Chaparral Energy, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Chaparral Energy, Inc.	a2018q3ex322.htm
EX-32.1 - EXHIBIT 32.1 - Chaparral Energy, Inc.	a2018q3ex321.htm
EX-31.2 - EXHIBIT 31.2 - Chaparral Energy, Inc.	a2018q3ex312.htm
EX-31.1 - EXHIBIT 31.1 - Chaparral Energy, Inc.	a2018q3ex311.htm
EX-10.2 - EXHIBIT 10.2 - Chaparral Energy, Inc.	a2018q3ex102.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

For the quarterly period ended September 30, 2018



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

For the transition period from to

Commission file number: 001-38602




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



Delaware		73-1590941
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

701 Cedar Lake Boulevard Oklahoma City, Oklahoma		73114
(Address of principal executive offices)		(Zip code)



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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer			x
Smaller reporting company			¨
Emerging growth company			¨

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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐

Number of shares outstanding of each of the issuer’s classes of common stock as of November 9, 2018:



Class	Number of Shares
Class A Common Stock, $0.01 par value	38,585,291
Class B Common Stock, $0.01 par value	7,871,512

CHAPARRAL ENERGY, INC.

Index to Form 10-Q



	Page

Part I. FINANCIAL INFORMATION	7
Item 1. Financial Statements	7
Consolidated Balance Sheets	7
Consolidated Statements of Operations	8
Consolidated Statement of Stockholders' Equity	9
Consolidated Statements of Cash Flows	10
Condensed Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Overview	33
Results of Operations	35
Liquidity and Capital Resources	43
Non-GAAP Financial Measure and Reconciliation	48
Critical Accounting Policies	49
Recent Accounting Pronouncements	49
Item 3. Quantitative and Qualitative Disclosures about Market Risk	50
Item 4. Controls and Procedures	54
Part II. OTHER INFORMATION
Item 1. Legal Proceedings	54
Item 1A. Risk Factors	54
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 5. Other Information	54
Item 6. Exhibits	55
Signatures	57

CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

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


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


•	the amount, nature and timing of capital expenditures;


•	drilling, completion and performance of wells;


•	competition and government regulations;


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


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


•	changes in proved reserves;


•	operating costs and other expenses;


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


•	estimates of proved reserves;


•	exploitation of property acquisitions; and


•	marketing of oil and natural gas.

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described in Part II, Item 1A. Risk Factors, of this report and Part I, Item 1A. Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2017, the factors include:


•	the ability to operate our business following emergence from bankruptcy;


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


•	volatility and declines in oil and natural gas prices;


•	drilling plans (including scheduled and budgeted wells);


•	our new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from current values;


•	the number, timing or results of any wells;


•	changes in wells operated and in reserve estimates;


•	future growth and expansion;


•	future exploration;


•	integration of existing and new technologies into operations;


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


•	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


•	any loss of key personnel;


•	geopolitical events affecting oil and natural gas prices;


•	outcome, effects or timing of legal proceedings;


•	the effect of litigation and contingencies;


•	the outcome, timing or effects of environmental litigation


•	the ability to generate additional prospects; and


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

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

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

GLOSSARY OF CERTAIN DEFINED TERMS

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



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

Bbl	One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate, or natural gas liquids.

BBtu	One billion British thermal units.

Boe	Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

Boe/d	Barrels of oil equivalent per day.

Btu	British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

CO₂	Carbon dioxide.

Dry well or dry hole	An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

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

EOR Areas	Areas where we previously injected and/or recycled CO₂ as a means of oil recovery which were divested in November 2017.

Exit Credit Facility	Ninth Restated Credit Agreement, dated as of March 21, 2017, by and among us, Chaparral Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and The Lenders and Prepetition Borrowers Party thereto.

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

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

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.

New Credit Facility	Tenth Restated Credit Agreement, dated as of December 21, 2017, by and among us, Chaparral Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and The Lenders and Prepetition Borrowers Party thereto.

NYMEX	The New York Mercantile Exchange.



Play	A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.

Prior Credit Facility	Eighth Restated Credit Agreement, dated as of April 12, 2010, by and among us, Chaparral Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and The Lenders and Prepetition Borrowers Party thereto.

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

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.

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

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.

PART I — FINANCIAL INFORMATION



ITEM 1.	FINANCIAL STATEMENTS

Chaparral Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)



(dollars in thousands, except share data)	September 30, 2018			December 31, 2017
Assets
Current assets:
Cash and cash equivalents	$	48,960		$	27,732
Accounts receivable, net	65,780			60,363
Inventories, net	5,774			5,138
Prepaid expenses	2,312			2,661
Total current assets	122,826			95,894
Property and equipment, net	43,996			50,641
Oil and natural gas properties, using the full cost method:
Proved	771,028			634,294
Unevaluated (excluded from the amortization base)	558,081			482,239
Accumulated depreciation, depletion, amortization and impairment	(179,540		)	(124,180		)
Total oil and natural gas properties	1,149,569			992,353
Other assets	446			418
Total assets	$	1,316,837		$	1,139,306
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	66,614		$	75,414
Accrued payroll and benefits payable	8,315			11,276
Accrued interest payable	7,057			187
Revenue distribution payable	28,470			17,966
Long-term debt and capital leases, classified as current	3,444			3,273
Derivative instruments	29,905			8,959
Total current liabilities	143,805			117,075
Long-term debt and capital leases, less current maturities	305,760			141,386
Derivative instruments	39,042			4,167
Deferred compensation	453			696
Asset retirement obligations	24,358			33,216
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, 5,000,000 shares authorized, none issued and outstanding	—			—
Class A Common stock, $0.01 par value, 180,000,000 shares authorized; 38,845,797 issued and 38,588,902 outstanding at September 30, 2018 and 38,956,250 shares issued and outstanding at December 31, 2017	388			389
Class B Common stock, $0.01 par value, 20,000,000 shares authorized and 7,871,512 shares issued and outstanding at September 30, 2018 and December 31, 2017	79			79
Additional paid in capital	972,229			961,200
Treasury stock, at cost, 256,895 and nil shares as of September 30, 2018 and December 31, 2017	(4,872		)	—
Accumulated deficit	(164,405		)	(118,902		)
Total stockholders' equity	803,419			842,766
Total liabilities and stockholders' equity	$	1,316,837		$	1,139,306

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

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Successor												Predecessor
(in thousands, except share and per share data)	Three months ended September 30, 2018			Three months ended September 30, 2017			Nine months ended September 30, 2018			Period from March 22, 2017 through September 30, 2017			Period from January 1, 2017 through March 21, 2017
Revenues:
Net commodity sales	65,519			75,947			181,835			157,803			66,531
Sublease revenue	1,199			—			3,595			—			—
Total revenues	66,718			75,947			185,430			157,803			66,531
Costs and expenses:
Lease operating	12,493			24,209			42,045			51,527			19,941
Transportation and processing (1)	—			2,942			—			6,370			2,034
Production taxes	4,028			4,536			9,473			8,235			2,417
Depreciation, depletion and amortization	22,252			32,167			63,765			66,432			24,915
General and administrative	9,021			9,924			28,718			24,641			6,843
Cost reduction initiatives	210			34			1,034			155			629
Other	402			—			1,633			—			—
Total costs and expenses	48,406			73,812			146,668			157,360			56,779
Operating income	18,312			2,135			38,762			443			9,752
Non-operating (expense) income:
Interest expense	(4,205		)	(5,283		)	(7,315		)	(10,984		)	(5,862		)
Derivative (losses) gains	(23,677		)	(15,448		)	(72,464		)	(4,089		)	48,006
(Loss) gain on sale of assets	(2,024		)	(13		)	(2,599		)	(876		)	206
Other income, net	19			389			123			696			1,167
Net non-operating (expense) income	(29,887		)	(20,355		)	(82,255		)	(15,253		)	43,517
Reorganization items, net	(493		)	(858		)	(2,010		)	(2,548		)	988,727
(Loss) income before income taxes	(12,068		)	(19,078		)	(45,503		)	(17,358		)	1,041,996
Income tax expense	—			37			—			75			37
Net (loss) income	$	(12,068	)	$	(19,115	)	$	(45,503	)	$	(17,433	)	$	1,041,959
Earnings per share:
Basic for Class A and Class B	(0.27		)	(0.42		)	(1.01		)	(0.39		)	*
Diluted for Class A and Class B	(0.27		)	(0.42		)	(1.01		)	(0.39		)	*
Weighted average shares used to compute earnings per share:
Basic for Class A and Class B	45,333,745			44,982,142			45,272,595			44,982,142			*
Diluted for Class A and Class B	45,333,745			44,982,142			45,272,595			44,982,142			*

____________________________________________________________

(1) See “Note 5—Revenue recognition.”

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

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

Chaparral Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

(Unaudited)



	Common stock
(dollars in thousands)	Shares outstanding		Amount			Additional paid in capital		Treasury stock			Accumulated deficit			Total
As at December 31, 2017	46,827,762		$	468		$	961,200	$	—		$	(118,902	)	$	842,766
Stock-based compensation	55,000		—			11,029		—			—			11,029
Restricted stock forfeited	(165,453	)	(1		)	—		—			—			(1		)
Repurchase of common stock	(256,895	)	—			—		(4,872		)	—			(4,872		)
Net loss	—		—			—		—			(45,503		)	(45,503		)
Balance at September 30, 2018	46,460,414		$	467		$	972,229	$	(4,872	)	$	(164,405	)	$	803,419

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

Chaparral Energy, Inc. and subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Successor						Predecessor
	Nine months ended			Period from March 22, 2017 through			Period from January 1, 2017 through
(in thousands)	September 30, 2018			September 30, 2017			March 21, 2017
Cash flows from operating activities
Net (loss) income	$	(45,503	)	$	(17,433	)	$	1,041,959
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Non-cash reorganization items	—			—			(1,012,090		)
Depreciation, depletion and amortization	63,765			66,432			24,915
Derivative losses (gains)	72,464			4,089			(48,006		)
Loss (gain) on sale of assets	2,599			876			(206		)
Other	4,376			1,300			645
Change in assets and liabilities
Accounts receivable	(6,743		)	(16,082		)	198
Inventories	(1,415		)	2,683			466
Prepaid expenses and other assets	322			2,560			(497		)
Accounts payable and accrued liabilities	(12,383		)	(13,369		)	8,733
Revenue distribution payable	10,895			4,549			(1,875		)
Deferred compensation	7,890			2,565			143
Net cash provided by operating activities	96,267			38,170			14,385
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(252,731		)	(114,358		)	(31,179		)
Proceeds from asset dispositions	36,335			7,791			1,884
(Payments) proceeds from derivative instruments, net	(16,642		)	15,143			1,285
Cash in escrow	—			42			—
Net cash used in investing activities	(233,038		)	(91,382		)	(28,010		)
Cash flows from financing activities
Proceeds from long-term debt	116,000			33,000			270,000
Repayment of long-term debt	(243,554		)	(1,154		)	(444,785		)
Proceeds from Senior Notes	300,000			—			—
Proceeds from rights offering, net	—			—			50,031
Principal payments under capital lease obligations	(2,003		)	(1,362		)	(568		)
Payment of debt issuance costs and other financing fees	(7,572		)	—			—
Treasury stock purchased	(4,872		)	—			(2,410		)
Net cash provided by (used in) financing activities	157,999			30,484			(127,732		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	21,228			(22,728		)	(141,357		)
Cash, cash equivalents, and restricted cash at beginning of period	27,732			45,123			186,480
Cash, cash equivalents, and restricted cash at end of period	$	48,960		$	22,395		$	45,123

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

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.

Reorganization, fresh start accounting and comparability of financial statements to prior periods

On May 9, 2016, the Company and ten of its subsidiaries filed voluntary petitions seeking relief under Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) commencing cases for relief under Chapter 11 of the Bankruptcy Code.

On March 10, 2017, the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy. Upon emergence, all existing equity was canceled and we issued new common stock to the previous holders of our Prior Senior Notes and certain general unsecured creditors whose claims were impaired as a result of our bankruptcy, as well as to certain other parties as set forth in the Reorganization Plan, including to parties participating in a rights offering.

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

As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Company’s consolidated financial statements after March 21, 2017, are not comparable with the consolidated financial statements prior to that date. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to March 21, 2017, and to the pre-emergence company as “Predecessor” for periods prior to and including March 21, 2017.

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, 2017.

The financial information as of September 30, 2018 (Successor), for the three and nine months ended September 30, 2018 (Successor), the periods of March 22, 2017, through September 30, 2017 (Successor), and the three months ended September 30, 2017 (Successor), is unaudited. The financial information as of December 31, 2017 (Successor), and the period of January 1, 2017, through March 21, 2017 (Predecessor), have been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2017. 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 nine months ended September 30, 2018 (Successor) are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2018.

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 September 30, 2018, cash with a recorded balance totaling approximately $46,640 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:

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)



	September 30, 2018			December 31, 2017
Joint interests	$	28,867		$	29,032
Accrued commodity sales	34,381			26,516
Derivative settlements	—			157
Other	3,338			5,326
Allowance for doubtful accounts	(806		)	(668		)
	$	65,780		$	60,363

Inventories

Inventories consisted of the following:



	September 30, 2018			December 31, 2017
Equipment inventory	$	5,282		$	4,163
Commodities	671			1,154
Inventory valuation allowance	(179		)	(179		)
	$	5,774		$	5,138

Oil and natural gas properties

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.

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



	September 30, 2018		December 31, 2017
Leasehold acreage	$	532,531	$	466,711
Capitalized interest	9,289		2,134
Wells and facilities in progress of completion	16,261		13,394
Total unevaluated oil and natural gas properties excluded from amortization	$	558,081	$	482,239

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 September 30, 2018, 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.

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

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at September 30, 2018, and December 31, 2017, were immaterial.

Income taxes

In December 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 (the “Act”), making significant changes to the Internal Revenue Code. Changes include, but are not limited to, a federal corporate tax rate of 21%, additional limitations on executive compensation, and limitations on the deductibility of interest. The FASB issued Accounting Standards Update (“ASU”) 2018-05, Income Taxes (Topic 740): "Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin (“SAB”) No. 118" to address the application of GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Act.

Upon final determination of tax return amounts for the year ended December 31, 2017, we completed the accounting with regard to Section 162(m) provisions under the Act and recorded an immaterial discrete income tax benefit for the nine months ended September 30, 2018, fully offset by a corresponding increase in valuation allowance.

Despite the Company’s net loss for the nine months ended September 30, 2018, we did not 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, 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 assets 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 September 30, 2018, or December 31, 2017.

Elements of the Reorganization Plan provided that our indebtedness related to Prior Senior Notes and certain general unsecured claims were exchanged for Successor common stock in settlement of those claims. Absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (“IRC”), provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings, the amount of CODI was $60,398, which reduced the value of the Company’s net operating losses.

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

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

subject to this limitation. The Company estimates that it will incur an additional $85,863 of post-change net operating loss carryforward not subject to the limitation for the tax year ended December 31, 2018. The limitation did not result in a current tax liability for the tax year ended December 31, 2017 and is not expected to result in a tax liability for the tax year ended December 31, 2018.

Other

Other consisted of the following:



	Three months ended September 30, 2018		Nine months ended September 30, 2018
Restructuring	$	—	$	425
Subleases	402		1,208
Total other expense	$	402	$	1,633

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 CO₂ compressors that were previously utilized in our EOR operations and leased as capital 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. Subsequent to the execution of the subleases, all payments received from the Sublessee are reflected as revenues on our statement of operations. Payments we make to U.S. Bank on the original operating leases, which are disclosed in the table above, are reflected in “Other” on our statement of operations while payments on the original capital leases are a reduction of debt and recognition of interest expense. With respect to the capital leases, we have reclassified the amount associated with these leases from the full cost amortization base to plant, property and equipment on our balance sheet and are amortizing the asset on a straight line basis prospectively. Please see “Note 1— Nature of operations and summary of significant accounting policies”,” Note 8— Debt”, and “Note 16— Commitments and contingencies” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2017, which contains additional information about our 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 will fund 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 will be drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County. The JDA provides us with a means to accelerate the delineation of our position within our Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and potentially adding reserves. In exchange for funding, BCE will receive wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retain 15%) until the program reaches a 14% internal rate of return. Once achieved, ownership interest in all JDA wells will revert such that we will own a 75% working interest and BCE will retain a 25% working interest. We will retain all acreage and reserves outside of the wellbore, with both parties 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 as a result of the rebound in industry conditions. 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. We have therefore recorded additions to oil and natural gas properties of $7,834 in cumulative drilling and completion costs on JDA wells that have exceeded the well cost caps specified under the JDA.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Cost reduction initiatives

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 and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows:



	Successor								Predecessor
	Three months ended September 30, 2018		Three months ended September 30, 2017		Nine months ended September 30, 2018		Period from March 22, 2017 through September 30, 2017		Period from January 1, 2017 through March 21, 2017
One-time severance and termination benefits	$	210	$	30	$	1,034	$	142	$	608
Professional fees	—		4		—		13		21
Total cost reduction initiatives expense	$	210	$	34	$	1,034	$	155	$	629

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. “Professional fees” in the table below for periods subsequent to the Effective Date 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:



	Successor								Predecessor
	Three months ended September 30, 2018		Three months ended September 30, 2017		Nine months ended September 30, 2018		Period from March 22, 2017 through September 30, 2017		Period from January 1, 2017 through March 21, 2017
Loss (gain) on the settlement of liabilities subject to compromise	$	—	$	—	$	48	$	—	$	(372,093	)
Fresh start accounting adjustments	—		—		—		—		(641,684		)
Professional fees	493		858		1,962		2,548		18,790
Rejection of employment contracts	—		—		—		—		4,573
Write off unamortized issuance costs on Prior Credit Facility	—		—		—		—		1,687
Total reorganization items	$	493	$	858	$	2,010	$	2,548	$	(988,727	)

Recently adopted accounting pronouncements

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Please see “Note 5—Revenue recognition” for our disclosure regarding adoption of this update.

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

In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

periods thereafter. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations.

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

In November 2016, the FASB issued authoritative guidance requiring that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and should be applied using a retrospective transition method to each period presented. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations.

Recently issued accounting pronouncements

In February 2016, the FASB issued authoritative guidance significantly amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. Furthermore, all leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2018 and interim periods thereafter, and currently should be applied using a modified retrospective approach. Early adoption is permitted. Our planned adoption of the new standard will utilize the transition option that allows us to apply legacy guidance, including disclosure requirements, in the comparative periods presented in the year of adoption. This transition option was one of several practical expedients introduced in a July 2018 guidance update. Our current operating leases are predominantly comprised of a limited number of leases for CO₂ compressors. However, we also enter into contractual arrangements relating to rights of ways or surface use that are typical of upstream oil and gas operations. We are currently assessing whether such arrangements are included in the new guidance, especially in light of a guidance update issued in January 2018 which provides a practical expedient on land easements. The land easement practical expedient allows an entity to continue its legacy accounting policy for land easements that exist or expire before the new standard’s effective date and which are not accounted for under the current lease standard. We are in the process of evaluating the impact of this guidance on our consolidated financial statements and related disclosures and as contracts are reviewed under the new standard, this analysis could result in an impact to our financial statements; however, that impact is currently not known.

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

Note 2: Earnings per share

We have not historically presented earnings per share (“EPS”) because our common stock did not previously trade on a public market, either on a stock exchange or in the over-the-counter (“OTC”) market. Accordingly, we were permitted under accounting guidance to omit such disclosure. However, on July 24, 2018, our Class A common stock began trading on the New York Stock Exchange (“NYSE”) under the symbol “CHAP”. From May 26, 2017, through July 23, 2018, our Class A common stock was quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. From May 18, 2017, through May 25, 2017, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP”. Our Class B common stock is not listed or quoted on the OTCQB or any other national exchange. Our Class A and Class B common stock shares equally in dividends and

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

undistributed earnings. Pursuant to our certificate of incorporation, our Class B common stock will convert to Class A common stock at the latest on December 15, 2018. We are presenting basic and diluted EPS for all Successor periods subsequent to our emergence from bankruptcy but are not presenting EPS for any Predecessor period.

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

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



							Nine months ended September 30, 2018			Period from March 22, 2017 through September 30, 2017
	Three months ended September 30,
(in thousands, except share and per share data)	2018			2017
Numerator for basic and diluted earnings per share
Net loss	$	(12,068	)	$	(19,115	)	$	(45,503	)	$	(17,433	)
Denominator for basic earnings per share
Weighted average common shares - Basic for Class A and Class B	45,333,745			44,982,142			45,272,595			44,982,142
Denominator for diluted earnings per share
Weighted average common shares - Diluted for Class A and Class B (1)	45,333,745			44,982,142			45,272,595			44,982,142
Earnings per share
Basic for Class A and Class B	$	(0.27	)	$	(0.42	)	$	(1.01	)	$	(0.39	)
Diluted for Class A and Class B	$	(0.27	)	$	(0.42	)	$	(1.01	)	$	(0.39	)
Participating securities excluded from earnings per share calculations
Unvested restricted stock awards (2)	1,126,669			1,796,943			1,126,669			1,796,943

________________________________


(1)	During the 2017 periods presented, 140,023 warrants were outstanding. All such warrants expired on June 30, 2018. The warrants to purchase shares of our Class A common stock were antidilutive due to the exercise price exceeding the average price of our Class A shares for the periods presented and due to the net losses we incurred.

(2)

Our unvested restricted stock awards are considered to be participating securities as they include non-forfeitable dividend rights in the event a dividend is paid on our common stock. Our participating securities do not participate in undistributed net losses because they are not contractually obligated to do so and hence are not included in the computation of EPS in periods when a net loss occurs. Figures reflect period end amounts.

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



	Successor						Predecessor
	Nine months ended September 30, 2018			Period from March 22, 2017 through September 30, 2017			Period from January 1, 2017 through March 21, 2017
Net cash provided by operating activities included:
Cash payments for interest	$	5,755		$	13,196		$	4,105
Interest capitalized	(7,155		)	(1,245		)	(248		)
Cash payments for income taxes	$	—		$	150		$	—
Cash payments for reorganization items	$	2,161		$	16,930		$	11,405
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	1,234		$	2,746		$	716
Change in accrued oil and gas capital expenditures	$	7,222		$	10,598		$	5,387

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 4: Debt and capital leases

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



	September 30, 2018			December 31, 2017
8.75% Senior Notes due 2023	$	300,000		$	—
New Credit Facility	—			127,100
Real estate mortgage note	8,738			9,177
Installment note payable	371			—
Capital lease obligations	12,358			14,361
Unamortized debt issuance costs	(12,263		)	(5,979		)
Total debt, net	309,204			144,659
Less current portion	3,444			3,273
Total long-term debt, net	$	305,760		$	141,386

New Credit Facility

The New Credit Facility is a $400,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our New Credit Facility is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on or around May 1 and November 1 of each year. On June 29, 2018, we repaid $243,100, representing the entire outstanding balance with proceeds from the issuance of our Senior Notes discussed below. Based on a borrowing base of $265,000, availability on the New Credit Facility as of September 30, 2018, after taking into account letters of credit, was $264,172.

As of June 29, 2018 (the day immediately preceding payment in full of the entire outstanding balance), our outstanding borrowings were accruing interest at the Adjusted LIBO Rate (as defined in the New Credit Facility), plus the Applicable Margin (as defined in the New Credit Facility), which resulted in a weighted average interest rate of 5.31%.

The New Credit Facility contains financial covenants that require, for each fiscal quarter, we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the New Credit Facility) of no greater than 4.0 to 1.0 calculated on a trailing four-quarter basis. We were in compliance with these financials covenants as of September 30, 2018.

The New 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, 2017, for a discussion of the material provisions of our New Credit Facility.

Effective May 9, 2018, we entered into the First Amendment to the Tenth Restated Credit Agreement, among the Company and its subsidiaries, as borrowers, certain financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (the “Amendment”). The Amendment reaffirmed our borrowing base at the same level of $285,000. In addition, the Amendment provided us with: (i) an increase from $150,000 to $250,000 to the aggregate amount of secured debt allowed, (ii) a waiver on the automatic reduction to the borrowing base calculation for the issuance of up to $300,000 in unsecured debt, (iii) the ability to offset the total debt calculation in the financial covenant calculations by up to $50,000 of unrestricted cash and cash equivalents whenever we do not have outstanding borrowings on the facility, and (iv) permission to make payments on account of the purchase, redemption, retirement, acquisition, cancellation or termination of our equity of up to $50,000.

Under the New Credit Facility, in the event of asset divestitures which occur between scheduled borrowing base redeterminations, individually or in aggregate amounting to more than 5% of the borrowing base value assigned to the disposed assets, an automatic borrowing base reduction under the Triggering Disposition clause (as defined in the New Credit Facility) would occur. In conjunction with the Triggering Disposition clause, we executed a letter agreement (the “Letter Agreement”) with the lenders under our New Credit Facility. The Letter Agreement decreased the borrowing base by $20,000 to $265,000 following the closing of several non-core asset divestitures which included the divestiture of certain properties in the Oklahoma/Texas Panhandle, which closed on July 27, 2018, for gross cash proceeds before selling costs of $17,000 and the conveyance of $629 in liabilities to the buyer, and two additional divestitures which closed in June 2018 for total proceeds of $6,913. The Letter Agreement, which was effective July 27, 2018, also excludes the property divestitures above from future determinations of whether a Triggering Disposition has occurred. See further discussion about these divestitures in “Note 11 – Divestitures.”

Our November 2018 borrowing base redetermination is currently in process.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

8.75% Senior Notes

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

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

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

The indenture governing our Senior Notes contains certain covenants which limit our ability to:


•	incur additional indebtedness or issue certain preferred stock;


•	pay dividends or repurchase or redeem capital stock;


•	make certain investments;


•	incur certain liens;


•	enter into certain types of transactions with affiliates;


•	sell assets;


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


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


•	create unrestricted subsidiaries.

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

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


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


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

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

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

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

Capital Leases

In 2013, we entered into lease financing agreements with U.S. Bank for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool. The lease financing obligations are for 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. 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.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Note 5: Revenue recognition

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

Description of products and revenue disaggregation

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

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



	Three months ended September 30, 2018			Nine months ended September 30, 2018
Revenues:
Oil	$	46,576		$	132,378
Natural gas	9,458			26,584
Natural gas liquids	14,078			34,789
Gross commodity sales	70,112			193,751
Transportation and processing	(4,593		)	(11,916		)
Net commodity sales	$	65,519		$	181,835

Performance Obligations

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

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

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

Pricing and measurement

All of our contracts use market or index-based pricing resulting in the entire transaction price being variable. Since our sales transactions meet the variable allocation criteria in the standard, all consideration is allocated entirely to performance obligations satisfied by distinct commodity units delivered. We record revenue in the month production is delivered to the purchaser. However, settlement statements for our commodity sales are received one to three months after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. Historically, differences between our revenue estimates and actual revenue received have not been significant. We receive payment for a majority of our sales receivables in the month following delivery and substantially all within three months following delivery. For the three and nine months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

Transaction Price Allocated to Remaining Performance Obligations

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

Nature of gas contracts

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

Contract assets and liabilities

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

Method of adoption

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

Reconciliation of Income Statement

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



	Three months ended September 30, 2018
	As reported		Balances without adoption of ASC 606			Effect of change
Revenues
Net commodity sales	$	65,519	$	70,112		$	(4,593	)
Costs and expenses
Transportation and processing	$	—	$	(4,593	)	$	4,593



	Nine months ended September 30, 2018
	As reported		Balances without adoption of ASC 606			Effect of change
Revenues
Net commodity sales	$	181,835	$	193,751		$	(11,916	)
Costs and expenses
Transportation and processing	$	—	$	(11,916	)	$	11,916

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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, put options, enhanced swaps and basis protection swaps. See “Note 9—Derivative Instruments” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2017, for a description of the various kinds of derivatives we may enter into.

During the second quarter of 2018, we entered into additional derivative contracts to hedge our exposure to natural gas liquids pricing, specifically propane and natural gasoline, natural gas basis differentials and the WTI NYMEX calendar month average roll (“oil roll”), which is a contractual component of our crude oil sales prices.

The following table summarizes our crude oil derivatives outstanding as of September 30, 2018:



		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Purchased puts		Sold calls
2018
Oil swaps	515	$	58.21	$	—	$	—
Oil collars	46	$	—	$	50.00	$	60.50
Oil roll swaps	150	$	0.59	$	—	$	—
2019
Oil swaps	1,562	$	55.90	$	—	$	—
Oil roll swaps	530	$	0.52	$	—	$	—
2020
Oil swaps	1,548	$	49.54	$	—	$	—
Oil roll swaps	410	$	0.38	$	—	$	—
2021
Oil swaps	543	$	44.34	$	—	$	—
Oil roll swaps	150	$	0.30	$	—	$	—

The following table summarizes our natural gas derivatives outstanding as of September 30, 2018:



Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2018
Natural gas swaps	2,519	$	2.88
Natural gas basis swaps	1,500	$	0.70
2019
Natural gas swaps	7,632	$	2.81
Natural gas basis swaps	2,500	$	0.70
2020
Natural gas swaps	3,600	$	2.77

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

The following table summarizes our natural gas liquid derivatives outstanding as of September 30, 2018:



Period and type of contract	Volume Gallons	Weighted average fixed price per gallon
2018
Natural gasoline swaps	1,512	$	1.55
Propane swaps	3,528	$	0.88
2019
Natural gasoline swaps	4,956	$	1.39
Propane swaps	11,466	$	0.74
2020
Natural gasoline swaps	1,890	$	1.39
Propane swaps	4,284	$	0.74

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

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the 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 at September 30, 2018								As at December 31, 2017
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas derivative contracts (1)	$	683	$	(297	)	$	386		$	1,332	$	(1,054	)	$	278
Crude oil derivative contracts (2)	119		(64,325		)	(64,206		)	—		(13,404		)	(13,404		)
NGL derivative contracts	—		(5,127		)	(5,127		)	—		—			—
Total derivative instruments	802		(69,749		)	(68,947		)	1,332		(14,458		)	(13,126		)
Less:
Netting adjustments (3)	802		(802		)	—			1,332		(1,332		)	—
Derivative instruments - current	—		(29,905		)	(29,905		)	—		(8,959		)	(8,959		)
Derivative instruments - long-term	$	—	$	(39,042	)	$	(39,042	)	$	—	$	(4,167	)	$	(4,167	)

________________________________


(1)	The fair value of our natural gas basis swaps, included herein, was $172 at September 30, 2018.


(2)	The fair value of our oil roll swaps, included herein, was $73 at September 30, 2018.


(3)	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.

In October and November 2018, we entered into several derivative contracts with varying maturities outlined below:



		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps
2019
Oil swaps	220	$	63.51
2020
Oil swaps	100	$	61.64

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)



Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2018
Natural gas basis swaps	681	$	(0.52	)
2019
Natural gas basis swaps	2,481	$	(0.66	)
Natural gas swaps	660	$	2.89

Effect of derivative instruments on the consolidated statements of operations

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

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



	Successor								Predecessor
	Three months ended September 30, 2018		Three months ended September 30, 2017		Nine months ended September 30, 2018		Period from March 22, 2017 through September 30, 2017		Period from January 1, 2017 through March 21, 2017
Change in fair value of commodity price derivatives	(16,804	)	(22,236	)	(55,822	)	(19,232	)	$	46,721
Settlements (paid) received on commodity price derivatives	(6,873	)	6,788		(16,642	)	15,143		1,285
Total derivative (losses) gains	(23,677	)	(15,448	)	(72,464	)	(4,089	)	$	48,006

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.

Recurring fair value measurements

As of September 30, 2018, and December 31, 2017, 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

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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 at September 30, 2018									As at December 31, 2017
	Derivative assets			Derivative liabilities			Net assets (liabilities)			Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	630		$	(69,172	)	$	(68,542	)	$	1,332		$	(14,163	)	$	(12,831	)
Significant unobservable inputs (Level 3)	172			(577		)	(405		)	—			(295		)	(295		)
Netting adjustments (1)	(802		)	802			—			(1,332		)	1,332			—
	$	—		$	(68,947	)	(68,947		)	$	—		$	(13,126	)	$	(13,126	)

________________________________


(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:



	Successor						Predecessor
	Nine months ended			Period from March 22, 2017 through September 30, 2017			Period from January 1, 2017 through March 21, 2017
Net derivative assets (liabilities)	September 30, 2018			Period from March 22, 2017 through September 30, 2017			Period from January 1, 2017 through March 21, 2017
Beginning balance	$	(295	)	$	715		$	(98	)
Realized and unrealized (losses) gains included in derivative (losses) gains	(1,069		)	(259		)	813
Settlements paid	959			—			—
Ending balance	$	(405	)	$	456		$	715
(Losses) gains relating to instruments still held at the reporting date included in derivative (losses) gains for the period	$	(342	)	$	(259	)	$	813

Nonrecurring fair value measurements

Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first nine months of 2018 and 2017 were escalated using an annual inflation rate of 2.26% and 2.30%, respectively. The estimated future costs to dispose of properties added during the nine months ended September 30, 2018, were discounted with a credit-adjusted risk-free rate ranging from 6.92% to 8.77%. For the properties added during the period from March 22, 2017, through September 30, 2017, a credit-adjusted risk-free rate range from 5.20% to 7.63% was used. 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.

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, except per share amounts)

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



	September 30, 2018				December 31, 2017
Level 2	Carrying value (1)		Estimated fair value		Carrying value (1)		Estimated fair value
8.75% Senior Notes due 2023	$	300,000	$	299,718	$	—	$	—
New Credit Facility	—		—		127,100		127,100
Other secured debt	9,109		9,109		9,177		9,177

________________________________


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

The carrying value of our New 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 September 30, 2018, the counterparties to our open derivative contracts consisted of five financial institutions, of which all were lenders under our New 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.

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

September 30, 2018

Derivative assets

Chaparral Energy, Inc. - FORM 10-Q - November 13, 2018

Attached files