CHAP Chaparral Energy Inc

Chaparral Energy, Inc. (Exact name of registrant as specified in its charter)

Delaware		73-1590941
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
701 Cedar Lake Boulevard Oklahoma City, Oklahoma		73114
(Address of principal executive offices)		(Zip code)

(405) 478-8770 (Registrant’s telephone number, including area code)

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

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

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•	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.

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

•	volatility and declines in oil and natural gas prices;

•	drilling plans (including scheduled and budgeted wells);

•	the number, timing or results of any wells;

•	changes in wells operated and in reserve estimates;

•	future growth and expansion;

•	future exploration;

•	integration of existing and new technologies into operations;

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

•	effectiveness and extent to our risk management activities;

•	availability and cost of equipment;

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

•	borrowings and capital resources and liquidity;

•	covenant compliance under instruments governing any of our existing or future indebtedness;

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

•	future tax matters;

•	legislation and regulatory initiatives;

•	loss of key personnel;

•	geopolitical events affecting oil and natural gas prices;

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

•	the ability to generate additional prospects; and

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

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GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this section are used throughout this Form 10-Q:

Bbl	One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate, or natural gas liquids.
BBtu	One billion British thermal units.
Boe	Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.
Boe/d	Barrels of oil equivalent per day.
Btu	British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
CO 2	Carbon dioxide.
Credit Facility	Tenth Restated Credit Agreement, as amended, by and among Chaparral Energy, Inc., Royal Bank of Canada as Administrative Agent and the Lenders thereto.
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	Date of emergence from bankruptcy, or March 21, 2017.
Enhanced oil recovery (EOR)	The use of any improved recovery method, including injection of CO 2  or polymer, to remove additional oil after Secondary Recovery.
EOR Areas	Areas where we previously injected and/or recycled CO 2  as a means of oil recovery which were divested in November 2017.
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.
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.
MMBtu	One million British thermal units.
MMcf	One million cubic feet of natural gas.
Natural gas liquids (NGLs)	Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline.
NYMEX	The New York Mercantile Exchange.

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Play	A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.
Proved developed reserves	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved reserves	The quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Proved undeveloped reserves	Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
PV-10 value	When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.
Reorganization Plan	First Amended Joint Plan of Reorganization for Chaparral Energy, Inc. and its Affiliate Debtors under Chapter 11 of the Bankruptcy Code.
SEC	The Securities and Exchange Commission.
Senior Notes	Our 8.75% senior notes due 2023.
STACK	An acronym standing for Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko basin of Oklahoma in which we operate.
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.

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PART I — FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS

(dollars in thousands, except share data)		June 30, 2019				December 31, 2018
Assets
Current assets:
Cash and cash equivalents		$	32,648			$	37,446
Accounts receivable, net		52,686				66,087
Inventories, net		4,142				4,059
Prepaid expenses		1,774				2,814
Derivative instruments		4,524				24,025
Total current assets		95,774				134,431
Property and equipment, net		36,265				43,096
Right of use assets from operating leases		9,005				—
Oil and natural gas properties, using the full cost method:
Proved		1,107,203				915,333
Unevaluated (excluded from the amortization base)		426,738				466,616
Accumulated depreciation, depletion, amortization and impairment		(384,401		)		(221,431		)
Total oil and natural gas properties		1,149,540				1,160,518
Derivative instruments		221				2,199
Other assets		411				425
Total assets		$	1,291,216			$	1,340,669
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities		$	73,770			$	73,779
Accrued payroll and benefits payable		7,807				10,976
Accrued interest payable		12,207				13,359
Revenue distribution payable		26,825				26,225
Long-term debt and financing leases, classified as current		11,502				12,371
Derivative instruments		4,802				—
Total current liabilities		136,913				136,710
Long-term debt and financing leases, less current maturities		382,295				295,100
Derivative instruments		9,196				1,542
Noncurrent operating lease obligations		2,075				—
Deferred compensation		693				540
Asset retirement obligations		22,300				22,090
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, 5,000,000 shares authorized, none issued and outstanding		—				—
Common stock, $0.01 par value, 192,130,071 shares authorized; 46,885,198 issued and 46,417,442 outstanding at June 30, 2019 and 46,651,616 issued and 46,390,513 outstanding at December 31, 2018		469				467
Additional paid in capital		977,611				974,616
Treasury stock, at cost, 467,756 and 261,103 shares as of June 30, 2019 and December 31, 2018		(6,107		)		(4,936		)
Accumulated deficit		(234,229		)		(85,460		)
Total stockholders' equity		737,744				884,687
Total liabilities and stockholders' equity		$	1,291,216			$	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

(Unaudited)

 

		Three months ended								Six months ended
(in thousands, except share and per share data)		June 30, 2019				June 30, 2018				June 30, 2019				June 30, 2018
Revenues:
Net commodity sales		$	66,707			$	58,427			$	115,326			$	116,316
Sublease revenue		1,198				1,198				2,396				2,396
Total revenues		67,905				59,625				117,722				118,712
Costs and expenses:
Lease operating		13,371				15,009				25,665				29,552
Production taxes		3,802				2,768				6,682				5,445
Depreciation, depletion and amortization		30,282				20,407				53,997				41,513
Impairment of oil and gas assets		63,593				—				113,315				—
Impairment of other assets		6,407				—				6,407				—
General and administrative		7,315				8,190				15,628				19,697
Cost reduction initiatives		—				824				—				824
Other		403				403				806				1,231
Total costs and expenses		125,173				47,601				222,500				98,262
Operating (loss) income		(57,268		)		12,024				(104,778		)		20,450
Non-operating income (expense):
Interest expense		(5,571		)		(1,739		)		(10,135		)		(3,110		)
Derivative gains (losses)		17,734				(32,286		)		(33,282		)		(48,787		)
Gain (loss) on sale of assets		491				469				490				(575		)
Other (expense) income, net		(302		)		19				(288		)		104
Net non-operating income (expense)		12,352				(33,537		)		(43,215		)		(52,368		)
Reorganization items, net		(313		)		(480		)		(776		)		(1,517		)
Loss before income taxes		(45,229		)		(21,993		)		(148,769		)		(33,435		)
Income tax expense		—				—				—				—
Net loss		$	(45,229	)		$	(21,993	)		$	(148,769	)		$	(33,435	)
Earnings per share:
Basic for Class A and Class B (1)		(0.99		)		(0.49		)		(3.27		)		(0.74		)
Diluted for Class A and Class B (1)		(0.99		)		(0.49		)		(3.27		)		(0.74		)
Weighted average shares used to compute earnings per share:
Basic for Class A and Class B (1)		45,641,797				45,338,650				45,549,518				45,241,513
Diluted for Class A and Class B (1)		45,641,797				45,338,650				45,549,518				45,241,513

  ____________________________________________________________

(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 Statement of Stockholders’ Equity

(Unaudited)

 

		Common stock
(dollars in thousands)		Shares outstanding			Amount				Additional paid in capital				Treasury stock				Accumulated deficit				Total
As of December 31, 2017		46,827,762			$	468			$	961,200			$	—			$	(118,902	)		$	842,766
Stock-based compensation		—			—				5,581				—				—				5,581
Restricted stock forfeited		(83,770	)		(1		)		—				—				—				(1		)
Repurchase of common stock		(63,919	)		—				—				(1,422		)		—				(1,422		)
Net loss		—			—				—				—				(11,442		)		(11,442		)
Balance at March 31, 2018		46,680,073			467				966,781				(1,422		)		(130,344		)		835,482
Stock-based compensation		55,000			—				2,336				—				—				2,336
Restricted stock forfeited		(81,683	)		—				—				—				—				—
Repurchase of common stock		(192,976	)		—				—				(3,450		)		—				(3,450		)
Net loss		—			—				—				—				(21,993		)		(21,993		)
Balance at June 30, 2018		46,460,414			$	467			$	969,117			$	(4,872	)		$	(152,337	)		$	812,375

		Common stock
(dollars in thousands)		Shares outstanding			Amount				Additional paid in capital				Treasury stock				Accumulated deficit				Total
As of December 31, 2018		46,390,513			$	467			$	974,616			$	(4,936	)		$	(85,460	)		$	884,687
Stock-based compensation		94,078			1				1,423				—				—				1,424
Restricted stock forfeited		(97,113	)		(1		)		—				—				—				(1		)
Repurchase of common stock		(80,422	)		—				—				(463		)		—				(463		)
Net loss		—			—				—				—				(103,540		)		(103,540		)
Balance at March 31, 2019		46,307,056			467				976,039				(5,399		)		(189,000		)		782,107
Stock-based compensation		160,400			1				1,249				—				—				1,250
Restricted stock forfeited		—			—				—				—				—				—
Repurchase of common stock		(126,231	)		—				—				(708		)		—				(708		)
Issuance of common stock - litigation settlement		76,217			1				323				—				—				324
Net loss		—			—				—				—				(45,229		)		(45,229		)
Balance at June 30, 2019		46,417,442			$	469			$	977,611			$	(6,107	)		$	(234,229	)		$	737,744

 

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

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Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

 

		Six months ended
(in thousands)		June 30, 2019				June 30, 2018
Cash flows from operating activities
Net loss		$	(148,769	)		$	(33,435	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization		53,997				41,513
Derivative losses		33,282				48,787
Impairment of oil and gas assets		113,315				—
Impairment of other assets		6,407				—
(Gain) loss on sale of assets		(490		)		575
Other		1,621				3,578
Change in assets and liabilities
Accounts receivable		13,584				(7,660		)
Inventories		40				(3,162		)
Prepaid expenses and other assets		1,055				286
Accounts payable and accrued liabilities		(18,389		)		(4,221		)
Revenue distribution payable		600				7,243
Deferred compensation		1,852				6,566
Net cash provided by operating activities		58,105				60,070
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties		(146,434		)		(176,275		)
Proceeds from asset dispositions		857				6,591
Proceeds from (payments on) derivative instruments, net		653				(9,769		)
Net cash used in investing activities		(144,924		)		(179,453		)
Cash flows from financing activities
Proceeds from long-term debt		85,000				116,000
Repayment of long-term debt		(343		)		(243,391		)
Proceeds from Senior Notes		—				300,000
Principal payments under financing lease obligations		(1,445		)		(1,329		)
Payment of debt issuance costs and other financing fees		(20		)		(6,316		)
Treasury stock purchased		(1,171		)		(4,872		)
Net cash provided by financing activities		82,021				160,092
Net (decrease) increase in cash and cash equivalents		(4,798		)		40,709
Cash and cash equivalents, at beginning of period		37,446				27,732
Cash and cash equivalents, at end of period		$	32,648			$	68,441

 

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

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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

Nature of operations

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 include crude oil, natural gas and natural gas liquids.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018 , as amended.

The financial information as of June 30, 2019 , and for the three and six months ended June 30, 2019 and 2018 , is unaudited. The financial information as of December 31, 2018 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2018 . In management’s opinion, such information contains all adjustments considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three and six months ended June 30, 2019 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2019 .

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

Cash and cash equivalents

We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of June 30, 2019 , cash with a recorded balance totaling approximately $29,695 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.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. Accounts receivable consisted of the following:

		June 30, 2019				December 31, 2018
Joint interests		$	25,713			$	31,573
Accrued commodity sales		25,318				30,287
Derivative settlements		1,120				2,092
Other		1,538				3,375
Allowance for doubtful accounts		(1,003		)		(1,240		)
		$	52,686			$	66,087

 

Inventories

Inventories consisted of the following:

		June 30, 2019				December 31, 2018
Equipment inventory		$	3,752			$	3,663
Commodities		569				574
Inventory valuation allowance		(179		)		(178		)
		$	4,142			$	4,059

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Property and equipment, net

Major classes of property and equipment are shown in the following table:

		June 30, 2019				December 31, 2018
Furniture and fixtures		$	520			$	520
Automobiles and trucks		4,712				3,548
Machinery and equipment		21,832				21,482
Office and computer equipment		6,685				6,183
Building and improvements		18,738				18,693
		52,487				50,426
Less accumulated depreciation, amortization and impairment		21,341				12,449
		31,146				37,977
Land		5,119				5,119
		$	36,265			$	43,096

Impairment of other assets. 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 will 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 to write-down the net book value of the property to its fair value based on its market appraisal.

Oil and natural gas properties

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

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

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The costs of unevaluated oil and natural gas properties consisted of the following :

		June 30, 2019				December 31, 2018
Leasehold acreage		$	395,002			$	427,206
Capitalized interest		15,696				11,377
Wells and facilities in progress of completion		16,040				28,033
Total unevaluated oil and natural gas properties excluded from amortization		$	426,738			$	466,616

 

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 June 30, 2019 , and the related PV-10 value, were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC. We recorded ceiling test write-downs to our oil and natural gas properties of $63,593 and $113,315 for the three and six months ended June 30, 2019 , respectively. These losses are reflected in “Impairment of oil and gas assets” in our consolidated statements of operations.

Producer imbalances. We account for natural gas production imbalances using the sales method, whereby we recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at June 30, 2019 , and December 31, 2018 , were immaterial.

Revenue recognition

In May 2014, the Financial Accounting Standards Board ("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”) and adopted by us in 2018. 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.

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

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Revenues:
Oil		$	50,990			$	42,752			$	83,792			$	85,802
Natural gas		10,476				8,390				21,682				17,126
Natural gas liquids		11,025				11,120				20,242				20,711
Gross commodity sales		72,491				62,262				125,716				123,639
Transportation and processing		(5,784		)		(3,835		)		(10,390		)		(7,323		)
Net commodity sales		$	66,707			$	58,427			$	115,326			$	116,316

 

Please see “Note 16: Revenue recognition” in "Item 8. Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of our revenue recognition policy including a description of products and revenue disaggregation criteria, performance obligations, pricing , measurement and contract assets and liabilities.

Income taxes

The provision for income taxes is based on a current estimate of the annual effective income tax rate adjusted to reflect the impact of permanent differences and discrete items. Management judgment is required in estimating operating income in order to determine our effective income tax rate. Our effective income tax rate was 0% and 0% for the three and six months ended June 30, 2019 and 2018, respectively. The consistent effective tax rate for the six months ended June 30, 2019, is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Despite the Company’s net loss for the three and six month period ended June 30, 2019, we did no t record any net deferred tax benefit, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured.

A valuation allowance for deferred tax assets, including net operating losses ("NOLs"), is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset 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.

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 asset is necessary, we likely will not have any additional deferred income tax expense or benefit.

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 June 30, 2019, or December 31, 2018.

As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code ("IRC") Section 382 on March 21, 2017. This ownership change subjected certain of the Company’s tax attributes, including $760,067 of federal net operating loss carryforwards, to an IRC Section 382 limitation. This limitation has not resulted in a current tax liability for the six month period ended June 30, 2019 , or any intervening period since March 21, 2017. If we were to experience an additional “ownership change,” as determined under IRC Section 382, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” at any time during a rolling three-year period. In the event of an ownership change, IRC Section 382 imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards after an ownership change. The limitation is generally equal to the product of (a) the fair market value of the equity of the Company multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are net unrealized built-in gains in the Company’s assets at the time of the ownership change, and those net unrealized built-in gains are recognized during the 60 month recognition period following the ownership change. Future ownership changes or future regulatory changes could limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.

Cost reduction initiatives

These include expenses related to our efforts to reduce our capital, operating and administrative costs in response to industry conditions. The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force.

Other expense

Other expense consisted of the following:

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Restructuring		$	—			$	—			$	—			$	425
Subleases		403				403				806				806
Total other expense		$	403			$	403			$	806			$	1,231

14

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Restructuring . We previously incurred exit costs in conjunction with our EOR asset divestiture, which are predominantly comprised 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 are comprised of CO ₂  compressors that were previously utilized in our EOR operations and leased as both financing and operating leases from U.S. Bank but are now subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and as such we did not record any losses upon initiation of the subleases. Prior to the asset sale, 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. Based on the facts and circumstances relating to our original leases and the current subleases, we determined that all the subleases were to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases in November 2017, all payments received from the Sublessee are reflected as “Sublease revenue” on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as “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 and have amortized the asset on a straight line basis prospectively. We will continue incurring interest expense on the financing leases. Please see “Note 5: Leases” for our disclosure on leases.

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 joint venture STACK wells, subject to average well cost caps that vary by well-type across location and targeted formations, approximately between $3,400 and $4,000 per gross well. The JDA wells, which are drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County. The JDA provided us with a means to accelerate the delineation of our position within our Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and adding reserves. In exchange for funding, BCE received wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retained 15% ) until the program reaches a 14% internal rate of return. Once achieved, a portion of BCE's ownership interest in all JDA wells will revert to us such that we will own a 75% working interest and BCE will retain a 25% working interest. We retained all acreage and reserves outside of the wellbore, with both parties entitled to revenues and paying lease operating expenses based on their working interest.

Our drilling and completion costs to date have been exceeding well cost caps specified under the JDA primarily due to inflation in the cost of oilfield services subsequent to our negotiations in mid-2017 that culminated in our entering into the JDA. In our negotiation with BCE to cover the inflationary cost increases, BCE had indicated willingness to increase the per well cost caps on remaining wells in exchange for adding more wells to the current program. Since we have achieved our goals to utilize the JDA as a means to delineate our acreage Garfield and Canadian counties, Oklahoma, we do not currently plan for any expansion of the JDA. For the six months ended June 30, 2019 , we have therefore recorded additions to oil and natural gas properties of $3,571 in drilling and completion costs on JDA wells that have exceeded the well cost caps specified under the JDA. We have substantially completed all wells under the JDA.

 

Reorganization items

Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business. As a result of our emergence from bankruptcy in March 2017, we have also recorded gains on the settlement of liabilities subject to compromise and gains from restating our balance sheet to fair values under fresh start accounting. “Professional fees” in the table below for periods subsequent to the emergence from bankruptcy are comprised of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed. Reorganization items are as follows:

15

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Loss on the settlement of liabilities subject to compromise		$	—			$	—			$	—			$	48
Professional fees		313				480				776				1,469
Total reorganization items		$	313			$	480			$	776			$	1,517

 

Recently adopted accounting pronouncements

In February 2016, the FASB issued authoritative guidance that supersedes previous lease recognition requirements and requires entities to recognize leases on-balance sheet and disclose key information about leasing arrangements. Please see “Note 5: Leases” for our disclosure regarding adoption of this update.

Recently issued accounting pronouncements

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

16

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 2: Earnings per share

Although we previously had both Class A and Class B common stock outstanding, where both classes of common stock shared equally in voting power, dividends and undistributed earnings, 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.

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

		Three months ended June 30,								Six months ended June 30,
(in thousands, except share and per share data)		2019				2018				2019				2018
Numerator for basic and diluted earnings per share
Net loss		$	(45,229	)		$	(21,993	)		$	(148,769	)		$	(33,435	)
Denominator for basic earnings per share
Weighted average common shares - Basic for Class A and Class B (1)		45,641,797				45,338,650				45,549,518				45,241,513
Denominator for diluted earnings per share
Weighted average common shares - Diluted for Class A and Class B (1)		45,641,797				45,338,650				45,549,518				45,241,513
Earnings per share
Basic for Class A and Class B (1)		$	(0.99	)		$	(0.49	)		$	(3.27	)		$	(0.74	)
Diluted for Class A and Class B (1)		$	(0.99	)		$	(0.49	)		$	(3.27	)		$	(0.74	)
Participating securities excluded from earnings per share calculations
Warrants (2)		—				140,023				—				140,023
Unvested restricted stock units - stock settled		81,119				—				81,119				—
Unvested restricted stock awards		706,821				1,126,669				706,821				1,126,669

________________________________

(1)

Effective December 19, 2018, all our outstanding Class B shares were converted to Class A shares and subsequently, all our outstanding common stock was comprised only of Class A common stock. Earnings per share for the three and six months ended June 30, 2018 reflects earnings per share for Class A and Class B common stock in aggregate whereas earnings per share for the three and six months ended June 30, 2019 reflects earnings per share for Class A common stock.

(2)	The warrants to purchase shares of our Class A common stock are antidilutive for three and six months ended June 30, 2018, 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.

Note 3: Supplemental disclosures to the consolidated statements of cash flows

		Six months ended June 30,
		2019				2018
Net cash provided by operating activities included:
Cash payments for interest		$	16,328			$	5,755
Interest capitalized		(6,613		)		(3,515		)
Cash payments for reorganization items		857				1,551
Non-cash investing activities included:
Asset retirement obligation additions and revisions		386				1,112
Leasing right of use asset additions (see Note 5: Leases)		1,387				—
Change in accrued oil and gas capital expenditures		7,024				15,560

17

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 4: Debt

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

		June 30, 2019				December 31, 2018
8.75% Senior Notes due 2023		$	300,000			$	300,000
Credit Facility		85,000				—
Real estate mortgage note		8,280				8,588
Installment note payable		492				354
Financing lease obligations		11,620				11,677
Unamortized debt issuance costs		(11,595		)		(13,148		)
Total debt, net		393,797				307,471
Less current portion		11,502				12,371
Total long-term debt, net		$	382,295			$	295,100

 

Credit Facility

The Credit Facility is 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 Facility 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 or around May 1 and November 1 of each year. Our borrowing base under the Credit Facility as of June 30, 2019 , was  $325,000 .

As of June 30, 2019 , our outstanding borrowings were accruing interest at the Adjusted LIBO Rate (as defined in the Credit Facility), plus the Applicable Margin (as defined in the Credit Facility), which resulted in a weighted average interest rate of 4.66% .

The Credit Facility contains financial covenants that require, for each fiscal quarter, we maintain: (1) a Current Ratio (as defined in the Credit Facility) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the Credit Facility) of no greater than 4.0 to 1.0 calculated on a trailing four -quarter basis. We were in compliance with these financial covenants as of June 30, 2019 .

The Credit Facility contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Please see “Note 8: Debt” in "Item 8. Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of the material provisions of our Credit Facility.

On May 2, 2019, we entered into the Third Amendment to the Tenth Restated Credit Agreement, among the Company and its subsidiaries, as borrowers, certain financial institutions party thereto, as lenders, and Royal Bank of Canada, as administrative agent (the “Third Amendment”). The Third Amendment, which was effective March 31, 2019, reaffirmed our borrowing base at the same level as it was at the beginning of 2019, at $325,000 .

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 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 Senior Notes contain customary covenants, certain callable provisions and events of default. Please see “Note 8: Debt” in "Item 8. Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of the material provisions of our Senior Notes.

18

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 5: Leases

In February 2016, the FASB established Accounting Standards Codification ("ASC") Topic 842, Leases (“ASC 842”) which 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, 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.

Financing leases

In 2013, we entered into lease financing agreements with U.S. Bank for $24,500 through the sale and subsequent leaseback of existing CO ₂ compressors owned by us. The lease financing obligations are for terms of 84 months 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. There are 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 has not been modified and there have been no triggering events subsequent to our adoption of ASC 842, we have not performed any reassessment of the lease. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8% . Minimum lease payments are approximately $3,181 annually. In conjunction with the sale of our EOR assets, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank.

During 2019, we entered into lease financing agreements for our fleet trucks for $1,387 . We intend to add additional vehicles throughout 2019 under the same fleet leasing arrangement. The lease 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 and nonlease components under these leases.

Operating leases

We also have operating leases for CO ₂ compressors previously deployed in our EOR operations. The operating lease obligations, which we entered into in 2014 and 2016, are for terms of 84 months without any specified purchase options. There are no residual value guarantees and 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 remain the primary obligor in relation to U.S. Bank.

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 for which 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 for which we have elected not to separate from the lease component for this asset class.

Short term leases

Our short term leases are those with lease terms of 12 months or less and are generally comprised 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.

19

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Subleases

As discussed above, our subleases are comprised of CO ₂  compressors that were previously utilized in our EOR operations and leased as both financing and operating leases from U.S. Bank but are now subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and as such we did not record any losses upon initiation of the subleases. Prior to the asset sale, the financing leases were included in our full cost amortization base and as such subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating” expense on our statement of operations. Based on the facts and circumstances relating to our original leases and the current subleases, we determined that all the subleases were to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases in November 2017, all payments received from the Sublessee are reflected as “Sublease revenue” on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as “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 and have amortized the asset on a straight line basis prospectively. We will continue incurring interest expense on the financing leases.

Lease assets and liabilities

Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of June 30, 2019 as follows:

		As of June 30, 2019
		Operating leases				Financing leases
Right of use asset:
Right of use assets from operating leases		$	9,005			$	—
Plant, property and equipment, net (1)		—				11,456
Total lease assets		$	9,005			$	11,456
Lease liability:
Account payable and accrued liabilities		$	6,930			$	—
Long-term debt and financing leases, classified as current		—				10,617
Long-term debt and financing leases, less current maturities		—				1,003
Noncurrent operating lease obligations		2,075				—
Total lease liabilities		$	9,005			$	11,620

________________________________

(1)	CO 2 compressors included in Machinery and equipment and fleet vehicles included in automobiles and trucks. See “Note 1: Nature of operations and summary of significant accounting policies.”

20

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Our income, expenses and cash flows related to our leases is as follows for the three and six months ended June 30, 2019 :

		Three months ended				Six months ended
		June 30, 2019				June 30, 2019
Lease cost
Finance lease cost:
Amortization of right-of-use assets		$	749			$	1,442
Interest on lease liabilities		117				230
Operating lease cost		308				616
Short-term lease cost		154				283
Variable lease cost		95				190
Sublease income		(1,198		)		(2,396		)
Total lease cost		$	225			$	365
Capitalized operating lease cost (1)		$	3,371			$	6,706
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for finance leases		$	(117	)		$	(230	)
Operating cash flows for operating leases		(308		)		(616		)
Investing cash flows for operating leases		(2,965		)		(3,988		)
Financing cash flows for finance leases		(746		)		(1,445		)
Right-of-use assets obtained in exchange for new finance lease liabilities		717				1,387

________________________________

(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.

		As of
		June 30, 2019
Weighted-average remaining lease term - finance leases		0.7 years
Weighted-average remaining lease term - operating leases		1.2 years
Weighted-average discount rate - finance leases		4.08	%
Weighted-average discount rate - operating leases		13.33	%

Our rent expense for the three months and six months ended June 30, 2018 , was $1,098 and $2,066 , 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 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.

21

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Lease maturities

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

		As of June 30, 2019							As of December 31, 2018 (1)
		Operating leases			Financing leases				Operating leases			Financing leases
2019		$	6,877		$	10,633			$	13,890		$	12,332
2020		1,233			392				1,330			—
2021		1,292			392				1,297			—
2022		274			392				278			—
2023		205			116				205			—
Thereafter		—			—				—			—
Total minimum lease payments		9,881			11,925				17,000			12,332
Less: imputed interest		876			305				*			*
Total lease liability		9,005			11,620				*			*
Less: current maturities of lease obligations		6,930			10,617				*			*
Noncurrent lease obligations		$	2,075		$	1,003			*			*

________________________________

(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.

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 6: Derivative instruments

Overview

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

22

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The following table summarizes our crude oil derivatives outstanding as of June 30, 2019 :

					Weighted average fixed price per Bbl
Period and type of contract		Volume MBbls			Swaps				Purchased Puts				Sold Calls
2019
Oil swaps		1,311			$	55.92			$	—			$	—
Oil roll swaps		240			$	0.46			$	—			$	—
2020
Oil swaps		2,007			$	50.56			$	—			$	—
Oil roll swaps		410			$	0.38			$	—			$	—
Oil collars		195			$	—			$	55.00			$	66.42
2021
Oil swaps		689			$	46.24			$	—			$	—
Oil roll swaps		150			$	0.30			$	—			$	—

The following table summarizes our natural gas derivatives outstanding as of June 30, 2019 :

Period and type of contract		Volume BBtu			Weighted average fixed price per MMBtu
2019
Natural gas swaps		7,824			$	2.85
Natural gas basis swaps		4,994			$	(0.59	)
2020
Natural gas swaps		6,000			$	2.75
Natural gas basis swaps		3,600			$	(0.46	)

The following table summarizes our natural gas liquid derivatives outstanding as of June 30, 2019 :

Period and type of contract		Volume Thousands of Gallons			Weighted average fixed price per gallon
2019
Natural gasoline swaps		7,896			$	1.13
Propane swaps		17,472			$	0.61
Butane		4,536			$	0.71
2020
Natural gasoline swaps		4,788			$	1.17
Propane swaps		10,668			$	0.63
Butane		2,352			$	0.71

23

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 7: 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.

		As of June 30, 2019												As of December 31, 2018
		Assets				Liabilities				Net value				Assets				Liabilities				Net value
Natural gas derivative contracts		$	5,240			$	(145	)		$	5,095			$	833			$	(488	)		$	345
Crude oil derivative contracts		2,463				(19,909		)		(17,446		)		24,208				(4,452		)		19,756
NGL derivative contracts		4,138				(1,040		)		3,098				4,581				—				4,581
Total derivative instruments		11,841				(21,094		)		(9,253		)		29,622				(4,940		)		24,682
Less:
Netting adjustments (1)		(7,096		)		7,096				—				(3,398		)		3,398				—
Derivative instruments - current		4,524				(4,802		)		(278		)		24,025				—				24,025
Derivative instruments - long-term		$	221			$	(9,196	)		$	(8,975	)		$	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 relate 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 gains (losses)” in the consolidated statements of operations.

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

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Change in fair value of commodity price derivatives		$	17,596			$	(26,761	)		$	(33,935	)		$	(39,018	)
Settlements received (paid) on commodity price derivatives		138				(5,525		)		653				(9,769		)
Total derivative gains (losses)		$	17,734			$	(32,286	)		$	(33,282	)		$	(48,787	)

 

Note 7: Fair value measurements

Fair value is defined by the 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.

Fair value measurements 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 as follows:

• Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

• Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than

quoted prices that are observable for the asset or liability.

• 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.

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.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Recurring fair value measurements

As of June 30, 2019 , and December 31, 2018 , our financial instruments recorded at fair value on a recurring basis consisted of commodity derivative contracts (see “Note 6: Derivative instruments”). We had no Level 1 assets or liabilities. Our derivative contracts classified as Level 2 consisted of commodity price swaps and oil roll swaps which are valued using an income approach. Future cash flows from the commodity price swaps are estimated based on the difference between the fixed contract price and the underlying published forward market price. Our derivative contracts classified as Level 3 consisted of collars and natural 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 and proprietary pricing curves. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or our counterparty credit risk for derivative assets. 

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

		As of June 30, 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)		$	11,109			$	(20,949	)		$	(9,840	)		$	29,370			$	(4,718	)		$	24,652
Significant unobservable inputs (Level 3)		732				(145		)		587				252				(222		)		30
Netting adjustments (1)		(7,096		)		7,096				—				(3,398		)		3,398				—
		$	4,745			$	(13,998	)		(9,253		)		$	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:

		Six months ended June 30,
Net derivative assets (liabilities)		2019				2018
Beginning balance		$	30			$	(295	)
Realized and unrealized gains (losses) included in derivative losses		441				(990		)
Settlements paid		116				459
Ending balance		$	587			$	(826	)
Gains (losses) relating to instruments still held at the reporting date included in derivative gains (losses) for the period		$	742			$	(678	)

Nonrecurring fair value measurements

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

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

		Six months ended June 30, 2019						Six months ended June 30, 2018
		Low			High			Low			High
Inflation rate (1)		2.25	%		2.25	%		2.26	%		2.26	%
Credit-adjusted risk-free discount rate		12.35	%		14.60	%		6.92	%		8.68	%

________________________________

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

These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 8: Asset retirement obligations” for additional information regarding our asset retirement obligations.

Fair value of other financial instruments

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

The carrying value and estimated fair value of our debt were as follows:

		June 30, 2019								December 31, 2018
Level 2		Carrying value (1)				Estimated fair value				Carrying value (1)				Estimated fair value
8.75% Senior Notes due 2023		$	300,000			$	182,598			$	300,000			$	213,618
Credit Facility		85,000				85,000				—				—
Other secured debt (2)		8,772				8,772				8,942				8,942

________________________________

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

(2)	Comprised of our real estate and equipment installment notes.

The carrying value of our Credit Facility and other secured long-term debt approximates fair value because 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.

Counterparty credit risk

Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our credit facilities at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a Lender, or an affiliate of a Lender, under our credit facilities can be offset against amounts owed to such counterparty Lender. As of June 30, 2019 , the counterparties to our open derivative contracts consisted of eight financial institutions, of which all were lenders under our Credit Facility.

The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our credit facilities that are available to offset our net derivative assets due from counterparties that are lenders under our credit facilities.  

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

		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
June 30, 2019
Derivative assets		$	11,841			$	(7,096	)		$	4,745			$	(887	)		$	(3,858	)		$	—
Derivative liabilities		(21,094		)		7,096				(13,998		)		887				—				(13,111		)
		$	(9,253	)		$	—			$	(9,253	)		$	—			$	(3,858	)		$	(13,111	)
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 relate 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 Facility that is available to offset our net derivative assets due from counterparties that are lenders under our Credit Facility.

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 Facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $21,094 before offsets at June 30, 2019 .

Note 8: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity:

Balance at January 1, 2019	$	23,147
Liabilities incurred in current period	316
Liabilities settled or disposed in current period	(478		)
Revisions in estimated cash flows	70
Accretion expense	713
Balance at June 30, 2019	$	23,768
Less current portion included in accounts payable and accrued liabilities	1,468
Asset retirement obligations, long-term	$	22,300

See “Note 7: Fair value measurements” for additional information regarding fair value assumptions associated with our asset retirement obligations.

Note 9: Deferred compensation

Cash Incentive Plan

We adopted the Long-Term Cash Incentive Plan (the “Cash LTIP”) on August 7, 2015. The Cash LTIP provides additional cash compensation to certain employees of the Company in the form of awards that generally vest in equal annual increments over a four -year period. Since the awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We accrue for the cost of each annual increment over the period service is required to vest. A summary of compensation expense for the Cash LTIP is presented below:

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Cash LTIP expense (net of amounts capitalized)		$	67			$	193			$	158			$	288
Cash LTIP awarded		—				47				—				47
Cash LTIP payments		—				—				—				17

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

 

As of June 30, 2019 , the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $1,622 . Beginning in October 2018, we ceased issuing cash grants under the Cash LTIP plan and instead are issuing restricted stock units ("RSUs") to our employees.

2017 Management Incentive Plan

In 2017, we adopted the Chaparral Energy, Inc. Management Incentive Plan (the “MIP”). The MIP provides for the following types of awards: options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other incentive awards. The aggregate number of shares of Class A common stock, par value $0.01 per share, reserved for issuance pursuant to the MIP was initially set at 3,388,832 subject to changes in the event additional shares of common stock are issued under our Reorganization Plan. The MIP contemplates that any award granted under the plan may provide for the earlier termination of restrictions and acceleration of vesting in the event of a Change in Control, as may be described in the particular award agreement.

Pursuant to the MIP, we have granted restricted stock to executive employees and members of our Board of Directors (the “Board”). Grants awarded to executives are generally comprised of shares for which 75% are subject to service vesting conditions (the “Time Shares”) and 25% are subject to performance or market-based vesting conditions (the “Performance Shares”). All grants to the Board were Time Shares.

Both the Time and Performance Shares are classified as equity-based awards. Compensation cost is generally recognized and measured according to the grant date fair value of the awards which are based on the market price of our common stock for awards with service and performance conditions.

The Time Shares vest in equal annual installments over the three -year vesting period. The Performance Shares vest in three tranches annually according to performance or market-based conditions established each year which generally relate to profitability, stock returns, drilling results and other strategic goals.

Vesting conditions for Performance Shares vesting in 2019 were established and approved by our Board in March 2019 and we have commenced recognizing expense for the related shares in the first quarter of 2019. Our Board established that all Performance Shares scheduled to vest in 2019 shall be subject to a market condition that is based on our stock return relative to a group of peer companies. Expense on these awards is based on a fair value that incorporates the probability of vesting. We utilized a Monte Carlo simulation to estimate the fair value of the market based award. The simulation utilized a risk free rate of  2.52%  and volatility of  64.1%  to arrive at a fair value of $ 4.66  per restricted share. These inputs are considered to be Level 3 inputs within the fair value hierarchy.

A summary of our restricted stock activity pursuant to our MIP is presented below:

		Time Shares											Performance Shares
		Weighted average award date fair value				Restricted shares			Vest date fair value				Weighted average award date fair value				Restricted shares
		($ per share)											($ per share)
Unvested and outstanding at January 1, 2019		$	20.06			818,206							$	20.12			125,528
Granted		$	6.94			198,378							$	6.74			55,000
Vested		$	20.00			(393,178	)		$	2,319			$	—			—
Forfeited		$	20.05			(73,515	)						$	20.05			(23,598	)
Unvested and outstanding at June 30, 2019		$	15.36			549,891							$	15.44			156,930

Beginning in October 2018, we have issued RSUs under our MIP to certain non-executive employees in lieu of cash awards. 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. These awards, which are service-based, will vest in equal installments over a  3 year period. See “Note 1: Nature of operations and summary of significant accounting policies” in "Item 8 Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of accounting policies regarding our RSUs.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

A summary of our RSU activity is presented below:

		Stock-settled RSUs							Cash-settled RSUs
		Weighted average award date fair value				Restricted units			Weighted average award date fair value				Restricted units
		($ per share)							($ per share)
Unvested and outstanding at January 1, 2019		$	17.66			89,633			$	17.66			37,196
Granted		$	—			—			$	6.37			1,570
Forfeited		$	17.66			(8,514	)		$	17.66			(5,394	)
Unvested and outstanding at June 30, 2019		$	17.66			81,119			$	17.13			33,372

Companywide stock award

Historically, new employees were eligible for a grant of 100 shares subsequent to being employed for a certain period of time. There are no vesting requirements for these awards and thus compensation is recognized in full on the award date based on the closing price of our common stock on that date. During the six months ended June 30, 2019 , 1,100 shares were awarded to new employees under this program.

Stock-based compensation cost

Compensation cost is calculated net of forfeitures. We recognize the impact of forfeitures due to employee terminations in expense 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. For awards with market conditions, expense is recognized on the entire value of the award regardless of the vesting outcome so long as the participant remains employed.

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:

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Stock-based compensation cost		$	1,260			$	2,335			$	2,720			$	7,915
Less: stock-based compensation cost capitalized		(399		)		(664		)		(1,025		)		(1,621		)
Stock-based compensation expense		$	861			$	1,671			$	1,695			$	6,294
Number of vested shares repurchased		126,231				192,976				206,653				256,895
Payments for stock-based compensation		$	708			$	3,449			$	1,171			$	4,872

Based on a quarter end market price of $4.71 per share of our Class A common stock, the aggregate intrinsic value of all restricted shares and stock settled RSUs outstanding was $3,711 as of June 30, 2019 . The repurchases of shares and associated payments disclosed above were primarily for tax withholding and tax liabilities and are reflected as treasury stock transactions on our consolidated statements of stockholders’ equity. As of June 30, 2019 , and December 31, 2018 , accrued payroll and benefits payable included for stock-based compensation costs expected to be settled within the next twelve months were $43 and $17 , respectively, all of which relates to our cash-settled RSUs. Unrecognized stock-based compensation cost of approximately $4,455 as of June 30, 2019 , is expected to be recognized over a weighted-average period of 1.2 years .

Note 10: Commitments and contingencies

Standby letters of credit (“Letters”) available under our Credit Facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had Letters outstanding totaling $869 as of each of June 30, 2019 and December 31, 2018 . When amounts under the Letters are paid by the lenders, interest accrues on the amount paid at the

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

same interest rate applicable to borrowings under the Credit Facility. No amounts were paid by the lenders under the Letters; therefore, we paid no interest on the Letters during the six months ended June 30, 2019 or 2018 .

Litigation and Claims

Chapter 11 Proceedings.  Commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016 (“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 which 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 prior to the Petition Date and 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. Of the total alleged dollar amount of claims still unresolved, the large majority, as measured by the alleged amount of such claims, is comprised of claims from the Naylor Farms case described below. If the Bankruptcy Court were to allow the remaining unresolved proofs of claims from any of these cases, the Company, pursuant to the Plan of Reorganization, would be required to issue additional shares to the holders of such allowed proofs of claim, 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 would be comprised 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 (the “Tenth Circuit”).

In addition to filing claims on behalf of the named and putative plaintiffs, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of  $150,000 in our Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90,000 inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims, to which we will also object. On June 7, 2017 we appealed the Bankruptcy Court order to the United States District Court for the District of Delaware.

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

Lacheverjuan Bennett et al. v. Chaparral Energy, L.L.C., et al.   On March 26, 2018, a group of  twenty-seven  individual plaintiffs filed a lawsuit in the District Court of Logan County, State of Oklahoma against  twenty-three  named defendants, including us, and  twenty-five  unnamed defendants. Plaintiffs are all property owners and residents of Logan County, Oklahoma, and allege the

30

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

defendants, all oil and gas companies which have engaged in injection well operations, induced earthquakes which have caused damage to real and personal property, and caused emotional damages. Plaintiffs claim absolute liability for ultra-hazardous activities, negligence, gross negligence, public and private nuisance, and trespass, and ask for compensatory and punitive damages, and attorney fees and costs. We have filed a motion to dismiss the lawsuit which we expect the court to consider during the third quarter of 2019. In the meantime, we will vigorously defend the case.

Hallco Petroleum, Inc. v. Chaparral Energy, L.L.C.  On November 7, 2017, Hallco Production, LLC (“Hallco”) filed a lawsuit against us in the District Court of Kay County, State of Oklahoma. Plaintiffs alleged carbon dioxide which was injected for enhanced oil recovery in wells operated by us in the North Burbank Unit migrated to wells operated by Hallco, damaging its salt water disposal well and therefore preventing operation of, and production from, all wells on Hallco’s lease. Plaintiffs allege the migration of carbon dioxide constituted trespass, and further allege negligence and nuisance. Plaintiff seeks actual damages in excess of   $75 , plus punitive damages in an unspecified amount. Because we sold the EOR wells on November 17, 2017, Hallco filed an amended petition on March 6, 2018 to add the purchaser, Perdure Petroleum, LLC, as an additional defendant in the lawsuit. Plaintiff claims the damage is ongoing. We dispute the plaintiff’s claims, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case.

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, quiet title actions, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. These proceedings may include allegations of damages from induced earthquakes, which we will vigorously defend as necessary. 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.

Contractual obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, financing leases and purchase obligations. Our operating leases include leases for drilling rigs, which have terms of up to 15 months , and leases on CO ₂ recycle compressors, which have terms of seven years . Aside from operating leases, we also have financing leases for our CO ₂ recycle compressors and fleet vehicles. In conjunction with the sale of our EOR assets, all our leased CO ₂ compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank, the originating lessor. The subleases are structured such that the lease payments and remaining lease term are identical to the original leases. As of June 30, 2019, other than additional borrowings under our Credit Facility and our new leases for fleet vehicles (see "Note 5: Leases"), we did not have material changes to our contractual commitments since December 31, 2018.

Note 11: Subsequent events

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. Conditioned upon closing of this sale, we entered into a leaseback agreement with the buyer for approximately half of the office space in our headquarters building for a period of two years . We expect to receive consideration of $11,600 from the buyer upon closing of the sale which is not significantly different from the carrying value of the property. We anticipate utilizing the expected proceeds from this divestiture to pay off the outstanding balance of the real estate mortgage note upon closing.

On July 31, 2019, we executed a workforce reduction as part of a cost reduction strategy to better align our business with the current operating environment and drive long-term value. We expect to incur a one-time charge of approximately $968 during the third quarter of 2019 on severance costs for employees affected by the workforce reduction.

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ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF   FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis is intended to assist in understanding our financial condition and results of operations for the three and six months ended June 30, 2019 and 2018 . The information should be read in conjunction with our unaudited consolidated financial statements and the notes thereto included in this quarterly report as well as the information included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 .

Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For more information, see “Cautionary Note Regarding Forward-Looking Statements.”

Overview

Chaparral Energy (NYSE: CHAP) is an independent oil and natural gas exploration and production company headquartered in Oklahoma City. Founded in 1988, Chaparral is a pure-play operator focused in Oklahoma’s highly economic STACK/Merge Play, where it has approximately 130,000 net acres primarily in Kingfisher, Canadian and Garfield counties. The Company has approximately 221,000 net surface acres in the Mid-Continent region. Beginning in the early 1990s, our operations in the area later to become known as the STACK were focused on vertical wells and waterfloods. Since late 2013, however, we have concentrated on the horizontal development of the Mississippian-age Osage and Meramec formations, Devonian-age Woodford Shale formation as well as the Pennsylvanian-age Oswego formation.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles (“GAAP”) requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and natural gas reserves. We use the full cost method of accounting for our oil and natural gas activities.

Our December 31, 2018 , reserve estimates reflect that our production rate on current proved developed properties will decline at annual rates of approximately 25%, 17%, and 13% 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.

Highlights

Our financial and operating performance in the second quarter of 2019 includes the following highlights and notable developments:

•

We grew net production from our STACK play to 2,165 MBoe and 3,599 MBoe for the three and six months ended June 30, 2019 , respectively, representing increases of 80% and 56% from the prior year periods. Total net production was 2,574 MBoe and 4,448 MBoe for the three and six months ended June 30, 2019 , respectively, representing increases of 43% and 26% , compared to net production for the prior year periods.

•	We lowered our lease operating expense from $8.36 /Boe to $5.19 /Boe, a decrease of 38% from the prior year quarter, primarily driven by production growth in our lower-cost STACK play and divestitures of certain non-core assets in 2018, which were assets characterized by higher operating costs compared to our STACK assets.

•	We brought online 40 new gross operated wells during the first half of the year, seven of which were part of our joint drilling program discussed below.

•	Our oil and natural gas capital expenditures for the six months ended June 30, 2019 , was $152.5 million , with $130.5 million incurred for drilling and completions and $5.7 million on acquisitions.

•	We incurred a net loss for the three months ended June 30, 2019 , of $45.2 million driven primarily by a ceiling impairment of $63.6 million which was partially offset by $17.6 million in non-cash mark-to-market gains on our commodity derivative instruments.

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Capital development

We incurred capital expenditures of $152.5 million for the six months ended June 30, 2019 , of which $130.5 million was for drilling and completions, which included completing and producing seven wells drilled in the prior year, drilling, completing and producing 26 wells, drilling five wells scheduled to be completed subsequent to June 30, 2019 , and participating in wells operated by others. The $130.5 million of expenditure for drilling and completions includes $5.2 million for participating in wells operated by others. These wells do not include wells under our joint development agreement which we discuss below. We were operating four horizontal drilling rigs in the STACK early in the year and reduced to three rigs by the end of March 2019, which we expect to maintain for the remainder of the year. Our capital expenditures for the six months ended June 30, 2019 also includes $5.7 million on acquisitions of which $0.6 million were for nonmonetary acreage trades. We currently expect capital expenditures to be in the range of $260 million to $285 million for the full year 2019. Our 2019 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital that we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated wells, our drilling results, other opportunities that may become available to us and our ability to obtain capital.

Joint development agreement

In 2017, we entered into a joint development agreement (“JDA”) with BCE Roadrunner, LLC, a wholly-owned subsidiary of Bayou City Energy (“BCE”), pursuant to which BCE funded 100 percent of our drilling, completion and equipping costs associated with 30 STACK wells. The provisions of the JDA are described more fully in “Note 1: Nature of operations and summary of significant accounting policies” in "Item 1. Financial Statements" of this report. During the six months ended June 30, 2019 , we drilled, completed and produced three wells and completed and produced four wells drilled in the prior year. As of June 30, 2019 , we have substantially completed the joint development agreement.

Price uncertainty and the full-cost ceiling impairment

Energy commodity prices are volatile and a decline in commodity prices negatively impacts our revenues, profitability, cash flows, liquidity, and reserves, which could lead us to consider reductions in our capital program, asset sales or organizational changes.

We mitigate the effects of volatility in commodity prices primarily by working to make our overall cost structure competitive and supportive in a low price environment. In addition, we maintain flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility. We also deal with price volatility by hedging a substantial portion of our expected future oil, natural gas and natural gas liquids production to reduce our exposure to commodity price decreases.  We currently have derivative contracts in place for a portion of production from 2019 through 2021 as disclosed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." The prices we receive for our oil, natural gas and natural gas liquids production affect our: (i) cash flow available for capital expenditures, (ii) ability to borrow and raise additional capital, (iii) ability to service debt, (iv) quantity of oil and natural gas we can produce, (v) quantity of oil and natural gas reserves, and (vi) operating results for oil and natural gas activities.

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 $63.6 million and $113.3 million for the three and six months ended June 30, 2019 primarily due to a decrease in the price used to estimate our reserves as disclosed in the table below. If commodity prices remain at their current level or decline, we expect the trailing 12-month average price to decline as we progress through 2019 and we believe that it is probable that we would record further ceiling test impairment losses in 2019. In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. Please see “Note 1: Nature of operations and summary of significant accounting policies” in "Item 1. Financial Statements" of this report for further discussion of our ceiling test.

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Benchmark prices utilized in ceiling test		June 30, 2019				March 31, 2019				December 31, 2018
Oil (per Bbl)		$	61.39			$	63.06			$	65.56
Natural gas (per MMbtu)		$	3.02			$	3.07			$	3.10
Natural gas liquids (per Bbl)		$	22.71			$	24.60			$	25.56

Results of operations

Production

Production volumes by area were as follows (MBoe):

		Three months ended June 30,						Six months ended June 30,
		2019			2018			2019			2018
STACK Areas:
STACK - Kingfisher County		646			533			1,251			1,210
STACK - Canadian County		1,125			347			1,601			596
STACK - Garfield County		343			260			639			405
STACK - Other		51			61			108			97
Total STACK Areas		2,165			1,201			3,599			2,308
Other		409			594			849			1,224
Total		2,574			1,795			4,448			3,532

Our total net production of 2,574 MBoe and 4,448 MBoe for the three and six months ended June 30, 2019 , respectively, increased approximately 43% and 26% , compared to net production for the prior year periods. The increases were primarily a result of production growth in our STACK Area. Net production from our STACK play was 2,165 MBoe and 3,599 MBoe for the three and six months ended June 30, 2019 , respectively, an increase of 80% and 56% from the prior year periods. This pattern of growth underscores our sole focus on developing the STACK which includes bringing online 65 gross (48 net) operated new wells in the area in the last 12 months.

Production growth during the second quarter of 2019 benefited from the timing of wells coming online as a result of our development strategy, which included full and partial section development. However, as a result of larger pads, the schedule of future wells coming online and additional full section development, the overall timing of our production growth may be uneven from quarter to quarter.

Revenues and transportation and processing

Our commodity sales are derived from the production and sale of oil, natural gas and natural gas liquids. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Commodity sales (in thousands):
Oil		$	50,990			$	42,752			$	83,792			$	85,802
Natural gas		10,476				8,390				21,682				17,126
Natural gas liquids		11,025				11,120				20,242				20,711
Gross commodity sales		$	72,491			$	62,262			$	125,716			$	123,639
Transportation and processing		(5,784		)		(3,835		)		(10,390		)		(7,323		)
Net commodity sales		$	66,707			$	58,427			$	115,326			$	116,316
Production:
Oil (MBbls)		873				645				1,491				1,342
Natural gas (MMcf)		5,715				4,164				10,189				7,952
Natural gas liquids (MBbls)		749				456				1,259				865
MBoe		2,574				1,795				4,448				3,532
Average daily production (Boe/d)		28,286				19,725				24,576				19,514
Average sales prices (excluding derivative settlements):
Oil per Bbl		$	58.41			$	66.28			$	56.20			$	63.94
Natural gas per Mcf		$	1.83			$	2.01			$	2.13			$	2.15
NGLs per Bbl		$	14.72			$	24.39			$	16.08			$	23.94
Transportation and processing per Boe		$	(2.25	)		$	(2.14	)		$	(2.34	)		$	(2.07	)
Average sales price per Boe		$	25.92			$	32.55			$	25.93			$	32.93

Our gross commodity sales (excludes transportation and processing deductions) of $72.5 million and $125.7 million for the three and six months ended June 30, 2019 , respectively, increased approximately 16% and 2% compared to gross commodity sales for the prior year periods. The increases for both the three months and six months ended June 30, 2019 , compared to the prior year periods are due to volume increases partially offset by price decreases on all three commodities. The table below discloses the impact of price and production volume changes on our revenues.

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		Three months ended June 30, 2019 vs. 2018							Six months ended June 30, 2019 vs. 2018
(in thousands)		Sales change				Percentage change in sales			Sales change				Percentage change in sales
Change in oil sales due to:
Prices		$	(6,874	)		(16.1	)%		$	(11,537	)		(13.4	)%
Production		15,112				35.4	%		9,527				11.1	%
Total change in oil sales		$	8,238			19.3	%		$	(2,010	)		(2.3	)%
Change in natural gas sales due to:
Prices		$	(1,032	)		(12.3	)%		$	(254	)		(1.5	)%
Production		3,118				37.2	%		4,810				28.1	%
Total change in natural gas sales		$	2,086			24.9	%		$	4,556			26.6	%
Change in natural gas liquids sales due to:
Prices		$	(7,241	)		(65.2	)%		$	(9,901	)		(47.8	)%
Production		7,146				64.3	%		9,432				45.5	%
Total change in natural gas liquids sales		$	(95	)		(0.9	)%		$	(469	)		(2.3	)%

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 $2.25 /Boe and $2.34 /Boe for the three and six months ended June 30, 2019 , respectively, representing increases of 5% and 13% compared to the prior year periods. Transportation and processing rates were higher driven by production growth in our STACK area where we have experienced higher transportation and processing costs compared to our other operating areas. Transportation and processing contracts related to our recent development in the STACK are fee-based and we are experiencing a larger proportion of gas production subject to fee based processing arrangements as opposed to percentage of proceeds arrangements typically associated with our legacy properties.

 

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 have entered into various types of derivative instruments, including commodity price swaps and costless collars.

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.

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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:

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Oil (per Bbl):
Before derivative settlements		$	58.41			$	66.28			$	56.20			$	63.94
After derivative settlements		$	56.13			$	57.38			$	55.54			$	56.80
Post-settlement to pre-settlement price		96.1		%		86.6		%		98.8		%		88.8		%
Natural gas liquids (per Bbl):
Before derivative settlements		$	14.72			$	24.39			$	16.08			$	23.94
After derivative settlements		$	16.08			$	24.46			$	17.33			$	23.98
Post-settlement to pre-settlement price		109.2		%		100.3		%		107.8		%		100.2		%
Natural gas (per Mcf):
Before derivative settlements		$	1.83			$	2.01			$	2.13			$	2.15
After derivative settlements		$	2.03			$	2.06			$	2.28			$	2.13
Post-settlement to pre-settlement price		110.9		%		102.5		%		107.0		%		99.1		%

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

(in thousands)		June 30, 2019				December 31, 2018
Derivative (liabilities) assets:
Crude oil derivatives		$	(17,446	)		$	19,756
Natural gas derivatives		5,095				345
NGL derivatives		3,098				4,581
Net derivative (liabilities) assets		$	(9,253	)		$	24,682

The effects of derivative activities on our results of operations and cash flows were as follows:

		Three months ended June 30,
		2019								2018
(in thousands)		Non-cash fair value adjustment				Settlements (paid) received				Non-cash fair value adjustment				Settlements (paid) received
Derivative gains (losses):
Crude oil derivatives		$	11,466			$	(1,991	)		$	(24,347	)		$	(5,742	)
Natural gas derivatives		4,889				1,113				(421		)		182
NGL derivatives		1,241				1,016				(1,993		)		35
Derivative gains (losses)		$	17,596			$	138			$	(26,761	)		$	(5,525	)

		Six months ended June 30,
		2019								2018
(in thousands)		Non-cash fair value adjustment				Settlements (paid) received				Non-cash fair value adjustment				Settlements (paid) received
Derivative (losses) gains:
Crude oil derivatives		$	(37,203	)		$	(980	)		$	(36,776	)		$	(9,582	)
Natural gas derivatives		4,750				52				(249		)		(222		)
NGL derivatives		(1,482		)		1,581				(1,993		)		35
Derivative (losses) gains		$	(33,935	)		$	653			$	(39,018	)		$	(9,769	)

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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” in our 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 to changes in our outstanding derivative contracts during these periods.

Lease operating expenses

		Three months ended June 30,								Six months ended June 30,
(in thousands, except per Boe data)		2019				2018				2019				2018
Lease operating expenses:
STACK Areas		$	8,445			$	6,370			$	15,559			$	12,318
Other		4,926				8,639				10,106				17,234
Total lease operating expenses		$	13,371			$	15,009			$	25,665			$	29,552
Lease operating expenses per Boe:
STACK Areas		$	3.90			$	5.30			$	4.32			$	5.34
Other		$	12.04			$	14.54			$	11.90			$	14.08
Lease operating expenses per Boe		$	5.19			$	8.36			$	5.77			$	8.37

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

LOE for the three and six months ended June 30, 2019 was $13.4 million and $25.7 million , respectively, a decrease of 11% and 13% compared to the prior year periods. These decreases were due to the divestiture of high-cost non-core assets in 2018 partially offset by LOE increases in the STACK where we are growing production. LOE per Boe of $5.19 was 38% lower than the prior year quarter primarily as a result of the divestitures and the STACK growth described above. LOE per Boe of $3.90 in our STACK Areas was 26% lower compared to the prior year quarter as a result of a decrease in water hauling costs in certain areas of the STACK as pipeline infrastructure is expanded into the area and contract rates are locked in, as well as reduced costs for well maintenance. These same factors attributed to the 19% decrease in LOE per Boe for the six months ended June 30, 2019, compared to the prior year period.

Production taxes (which include severance and ad valorem taxes)

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Production taxes (in thousands)		$	3,802			$	2,768			$	6,682			$	5,445
Production taxes per Boe		$	1.48			$	1.54			$	1.50			$	1.54
Production taxes as % of commodity sales		5.2		%		4.4		%		5.3		%		4.4		%

Production taxes for the three and six months ended June 30, 2019 , of $3.8 million and $6.7 million , respectively, were 37% and 23% higher than the prior year periods. The increases were a result of the legislative tax increases discussed below. Production taxes on a per Boe basis did not increase despite the legislative rate increases due to price decreases on all three commodities.

In March 2018, the Oklahoma legislature approved a production tax increase from 2% to 5% during the first three years of production on horizontal wells spudded after July 1, 2015. The production tax rate on any new well is currently 5% of commodity revenues for the first 36 months and 7% thereafter.

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Depreciation, depletion and amortization (“DD&A”)

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
DD&A (in thousands):
Oil and natural gas properties (1)		$	28,488			$	18,182			$	50,369			$	36,641
Property and equipment		1,794				2,225				3,628				4,872
Total DD&A		$	30,282			$	20,407			$	53,997			$	41,513
DD&A per Boe:
Oil and natural gas properties (1)		$	11.07			$	10.13			$	11.32			$	10.37
Other fixed assets		0.69				1.24				0.82				1.38
Total DD&A per Boe		$	11.76			$	11.37			$	12.14			$	11.75

_________________________________________

(1)	Includes accretion of asset retirement obligations

We adjust our DD&A rate on oil and natural gas properties each quarter for changes in our estimates of oil and natural gas reserves and costs. Oil and natural gas DD&A for the three and six months ended June 30, 2019 , of $28.5 million and $50.4 million , respectively, was 57% and 37% higher than the prior year periods due to higher production and a higher DD&A rate.

General and administrative expenses (“G&A”)

		Three months ended June 30,								Six months ended June 30,
(in thousands)		2019				2018				2019				2018
G&A:
Gross G&A expenses		$	9,836			$	11,051			$	20,871			$	24,985
Capitalized exploration and development costs		(2,521		)		(2,861		)		(5,243		)		(5,288		)
Net G&A expenses		7,315				8,190				15,628				19,697
Cost reduction initiatives		—				824				—				824
Net G&A expenses and cost reduction initiatives		7,315				9,014				15,628				20,521
Net G&A expense per Boe		$	2.84			$	4.56			$	3.51			$	5.58
Net G&A and cost reduction initiatives per Boe		$	2.84			$	5.02			$	3.51			$	5.81

  Net G&A of $7.3 million and $15.6 million for the three and six months ended June 30, 2019 , respectively, decreased 11% and 21% from the prior year periods primarily due to lower stock based compensation expense partially offset by one-time severance costs associated with the departure of certain company officers as disclosed in the table below.

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to industry conditions. The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force.

		Three months ended June 30,								Six months ended June 30,
(in thousands)		2019				2018				2019				2018
Officer severance costs		$	—			$	—			$	1,058			$	—
Stock compensation, gross		1,228				2,335				2,647				7,915
		$	1,228			$	2,335			$	3,705			$	7,915

Stock compensation expense was lower for the three and six months ended June 30, 2019 , compared to the prior year periods because our executive stock grants are front loaded for three-year periods and subject to accelerated cost recognition which results in higher expense early during the life of a grant with graded vesting. In addition, stock compensation expense was lower for the six months ended June 30, 2019, compared to the prior year period as a result of forfeitures that occurred early in the year.

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Other expense

Other expense consists of the following (in thousands):

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Restructuring		$	—			$	—			$	—			$	425
Subleases		403				403				806				806
Total other expense		$	403			$	403			$	806			$	1,231

Restructuring expense. We previously incurred exit costs in conjunction with our EOR asset divestiture, which are predominantly comprised 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 are comprised of CO ₂  compressors that were previously utilized in our EOR operations and leased as both financing and operating leases from U.S. Bank but are now subleased to the purchaser of our EOR assets (the “Sublessee”).Please see “Note 5: Leases” in "Item 1. Financial Statements" of this report for further discussion of our leases.

Impairment of other assets

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 will 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 $6.4 million to write-down the net book value of the property to its fair value based on its market appraisal.

Income taxes

We did not record any net deferred tax benefit for the three months ended June 30, 2019, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured. Please see “Note 12: Income Taxes” in "Item 8. Financial Statement and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2018, which contains additional information about our income taxes.

As a result of the Chapter 11 reorganization and related transactions, upon emergence from bankruptcy, we experienced an ownership change within the meaning of IRC Section 382 which subjected certain of the Company’s tax attributes, including our federal net operating loss carryforwards, to an IRC Section 382 limitation. If we were to experience an additional “ownership change,” our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. See "Note 1: Nature of operations and summary of significant accounting policies" in "Item 1. Financial Statements" of this report for our discussion of the Section 382 limitation.

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Other income and expenses

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

		Three months ended June 30,								Six months ended June 30,
(in thousands)		2019				2018				2019				2018
Credit Facility		$	838			$	2,914			$	988			$	5,118
Senior Notes		6,562				146				13,125				146
Bank fees, other interest and amortization of issuance costs		1,292				673				2,635				1,361
Interest expense, gross		8,692				3,733				16,748				6,625
Capitalized interest		(3,121		)		(1,994		)		(6,613		)		(3,515		)
Total interest expense		$	5,571			$	1,739			$	10,135			$	3,110
Average borrowings		$	391,405			$	243,815			$	362,557			$	230,625

Interest expense for the three and six months ended June 30, 2019 , was $5.6 million and $10.1 million , respectively, which was higher than the prior year periods, due to an increase in gross interest expense partially offset by an increase in capitalized interest. Gross interest expense was higher primarily due to a larger balance of outstanding debt, as disclosed in the average borrowings in the table above, coupled with an increase in the effective interest rate on our indebtedness. Our Senior Notes, which comprised the majority of our debt during 2019, carries a significantly higher interest rate compared to the interest rate on our Credit Facility, which comprised the majority of our debt in the prior year period. Capitalized interest for the three and six months ended June 30, 2019 of $3.1 million and $6.6 million , respectively, increased compared to the prior year periods due the aforementioned higher effective interest rate and a larger average balance in unevaluated non-producing leasehold. As a result of applying fresh start accounting upon our emergence from bankruptcy in March 2017, 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.

Reorganization items

Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business. As a result of our emergence from bankruptcy, we have also recorded gains on the settlement of liabilities subject to compromise and gains from restating our balance sheet to fair values under fresh start accounting. Our reorganization items are presented below:

		Three months ended June 30,								Six months ended June 30,
		2019				2018				2019				2018
Loss on the settlement of liabilities subject to compromise		$	—			$	—			$	—			$	48
Professional fees		313				480				776				1,469
Total reorganization items		$	313			$	480			$	776			$	1,517

“Professional fees” in the table above is comprised of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed.

Liquidity and capital resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our revolving credit facility or issuance of debt and proceeds from hedge settlements. Additionally, in recent years, asset dispositions and our joint development arrangement have provided a source of cash flow for enhancing liquidity.

Our business strategy requires that we continuously commit substantial investment to drill and develop our oil and natural gas properties such that production from new wells can offset the natural production decline from existing wells. During the past three years, cash flows from operations have been insufficient to fully fund our capital programs and were funded by borrowings and cash on hand.

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As of June 30, 2019 , our cash balance was $32.6 million and the amount outstanding under our Credit Facility was $85.0 million . Availability under our Credit Facility is subject to financial covenants, discussed below, and borrowing base redeterminations conducted semi-annually on or around May 1 and November 1, or upon occurrence of certain specified events. We continuously monitor our liquidity needs, coordinate our capital expenditure program with our expected cash flows, and evaluate our available alternative sources of liquidity. We believe that we have sufficient liquidity to fund our capital expenditures and day to day operations at a minimum for the next 12 months.

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

We mitigate the impact of volatility in commodity prices, in part through the use of derivative instruments which help stabilize our cash flow. We currently have derivative contracts in place for a portion of our oil, natural gas and natural gas liquids production from 2019 through 2021 (see "Item 3. Quantitative and Qualitative Disclosures About Market Risk").

Sources and uses of cash

Our net change in cash is summarized as follows:

		Six months ended June 30,
(in thousands)		2019				2018
Cash flows provided by operating activities		$	58,105			$	60,070
Cash flows used in investing activities		(144,924		)		(179,453		)
Cash flows provided by financing activities		82,021				160,092
Net (decrease) increase in cash during the period		$	(4,798	)		$	40,709

Our cash flows from operating activities is derived substantially from the production and sale of oil and natural gas. Cash flows from operating activities for the six months ended June 30, 2019 , of $58.1 million , was marginally lower compared to the prior year. The decrease was primarily due to higher cash interest payments due to the timing of coupon payments on our Senior Notes partially offset by lower cash operating costs and changes in working capital.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. During 2019, we also relied on borrowings from our Credit Facility and cash on hand to fund our capital expenditures.

Our cash flows from investing activities is typically comprised primarily of cash outflows for capital expenditures, cash inflows from asset dispositions and derivative settlement payments or receipts.

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Our actual costs incurred, including costs that we have accrued for during the six months ended June 30, 2019 , are summarized in the table below.

		Six months ended June 30, 2019
(in thousands)		STACK				Other				Total
Acquisitions (1)		$	5,746			$	—			$	5,746
Drilling (2)		130,519				—				130,519
Enhancements		3,549				1,476				5,025
Operational capital expenditures incurred		139,814				1,476				141,290
Other (3)		—				—				11,177
Total capital expenditures incurred		$	139,814			$	1,476			$	152,467

  ______________________________________________________

(1)	Includes $0.6 million of nonmonetary acreage trades.

(2)	Includes  $5.2 million  on development of wells operated by others and  $12.0 million  on our joint development agreement. Of the  $12.0 million incurred on our joint development program,  $3.6 million was incurred on costs that were in excess of the well cost caps specified under the agreement as a result of inflation and  $8.4 million  was incurred to acquire additional working interests.

(3)	For the six months ended June 30, 2019 , this amount includes $5.2 million  for capitalized general and administrative expenses, and $6.6 million  for capitalized interest.

Net cash used in investing activities during the six months ended June 30, 2019 was comprised of cash outflows for capital expenditure of $146.4 million partially offset by receipts for derivative settlements of $0.7 million     and proceeds from asset sales of $0.9 million . Net cash used in investing activities during the six months ended June 30, 2018, was comprised of cash outflows for capital expenditure of $176.3 million and payments for derivative settlements of $9.8 million partially offset by proceeds from asset divestitures of $6.6 million. Capital expenditures during the six months ended June 30, 2018, included the closing payment of $54.8 million on our 7,000 acre leasehold purchase in January 2018. 

Net cash from financing activities during the six months ended June 30, 2019 , was comprised of borrowings on our Credit Facility of $85.0 million partially offset by cash outflows for repayment of debt and financing leases of $1.8 million and for treasury stock repurchases of $1.2 million . Net cash from financing activities during the six months ended June 30, 2018 , was comprised of cash inflows from the issuance of our Senior Notes of $300.0 million and from borrowings on our New Credit Facility of $116.0 million partially offset by cash outflows for repayment of debt and capital leases of $244.7 million, for debt financing costs of $6.3 million and for treasury stock repurchases of $4.9 million.

Indebtedness

Debt consists of the following as of the dates indicated:

(in thousands)		June 30, 2019				December 31, 2018
8.75% Senior Notes due 2023		$	300,000			$	300,000
Credit Facility		85,000				—
Real estate mortgage notes		8,280				8,588
Financing lease obligations		11,620				11,677
Installment note payable		492				354
Unamortized issuance costs		(11,595		)		(13,148		)
Total debt, net		$	393,797			$	307,471

Credit Facility

The Credit Facility is a $750.0 million facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our Credit Facility is subject to financial covenants (see "Note 4: Debt" in "Item 1. Financial Statements" of this report) and 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 of June 30, 2019 , our borrowing base on the Credit Facility was $325.0 million .

The Credit Facility contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Please see “Note 8: Debt” in "Item 8 Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of the material provisions of our Credit Facility.

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8.75% Senior Notes

On June 29, 2018, we issued at par $300.0 million in aggregate principal amount of our 8.75% Senior Notes maturing in July 15, 2023 in a private placement under Rule 144A and Regulation S of the Securities Act of 1933, as amended. The estimated offering costs were $7.3 million resulting in net proceeds of $292.7 million, which we used to repay the Credit Facility and for general corporate purposes.

Please see “Note 8: Debt” in "Item 8 Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2018, for a discussion of the material provisions of our Senior Notes.

Finance leases

During 2013, we entered into lease financing agreements with U.S. Bank 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 with minimum lease payments of $3.2 million annually. As discussed above, these compressors are currently being subleased.

During 2019, we entered into lease financing agreements for our fleet trucks for $1.4 million . The lease 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 title to the vehicle can be transferred to us at minimal cost.

Contractual obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, financing leases and purchase obligations. Our operating leases include leases for drilling rigs, which have terms of up to 15 months, and leases on CO ₂ recycle compressors, which have terms of seven years. Aside from operating leases, we also have financing leases for our CO ₂ recycle compressors and fleet vehicles. In conjunction with the sale of our EOR assets, all our leased CO ₂ compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank, the originating lessor. The subleases are structured such that the lease payments and remaining lease term are identical to the original leases. As of June 30, 2019, other than additional borrowings under our Credit Facility and our new leases for fleet vehicles, we did not have material changes to our contractual commitments since December 31, 2018.

Financial position

We believe that the following discussion of material changes in our balance sheet may be useful:

(in thousands)		June 30, 2019				December 31, 2018				Change
Assets
Right of use asset from operating leases		$	9,005			$	—			$	9,005
Accounts receivable, net		52,686				66,087				(13,401		)
Liabilities
Accounts payable and accrued liabilities		$	73,770			$	73,779			$	(9	)
Long-term debt and financing leases		393,797				307,471				86,326
Derivative instrument liabilities (assets) net		9,253				(24,682		)		33,935
Noncurrent operating lease obligations		2,075				—				2,075

•	We recognized a right of use asset on operating leases pursuant to our adoption of the new lease accounting standard at the beginning of the year.

•	Accounts receivable, net, decreased due to lower commodity sales in the month prior to quarter end, resulting in a decline in trade receivables, and a decrease in capital spending prior to quarter end, resulting in a decline in joint interest receivables. .

•

While our accounts payable and accrued liabilities remained flat, the balance as of June 30, 2019, includes $6.9 million for our current obligations on operating leases pursuant to the adoption of the new lease accounting standard at the beginning of the year. The table above also discloses the noncurrent portion of these obligations totalling $2.1 million . The operating lease liabilities reflect our obligations on compressors and drilling rigs as of June 30, 2019.

•	Long-term debt was higher in total primarily due to $85.0 million in borrowings on our Credit Facility.

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•	Our portfolio of derivative instruments reverted from a net asset to a net liability as a result of an increase in forward commodity prices.

Non-GAAP financial measure and reconciliation

Management uses adjusted EBITDA (as defined below) as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash and/or non-recurring adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, Adjusted EBITDA is generally consistent with the EBITDAX calculation that is used in the Ratio of Total Debt to EBITDAX covenant under our Credit Facility. We consider compliance with this covenant to be material.

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 agreements and fresh start accounting activities for which our lenders have permitted us to exclude when calculating covenant compliance.

The following tables provide a reconciliation of net loss to adjusted EBITDA for the specified periods:

		Three months ended June 30,								Six months ended June 30,
(in thousands)		2019				2018				2019				2018
Net loss		(45,229		)		(21,993		)		(148,769		)		(33,435		)
Interest expense		5,571				1,739				10,135				3,110
Depreciation, depletion, and amortization		30,282				20,407				53,997				41,513
Non-cash change in fair value of derivative instruments		(17,596		)		26,761				33,935				39,018
Impact of derivative repricing		—				(1,680		)		—				(2,252		)
Loss on settlement of liabilities subject to compromise		—				—				—				48
Interest income		(2		)		(1		)		(2		)		(2		)
Stock-based compensation expense		852				1,671				1,654				6,294
(Gain) loss on sale of assets		(491		)		(469		)		(490		)		575
Loss on impairment of oil and gas assets		63,593				—				113,315				—
Loss on impairment of other assets		6,407				—				6,407				—
Restructuring, reorganization and other		313				480				1,833				1,469
Adjusted EBITDA		$	43,700			$	26,915			$	72,015			$	56,338

Our Credit Facility requires us to maintain a current ratio (as defined in Credit Facility) of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our Credit Facility, we consider the current ratio calculated under our Credit Facility to be a useful measure of our liquidity because it includes the funds available to us under our Credit Facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. The following table discloses the current ratio for our loan compliance compared to the ratio calculated per GAAP: 

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(dollars in thousands)		June 30, 2019				December 31, 2018
Current assets per GAAP		$	95,774			$	134,431
Plus—Availability under Credit Facility		189,872				208,355
Less—Short term derivative instruments		(4,524		)		(24,025		)
Current assets as adjusted		$	281,122			$	318,761
Current liabilities per GAAP		136,913				136,710
Less—Current derivative instruments		(4,802		)		—
Less—Current operating lease obligation		(6,930		)		—
Less—Current asset retirement obligation		(1,468		)		(1,057		)
Less—Current maturities of long term debt		(11,502		)		(12,371		)
Current liabilities as adjusted		$	112,211			$	123,282
Current ratio per GAAP		0.70				0.98
Current ratio for loan compliance		2.51				2.59

Off-Balance Sheet Arrangements

At June 30, 2019 , we did not have any off-balance sheet arrangements.

Critical accounting policies

For a discussion of our critical accounting policies, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2018 .

Also see the footnote disclosures included in “Note 1: Nature of operations and summary of significant accounting policies” and “Note 5: Leases” in "Item 1. Financial Statements" of this report.

Recent accounting pronouncements

See recently adopted and issued accounting standards in “Note 1: Nature of operations and summary of significant accounting policies” in "Item 1. Financial Statements" of this report.

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ITEM 3.	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 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 six months ended June 30, 2019 , our gross revenues from oil and natural gas sales would change approximately $2.7 million for each $1.00 change in oil and natural gas liquid prices and $1.0 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 have 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 6: Derivative instruments” in “Item 1. Financial Statements” of this report for further discussion of our derivative instruments.

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

The fair value of our outstanding derivative instruments at June 30, 2019 was a net liability of $9.3 million . Based on our outstanding derivative instruments as of June 30, 2019 , summarized below, a 10% increase in the June 30, 2019 , forward curves used to mark-to-market our derivative instruments would have increased our net liability position to $38.9 million , while a 10% decrease would have reverted our net liability to a net asset position of $19.2 million .

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Our outstanding oil derivative instruments as of June 30, 2019 , are summarized below:

Period and type of contract		Volume MBbls			Weighted average fixed price per Bbl
July - September 2019					Swaps				Purchased Puts				Sold Calls
Oil swaps		645			$	55.96			$	—			$	—
Oil roll swaps		120			$	0.46			$	—			$	—
October - December 2019
Oil swaps		666			$	55.89			$	—			$	—
Oil roll swaps		120			$	0.46			$	—			$	—
January - March 2020
Oil swaps		504			$	50.47			$	—			$	—
Oil roll swaps		120			$	0.46			$	—			$	—
Oil collars		195			$	—			$	55.00			$	66.42
April - June 2020
Oil swaps		477			$	50.65			$	—			$	—
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 June 30, 2019 , are summarized below:

Period and type of contract		Volume BBtu			Weighted average fixed price per MMBtu
July - September 2019					Swaps
Natural gas swaps		3,847			$	2.85
Natural gas basis swaps		3,164			$	(0.61	)
October - December 2019
Natural gas swaps		3,977			$	2.85
Natural gas basis swaps		1,830			$	(0.56	)
January - March 2020
Natural gas swaps		1,500			$	2.75
Natural gas basis swaps		900			$	(0.46	)
April - June 2020
Natural gas swaps		1,500			$	2.75
Natural gas basis swaps		900			$	(0.46	)
July - September 2020
Natural gas swaps		1,500			$	2.75
Natural gas basis swaps		900			$	(0.46	)
October - December 2020
Natural gas swaps		1,500			$	2.75
Natural gas basis swaps		900			$	(0.46	)

Our outstanding natural gas liquid derivative instruments as of June 30, 2019 are summarized below:

Period and type of contract		Volume Thousands of Gallons			Weighted average fixed price per gallon
July - September 2019					Swaps
Natural gasoline swaps		3,696			$	1.14
Propane swaps		8,316			$	0.61
Butane		2,142			$	0.71
October - December 2019
Natural gasoline swaps		4,200			$	1.13
Propane swaps		9,156			$	0.61
Butane		2,394			$	0.71
January - March 2020
Natural gasoline swaps		4,032			$	1.13
Propane swaps		8,988			$	0.61
Butane		2,352			$	0.71
April - June 2020
Natural gasoline swaps		756			$	1.39
Propane swaps		1,680			$	0.74

Interest rates .  All of the outstanding borrowings under our Credit Facility as of June 30, 2019 are subject to market rates of interest as determined from time to time by the banks. As of June 30, 2019 , borrowings bear interest at the adjusted LIBO Rate, as defined under the Credit Facility, plus the applicable margin, which resulted in a weighted average interest rate of  4.66% 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 Facility of $325.0 million , equal to our borrowing base at June 30, 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 4.	CONTROLS AND PROCEDURES

Disclosure Controls and procedures

As required by Rule 13a-15(b) of 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 Form 10-Q. 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 as of June 30, 2019 , at the reasonable assurance level .

Changes in Internal control over financial reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the most recent fiscal quarter 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.

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PART II—OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS

Please see “Note 10: Commitments and contingencies” in "Item 1. Financial Statements" of this report 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.

ITEM 1A.	RISK FACTORS

Security holders and potential investors in our securities should carefully consider the risk factors in our Annual Report on Form 10-K filed with the SEC on March 14, 2019, together with the information set forth in our subsequent Quarterly Reports on Form 10-Q, current reports on Form 8-K and other materials we file with the SEC. 

There have been no material changes to the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018 , or our subsequent quarterly reports on Form 10-Q.

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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
April 1-30, 2019		123,231			$	5.61			N/A		N/A
May 1-31, 2019		—			$	—			N/A		N/A
June 1-30, 2019		—			$	—			N/A		N/A
Total		123,231			$	5.61			N/A		N/A

(1)	All shares purchases relate to tax withholding and the payment of taxes in connection with vesting of restricted shares issued under our MIP.

Pursuant to a settlement agreement, the Company issued 76,217 shares in June 2019 to certain holders of general unsecured claims pursuant to pending litigation that existed at the date of the Reorganization Plan. These shares were issued under an exemption from registration requirements of the Securities Act pursuant to section 1145(a) of the Bankruptcy Code.

ITEM 5.	OTHER INFORMATION

Not applicable.

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ITEM 6.	EXHIBITS

Exhibit No.		Description
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*		Amended and Restated Bylaws of Chaparral Energy, Inc., dated as of March 21, 2017 (Incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017).
4.1*		Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017).
4.2*		Stockholders Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed on March 27, 2017).
4.3*		First Amendment to Stockholders Agreement, dated as of March 6, 2018, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on March 9, 2018).
4.4*		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).
4.5*		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).
10.1 †		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).
10.2 *		Third Amendment to Tenth Restated Credit Agreement, dated as of May 2, 2019, among Chaparral Energy, Inc., as borrower, Royal Bank of Canada, as administrative agent and issuing bank, and the additional lenders party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 10-Q filed on May 9, 2019).
10.3		Chaparral Energy, Inc. 2019 Long-Term Incentive Plan, effective June 28, 2019. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on July 02, 2019).
31.1		Certification by Principal Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

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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 by Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Extension Schema Document.
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

*	Incorporated by reference
†	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/ K. Earl Reynolds
Name:		K. Earl Reynolds
Title:		Chief Executive Officer
		(Principal Executive Officer)
By:		/s/ Scott Pittman
Name:		Scott Pittman
Title:		Chief Financial Officer and Senior Vice President
		(Principal Financial Officer and Principal Accounting Officer)

 

Date: August 8, 2019

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