Form 10-K (see Part II, Item 8-Financial Statements and Supplementary Data).

(2)	Financial Statement Schedules

All other consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this report on Form 10-K.

(3)	Exhibits

The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this report on Form 10-K.

Exhibit No.		Description
2.1*		First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code, dated March 7, 2017 (Incorporated by reference to Exhibit 1 of Exhibit 99.1 of the Company’s Current Report on Form 8-K filed on March 14, 2017).
2.2*		Asset Purchase and Sale Agreement dated October 13, 2017, by and among Chaparral Energy, L.L.C., Chaparral CO2, L.L.C., Chaparral Real Estate, L.L.C., and Perdure Petroleum, L.L.C. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed on November 21, 2017).
2.3*		Purchase and Sale Agreement dated December 22, 2017, by and among Blake Production Company, Inc., Fairway Energy L.L.C., Vernon Resources L.L.C., ABV Ventures L.L.C., and Chaparral Energy, L.L.C. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed on December 27, 2017).
2.4*		First Amendment to Purchase and Sale Agreement dated January 2, 2018, by and among Blake Production Company, Inc., Fairway Energy L.L.C., Vernon Resources LLC, ABV Ventures LLC and Chaparral Energy, L.L.C. (Incorporated by reference to Exhibit 2.4 of the Company’s Annual Report on Form 10-K filed on March 29, 2018).
2.5*		Purchase and Sale Agreement dated December 22, 2017, by and between BVD INC. and Chaparral Energy, L.L.C. (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K filed on December 27, 2017).
3.1*		Third Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc., dated as of March 21, 2017 (Incorporated by reference to Exhibit 3.1 of  the Company’s Current Report on Form 8-K filed on March 27, 2017).
3.2*		Certificate of Retirement of 7,869,929 shares of Class B Common Stock (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on December 19, 2018).
3.3*		Second Amended and Restated Bylaws of Chaparral Energy, Inc., dated as of December 20, 2019 (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
4.1*		Indenture dated June 29, 2018, among the Company, the Guarantors party thereto, and UMB Bank, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on July 2, 2018).
4.2*		Form of 8.750% Senior Note due 2023 (Incorporated by reference to Exhibit A of Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on July 2, 2018).
4.3*		Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017).
4.4		Description of the Common Stock, par value $0.01 per share, of Chaparral Energy, Inc.
10.1*†		Form of Indemnification Agreement between Chaparral Energy, Inc. and the directors and officers of Chaparral Energy, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Amendment to Form 10-K on Form 10-K/A filed on April 29, 2019).

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Exhibit No.		Description
10.2*†		Chaparral Energy, LLC Long-Term Cash Incentive Plan Agreement (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 16, 2015).
10.3*†		Amended and Restated Employment Agreement, dated as of March 21, 2017, by and between the Company and K. Earl Reynolds (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q filed on May 15, 2017).
10.4*†		Separation and Release Agreement, dated as of December 20, 2019, by and among Chaparral Energy, Inc., Chaparral Energy, L.L.C. and K. Earl Reynolds (Incorporated by reference to Exhibit 99.3 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
10.5*†		Amended and Restated Employment Agreement, dated as of March 21, 2017, by and between the Company and Joseph O. Evans (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q filed on May 15, 2017).
10.6*†		Separation and Release Agreement, dated February 14, 2019, by and between Chaparral Energy, Inc. and Joseph O. Evans (Incorporated by Reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on February 15, 2019).
10.7*†		Employment Agreement, dated as of December 20, 2019, by and among Chaparral Energy, Inc., Chaparral Energy, L.L.C. and Charles Duginski (Incorporated by reference to Exhibit 99.4 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
10.8*†		Restricted Stock Award Agreement by and between Chaparral Energy, Inc., and Charles Duginski, together with related Restricted Stock Award Notice (3-Year Time-Based Vesting) (Incorporated by reference to Exhibit 99.5 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
10.9*†		Restricted Stock Award Agreement by and between Chaparral Energy, Inc., and Charles Duginski, together with related Restricted Stock Award Notice (3-Year Performance-Based Vesting) (Incorporated by reference to Exhibit 99.6 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
10.10*†		Cash Incentive Award Agreement, dated as of December 20, 2019, by and between Chaparral Energy, Inc., and Charles Duginski, together with related Cash Incentive Award Notice (3-Year Time-Based Vesting) (Incorporated by reference to Exhibit 99.7 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
10.11*†		Cash Incentive Award Agreement, dated as of December 20, 2019, by and between Chaparral Energy, Inc., and Charles Duginski, together with related Cash Incentive Award Notice (3-Year Performance-Based Vesting) (Incorporated by reference to Exhibit 99.8 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
10.12*†		Employment Agreement, dated as of April 22, 2019, by and between the Company and Scott Pittman. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K/A filed on April 23, 2019).
10.13*†		Amended and Restated Employment Agreement, dated as of March 21, 2017, by and between the Company and James M. Miller (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q filed on May 15, 2017).
10.14*		Tenth Restated Credit Agreement, dated as of December 21, 2017, among Chaparral Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on December 27, 2017).
10.15*		First Amendment to Tenth Restated Credit Amendment, effective as of May 9, 2018, by and among Chaparral Energy, Inc., a Delaware corporation, each Guarantor party hereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on May 10, 2018).
10.16*		Resignation, Consent and Appointment Agreement and Second Amendment to Tenth Restated Credit Agreement, dated as of December 7, 2018, among Chaparral Energy, Inc., as borrower, JPMorgan Chase Bank, N.A., as existing administrative agent and issuing bank, Royal Bank of Canada, as successor administrative agent and issuing bank, and the additional lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on December 10, 2018).
10.17*		Third Amendment to Tenth Restated Credit Amendment, dated as of May 2, 2019 and effective as of March 31, 2019, by and among Chaparral Energy, Inc., a Delaware corporation, each Guarantor party hereto, Royal Bank of Canada, as Administrative Agent, and each of the Lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on May 9, 2019).

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10.18*		Fourth Amendment to Tenth Restated Credit Amendment, dated as of September 27, 2019, by and among Chaparral Energy, Inc., a Delaware corporation, each Guarantor party hereto, Royal Bank of Canada, as Administrative Agent, and each of the Lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on October 2, 2019).
10.19*		Letter Agreement, effective as of July 27, 2018, by and among Chaparral Energy, Inc., each Guarantor party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 13, 2018).
10.20*†		Chaparral Energy, Inc. Management Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on August 15, 2017).
10.21*†		Form of Time Vesting Restricted Stock Award Agreement under the Chaparral Energy, Inc. Management Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on August 15, 2017).
10.22*†		Form of Time Performance Vesting Restricted Stock Award Agreement under the Chaparral Energy, Inc. Management Incentive Plan (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on August 15, 2017).
10.23*†		Chaparral Energy, Inc. 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on July 2, 2019).
10.24*†		Form of LTIP One Year Time Vesting Restricted Stock Unit Award Agreement under the Chaparral Energy, Inc. 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.2 of the Company’s Registration Statement on Form S-8 filed on August 13, 2019).
10.25*†		Form of LTIP Three Year Time Vesting Restricted Stock Unit Award Agreement under the Chaparral Energy, Inc. 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.3 of the Company’s Registration Statement on Form S-8 filed on August 13, 2019).
10.26*†		Form of LTIP Three Year Time Performance Vesting Restricted Stock Unit Award Agreement under the Chaparral Energy, Inc. 2019 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.4 of the Company’s Registration Statement on Form S-8 filed on August 13, 2019).
10.27*		Amended and Restated Support Agreement, dated as of December 20, 2019, by and among Strategic Value Partners, LLC, certain investment funds directly and indirectly managed by Strategic Value Partners, LLC, and Chaparral Energy, Inc. (Incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
10.28*		Amended and Restated Support Agreement, dated as of December 20, 2019, by and among Contrarian Capital Management, L.L.C., certain private investment funds directly and indirectly managed by Contrarian, Capital Management, L.L.C. and Chaparral Energy, Inc. (Incorporated by reference to Exhibit 99.2 of the Company’s Current Report on Form 8-K filed on December 27, 2019).
21.1		List of Subsidiaries of the Company.
23.1		Consent of Grant Thornton LLP.
23.2		Consent of Cawley, Gillespie & Associates, Inc.
31.1		Certification by Principal Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.
31.2		Certification by Principal Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.
32.1		Certification by Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1		Report of Cawley, Gillespie & Associates, Inc.
99.2*		Findings of Fact, Conclusions of Law and Order Confirming the First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code, as entered by the Bankruptcy Court on March 10, 2017. (Incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K filed on March 14, 2017).
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Extension Schema Document.
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

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101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

 

*	Incorporated by reference

**	The schedules and exhibits to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K.

†	Management contract or compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	CHAPARRAL ENERGY, INC.
	By:		/s/    Charles Duginski
	Name:		Charles Duginski
	Title:		Chief Executive Officer
			(Principal Executive Officer)

 

Date: March 12, 2020

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POWER OF ATTORNEY

Each person whose signature appears below appoints Charles Duginski, Scott Pittman and Justin Byrne, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K under the Securities Exchange Act of 1934, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorney-in-fact and agent may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature		Title		Date
/s/    Marcus Rowland		Chairman of the Board		March 12, 2020
Marcus Rowland
/s/    Charles Duginski		Chief Executive Officer and Director		March 12, 2020
Charles Duginski		(Principal Executive Officer)
/s/    Scott Pittman		Chief Financial Officer and Executive Vice President		March 12, 2020
Scott Pittman		(Principal Financial and Principal Accounting Officer)
/s/    Douglas E. Brooks		Director		March 12, 2020
Douglas E. Brooks
/s/    Michael Kuharski		Director		March 12, 2020
Michael Kuharski
/s/    Samuel Langford		Director		March 12, 2020
Samuel Langford
/s/    Kenneth W. Moore		Director		March 12, 2020
Kenneth W. Moore
/s/    Gysle Shellum		Director		March 12, 2020
Gysle Shellum
/s/    Mark McFarland		Director		March 12, 2020
Mark McFarland

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