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 ☒

(Explanatory Note: The registrant iswas a voluntary filer within the past 90 days and iswas not subject to the filing requirements of the Securities Exchange Act of ~~1934.~~1934 for such period.)

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

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

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 7, 2016:~~

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, ~~our bankruptcy proceedings,~~ 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:

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. ~~These risks and uncertainties include those~~In addition to the risk factors described in Part II, Item 1A1A. Risk Factors of this report, our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, and ~~under the heading “Risk Factors”~~Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, ~~2015. Specifically, some~~2016, the factors ~~that could cause actual results to differ~~ include:

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.

	September 30,						Successor			Predecessor
	2016			December 31,			June 30,			December 31,
(dollars in thousands, except share data)	(unaudited)			2015			2017			2016
							(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	189,361		$	17,065		$	17,267		$	186,480
Accounts receivable, net		41,273			79,000			59,901			46,226
Inventories, net		8,121			12,329			5,289			7,351
Prepaid expenses		2,945			3,700			2,677			3,886
Derivative instruments		—			143,737			23,275			—
Total current assets		241,700			255,831			108,409			243,943
Property and equipment—at cost, net		43,179			48,962
Property and equipment, net								53,902			41,347
Oil and natural gas properties, using the full cost method:
Proved		4,279,179			4,128,193			661,695			4,323,964
Unevaluated (excluded from the amortization base)		17,115			66,905			604,927			20,353
Accumulated depreciation, depletion, amortization and impairment		(3,763,423	)		(3,396,261	)		(30,583	)		(3,789,133	)
Total oil and natural gas properties		532,871			798,837			1,236,039			555,184
Derivative instruments		—			19,501			13,081			—
Deferred income taxes		—			53,914
Other assets		8,253			27,694			3,340			5,513
Total assets	$	826,003		$	1,204,739		$	1,414,771		$	845,987

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

September 30,

2016

December 31,

(dollars in thousands, except share data)

(unaudited)

2015

Liabilities and stockholders’ deficit

Current liabilities:

Accounts payable and accrued liabilities

$
32,003

$
66,222

Accrued payroll and benefits payable

2,553

15,305

Accrued interest payable

107

23,303

Revenue distribution payable

8,874

12,391

Long-term debt and capital leases, classified as current

472,435

1,607,127

Deferred income taxes

—

53,914

Total current liabilities

515,972

1,778,262

Stock-based compensation

—

400

Asset retirement obligations

50,211

46,434

Liabilities subject to compromise

1,286,828

—

Commitments and contingencies (Note 9)

Stockholders’ deficit:

Preferred stock, 600,000 shares authorized, none issued and outstanding

—

—

Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 334,545
   and 345,289 shares issued and outstanding as of September 30, 2016, and
   December 31, 2015, respectively

4

4

Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 344,859
   shares issued and outstanding

3

3

Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882
   shares issued and outstanding

2

2

Class E Common stock, $0.01 par value, 10,000,000 shares authorized and 504,276
   shares issued and outstanding

5

5

Class F Common stock, $0.01 par value, 1 share authorized, issued, and outstanding

—

—

Class G Common stock, $0.01 par value, 3 shares authorized and 2 shares issued
   and outstanding

—

—

Additional paid in capital

425,207

431,307

Accumulated deficit

(1,452,229
)

(1,051,678
)
Total stockholders' deficit

(1,027,008
)

(620,357
)
Total liabilities and stockholders' deficit

$
826,003

$
1,204,739

	Successor		Predecessor
	June 30,		December 31,
(dollars in thousands, except share data)	2017		2016
	(unaudited)
Liabilities and stockholders’ equity (deficit)
Current liabilities:
Accounts payable and accrued liabilities	$	64,495	$	42,442
Accrued payroll and benefits payable		9,634		3,459
Accrued interest payable		679		732
Revenue distribution payable		13,009		9,426
Long-term debt and capital leases, classified as current		4,813		469,112
Derivative instruments		—		7,525
Total current liabilities		92,630		532,696
Long-term debt and capital leases, less current maturities		305,572		—
Derivative instruments		—		5,844
Deferred compensation		836		—
Asset retirement obligations		64,988		65,456
Liabilities subject to compromise		—		1,284,144
Commitments and contingencies (Note 10)
Stockholders’ equity (deficit):
Predecessor preferred stock, 600,000 shares authorized, none issued and outstanding as of December 31, 2016		—		—
Predecessor Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 333,686 shares issued and outstanding as of December 31, 2016		—		4
Predecessor Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 344,859 shares issued and outstanding as of December 31, 2016		—		3
Predecessor Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882 shares issued and outstanding as of December 31, 2016		—		2
Predecessor Class E Common stock, $0.01 par value, 10,000,000 shares authorized and 504,276 shares issued and outstanding as of December 31, 2016		—		5
Predecessor Class F Common stock, $0.01 par value, 1 share authorized, issued, and outstanding as of December 31, 2016		—		—
Predecessor Class G Common stock, $0.01 par value, 3 shares authorized and 2 shares issued and outstanding as of December 31, 2016		—		—
Predecessor additional paid in capital		—		425,231
Successor preferred stock, 5,000,000 shares authorized, none issued and outstanding as of June 30, 2017		—		—
Successor Class A Common stock, $0.01 par value, 180,000,000 shares authorized and 37,110,630 shares issued and outstanding as of June 30, 2017		371		—
Successor Class B Common stock, $0.01 par value, 20,000,000 shares authorized and 7,871,512 shares issued and outstanding as of June 30, 2017		79		—
Successor additional paid in capital		948,613		—
Retained earnings (accumulated deficit)		1,682		(1,467,398	)
Total stockholders' equity (deficit)		950,745		(1,042,153	)
Total liabilities and stockholders' equity (deficit)	$	1,414,771	$	845,987

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

	Three months ended						Nine months ended						Successor			Predecessor
	September 30,						September 30,						Three months			Three months
(in thousands)	2016			2015			2016			2015
	(unaudited)												ended			ended
(in thousands, except share and per share data)													June 30, 2017			June 30, 2016
Revenues - commodity sales	$	65,847		$	74,512		$	180,076		$	261,801		$	74,048		$	65,990
Costs and expenses:
Lease operating		22,291			24,881			68,462			83,921			23,059			22,756
Transportation and processing		2,429			1,902			6,493			6,246			3,067			2,185
Production taxes		2,174			2,795			6,812			11,123			3,383			2,882
Depreciation, depletion and amortization		29,624			52,027			94,396			173,694			30,851			32,964
Loss on impairment of oil and gas assets		—			737,758			281,079			955,320			—			203,183
Loss on impairment of other assets		202			—			1,461			13,311			—			1,259
General and administrative		1,519			7,389			14,812			25,843			8,973			6,804
Liability management		—			—			9,396			—			—			3,807
Cost reduction initiatives		89			603			3,228			9,739			115			14
Total costs and expenses		58,328			827,355			486,139			1,279,197			69,448			275,854
Operating income (loss)		7,519			(752,843	)		(306,063	)		(1,017,396	)		4,600			(209,864	)
Non-operating income (expense):
Non-operating (expense) income:
Interest expense		(7,436	)		(28,598	)		(57,243	)		(83,202	)		(5,051	)		(20,153	)
Non-hedge derivative gains (losses)		—			85,415			(9,468	)		105,266
Write-off of Senior Note issuance costs, discount and premium		—			—			(16,970	)		—
Derivative gains (losses)														23,474			(21,400	)
Other (expense) income, net		(129	)		108			217			2,088			(551	)		210
Net non-operating (expense) income		(7,565	)		56,925			(83,464	)		24,152			17,872			(41,343	)
Reorganization items, net		(5,504	)		—			(10,859	)		—			(1,070	)		(5,355	)
Loss before income taxes		(5,550	)		(695,918	)		(400,386	)		(993,244	)
Income tax (benefit) expense		(59	)		(48,776	)		165			(161,314	)
Net loss	$	(5,491	)	$	(647,142	)	$	(400,551	)	$	(831,930	)
Income (loss) before income taxes														21,402			(256,562	)
Income tax expense														37			92
Net income (loss)													$	21,365		$	(256,654	)
Net income per share:
Basic													$	0.47		*
Diluted													$	0.47		*
Weighted average shares used to compute net income per share:
Basic														44,982,142		*
Diluted														44,982,142		*

* Item not disclosed. See “Note 1—Nature of operations and summary of significant accounting policies.”

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

	Successor			Predecessor
	Period from			Period from
	March 22, 2017			January 1, 2017			Six months
	through			through			ended
(in thousands, except share and per share data)	June 30, 2017			March 21, 2017			June 30, 2016
Revenues - commodity sales	$	81,856		$	66,531		$	114,229
Costs and expenses:
Lease operating		27,318			19,941			46,171
Transportation and processing		3,428			2,034			4,064
Production taxes		3,699			2,417			4,638
Depreciation, depletion and amortization		34,265			24,915			64,772
Loss on impairment of oil and gas assets		—			—			281,079
Loss on impairment of other assets		—			—			1,259
General and administrative		14,717			6,843			13,293
Liability management		—			—			9,396
Cost reduction initiatives		121			629			3,139
Total costs and expenses		83,548			56,779			427,811
Operating (loss) income		(1,692	)		9,752			(313,582	)
Non-operating (expense) income:
Interest expense		(5,701	)		(5,862	)		(49,807	)
Derivative gains (losses)		11,359			48,006			(9,468	)
Write-off of Senior Note issuance costs, discount and premium		—			—			(16,970	)
Other (expense) income, net		(556	)		1,373			346
Net non-operating (expense) income		5,102			43,517			(75,899	)
Reorganization items, net		(1,690	)		988,727			(5,355	)
Income (loss) before income taxes		1,720			1,041,996			(394,836	)
Income tax expense		38			37			224
Net income (loss)	$	1,682		$	1,041,959		$	(395,060	)
Net income per share:
Basic	$	0.04		*			*
Diluted	$	0.04		*			*
Weighted average shares used to compute net income per share:
Basic		44,982,142		*			*
Diluted		44,982,142		*			*

* Item not disclosed. See “Note 1—Nature of operations and summary of significant accounting policies.”

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

										Retained
							Additional			earnings
	Common stock						paid in			(accumulated
(dollars in thousands)	Shares			Amount			capital			deficit)			Total
Balance at December 31, 2016 - Predecessor		1,392,706		$	14		$	425,231		$	(1,467,398	)	$	(1,042,153	)
Restricted stock forfeited		(1,454	)		—			—			—			—
Restricted stock cancelled		(8,964	)		—			—			—			—
Stock-based compensation		—			—			194			—			194
Net income		—			—			—			1,041,959			1,041,959
Balance at March 21, 2017 - Predecessor		1,382,288			14			425,425			(425,439	)		—
Cancellation of Predecessor equity		(1,382,288	)		(14	)		(425,425	)		425,439			—
Balance at March 21, 2017 - Predecessor		—		$	—		$	—		$	—		$	—


Issuance of Successor common stock - rights offering		4,197,210		$	42		$	49,985		$	—		$	50,027
Issuance of Successor common stock - backstop premium		367,030			4		—				—			4
Issuance of Successor common stock - settlement of claims		40,417,902			404			898,510			—			898,914
Issuance of Successor warrants	—				—			118			—			118
Balance at March 21, 2017 - Successor		44,982,142			450			948,613			—			949,063
Net income		—			—			—			1,682			1,682
Balance at June 30, 2017 - Successor		44,982,142		$	450		$	948,613		$	1,682		$	950,745

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

							Successor			Predecessor
							Period from			Period from
	Nine months ended						March 22, 2017			January 1, 2017			Six months
	September 30,						through			through			ended
(in thousands)	2016			2015			June 30, 2017			March 21, 2017			June 30, 2016
	(unaudited)
Cash flows from operating activities
Net loss	$	(400,551	)	$	(831,930	)
Net income (loss)							$	1,682		$	1,041,959		$	(395,060	)
Adjustments to reconcile net loss to net cash provided by operating activities
Non-cash reorganization items								—			(1,012,090	)		—
Depreciation, depletion and amortization		94,396			173,694			34,265			24,915			64,772
Loss on impairment of assets		282,540			968,631			—			—			282,338
Write-off of Senior Note issuance costs, discount and premium		16,970			—			—			—			16,970
Deferred income taxes		—			(161,480	)
Non-hedge derivative losses (gains)		9,468			(105,266	)
Derivative (gains) losses								(11,359	)		(48,006	)		9,468
Loss (gain) on sale of assets		128			(1,448	)		863			(206	)		(66	)
Other		2,832			4,013			1,120			645			1,998
Change in assets and liabilities
Accounts receivable		(4,866	)		16,625			(11,973	)		198			(12,006	)
Inventories		2,758			(3,642	)		1,596			466			1,837
Prepaid expenses and other assets		(370	)		2,258			1,830			(497	)		(557	)
Accounts payable and accrued liabilities		24,026			(15,012	)		(14,098	)		8,733			22,519
Revenue distribution payable		1,173			(12,444	)		1,983			(1,875	)		(354	)
Stock-based compensation		(5,384	)		(4,355	)
Net cash provided by operating activities		23,120			29,644
Deferred compensation								582			143			(424	)
Net cash provided by (used in) operating activities								6,491			14,385			(8,565	)
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties		(119,994	)		(267,203	)		(61,198	)		(31,179	)		(88,901	)
Proceeds from asset dispositions		954			29,251			1,929			1,884			487
Proceeds from non-hedge derivative instruments		90,590			173,149
Cash in escrow		49			—
Proceeds from derivative instruments								8,355			1,285			74,847
Net cash used in investing activities		(28,401	)		(64,803	)		(50,914	)		(28,010	)		(13,567	)
Cash flows from financing activities
Proceeds from long-term debt		181,000			120,000			18,000			270,000			181,000
Repayment of long-term debt		(1,563	)		(75,354	)		(720	)		(444,785	)		(1,096	)
Proceeds from rights offering, net								—			50,031			—
Principal payments under capital lease obligations		(1,860	)		(1,792	)		(713	)		(568	)		(1,234	)
Payment of other financing fees		—			(1,404	)		—			(2,410	)		—
Net cash provided by financing activities		177,577			41,450
Net increase in cash and cash equivalents		172,296			6,291
Net cash provided by (used in) financing activities								16,567			(127,732	)		178,670
Net (decrease) increase in cash and cash equivalents								(27,856	)		(141,357	)		156,538
Cash and cash equivalents at beginning of period		17,065			31,492			45,123			186,480			17,065
Cash and cash equivalents at end of period	$	189,361		$	37,783		$	17,267		$	45,123		$	173,603

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

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 Texas. 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 March 21, 2017. As discussed in “Note 2—Chapter 11 ~~filing,~~Reorganization,” we ~~are currently operating our business~~filed voluntary petitions for bankruptcy relief and subsequently operated as debtor in possession, in accordance with the applicable provisions of the Bankruptcy ~~Code.~~Code, until our emergence from bankruptcy on March 21, 2017. The cancellation of all existing shares outstanding followed by the issuance of new shares in the reorganized Company upon our emergence from bankruptcy caused a related change of control under US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Company’s consolidated financial statements on or after March 21, 2017, are not comparable with the consolidated financial statements prior to that date.

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, ~~2015.~~2016.

The financial information as of ~~September~~June 30, 2017 (Successor), the three months ended June 30, 2017 (Successor), and 2016 (Predecessor), the periods of March 22, 2017, through June 30, 2017 (Successor) and January 1, 2017, through March 21, 2017 (Predecessor), and the six months ended June 30, 2016 ~~and for the three and nine months ended September 30, 2016, and 2015, respectively,~~(Predecessor), is unaudited. The financial information as of December 31, ~~2015,~~2016, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, ~~2015.~~2016. 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~~June 30, ~~2016,~~2017 and the periods of March 22, 2017, through June 30, 2017 (Successor), and January 1, 2017, through March 21, 2017 (Predecessor), are not necessarily indicative of the results of operations that will be realized for the year ended December 31, ~~2016.~~2017.

We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of ~~September~~June 30, ~~2016,~~2017, cash with a recorded balance totaling ~~$37,535 and $49,852~~approximately $13,981 was held at JP Morgan Chase Bank, ~~N.A and Arvest Bank, respectively. In addition, we also held cash equivalents in the form of treasury securities with a recorded balance of $101,095 at Arvest Wealth Management.~~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. ~~We are not party~~

As of December 31, 2016, we had restricted cash of $1,400 which was required to ~~any valid blocked account agreements with respect to any material amount~~be maintained during the pendency of our bankruptcy. The restricted cash is included in “Cash and cash equivalents” in our consolidated balance sheets. As of June 30, 2017, we no longer had restricted cash.

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. Accounts receivable consisted of the ~~following at September 30, 2016, and December 31, 2015:~~following:

							Successor			Predecessor
	September 30,			December 31,			June 30,			December 31,
	2016			2015			2017			2016
Joint interests	$	10,471		$	14,149		$	22,190		$	13,818
Accrued commodity sales		26,628			21,645			30,756			31,304
Derivative settlements		—			40,380			5,164			—
Other		4,669			3,329			2,349			1,657
Allowance for doubtful accounts		(495	)		(503	)		(558	)		(553	)
	$	41,273		$	79,000		$	59,901		$	46,226

Inventories consisted of the ~~following at September 30, 2016, and December 31, 2015:~~following:

							Successor		Predecessor
	September 30,			December 31,			June 30,		December 31,
	2016			2015			2017		2016
Equipment inventory	$	9,066		$	11,470		$	3,725	$	8,165
Commodities		1,355			1,698			1,564		1,418
Inventory valuation allowance		(2,300	)		(839	)		—		(2,232	)
	$	8,121		$	12,329		$	5,289	$	7,351

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

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 fresh start accounting, a substantial portion of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our STACK play (see “Note 3—Fresh start accounting”).

The costs of unevaluated oil and natural gas properties ~~which are excluded from amortization until the properties are evaluated,~~ consisted of the ~~following at September 30, 2016, and December 31, 2015:~~following:

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~~June 30, ~~2016,~~2017, 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.

~~Due~~ As discussed in “Note 3—Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the ~~substantial decline of commodity prices that began in mid-2014 and which continue to remain low, the cost center ceiling exceeded the net capitalized cost~~carrying value of our oil and natural gas properties at the end of each quarter beginning with the second quarter of 2015 through the second quarter of 2016, resulting in ceiling test write-downs in those periods. The amount of any future impairment is generally difficult to predict, and will dependbeing restated based on ~~the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent~~their fair value.

We recorded ~~impairment losses of $6,015 related~~income tax expense during the Successor and Predecessor periods in 2017 to ~~four drilling rigs~~reflect our obligation for current Texas margin tax on gross revenues less certain deductions. We did not ~~currently~~record any net deferred tax benefit in ~~use for~~ the ~~nine months ended September 30, 2015. One of~~Successor or Predecessor periods in 2017 as any deferred tax asset arising from the ~~rigs was last deployed in January 2015 while the remaining three have been stacked for three to four years. The loss was recorded as~~benefit is reduced by a result of the deterioration in commodity prices and drilling activity whereby the value of such equipment had declined while utilizing third party equipment had become more cost effective, resulting in us impairing the value of the rigs to their estimated fair value. These losses are reflected in “Loss on impairment of other assets” in our consolidated statements of operations.valuation allowance.

~~Our bankruptcy filing on May 9, 2016, (see “Note 2—Chapter 11 filing) was an event~~A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that ~~required an assessment whether the carrying amounts of our long-lived assets would be recoverable. Our evaluation indicated that no additional impairment was necessary as a direct result~~some or all of the ~~bankruptcy.~~

~~In October 2016,~~benefit from the ~~Company entered into an agreement for the sale of our four drilling rigs for a price of $2,000. We anticipate the sale to close in January, 2017.~~

~~Although we recorded a net loss for the nine months ended September 30, 2016, we did not record any corresponding tax benefit as any~~ deferred tax asset ~~arising from~~will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the ~~loss~~jurisdiction in which such taxable income is ~~currently not believed~~generated, to ~~be realizable and is therefore reduced by~~determine whether a ~~valuation allowance. At September 30, 2016, our~~ valuation allowance is ~~$580,280 which reduces~~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.

As of the bankruptcy emergence date of March 21, 2017, we were in a net deferred tax asset position and based on our anticipated operating results in subsequent quarters, we project being in a net deferred tax asset position at December 31, 2017. We believe it is more likely than not that these deferred tax assets will not be realized, and accordingly, recorded a full valuation allowance against our net deferred tax assets ~~to zero value~~ as weof March 21, 2017, and as of June 30, 2017.

We will continue to ~~believe~~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 ~~we will not realize the~~our net deferred tax assets ~~primarily~~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 ~~our cumulative net operating losses. Income~~uncertain tax ~~recognized for the nine months ended September~~positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at June 30, ~~2016, is a result of current Texas margin tax on gross revenues less certain deductions. See “Note 10—Income Taxes” in Item 8. Financial Statement~~2017, and ~~Supplementary Data of our Annual Report on Form 10-K for the year ended~~ December 31, ~~2015, for additional information about our income taxes.~~2016.

As described in “Note 2—Chapter 11 ~~filing~~Reorganization,”, ~~in conjunction with our efforts to restructure~~ elements of the Reorganization Plan provided that our indebtedness on May 9, 2016, we filed voluntary petitions seeking relief under Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware commencing cases for relief under Chapter 11 of the Bankruptcy Code. Our negotiationsrelated to ~~restructure our debt include a proposal for the holders of our~~ Senior Notes ~~to convert~~and certain general unsecured claims were exchanged for Successor common stock in settlement of those ~~notes into equity of the reorganized Company, effectuated through a plan of reorganization in bankruptcy.~~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. ~~Upon~~As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings, the ~~CODI may reduce some or the entire~~estimated amount of ~~prior tax attributes,~~CODI is approximately $61,000, which ~~can include~~will reduce the value of the Company’s net operating ~~losses, capital losses, alternative minimum tax credits and tax basis in assets.~~losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year ~~ending~~ subsequent to the date of ~~emergence.~~emergence, or January 1, 2018. The reduction of net operating losses is expected to be fully offset by a corresponding decrease in valuation allowance.

The IRC provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future taxable income in the event of a change in ownership. Emergence from Chapter 11 bankruptcy proceedings ~~may result~~resulted in a change in ownership for purposes of the ~~IRC. However,~~IRC Section 382. We analyzed alternatives available within the IRC ~~provides alternatives for~~to taxpayers in Chapter 11 bankruptcy proceedings ~~that may or may not~~in order to minimize the impact of the ownership change and CODI on our tax attributes. Upon filing our 2017 U.S. Federal income tax return, we plan to elect an available alternative which would likely result in the Company experiencing a limitation that subjects existing tax attributes at emergence to an ~~annual~~IRC Section 382 limitation that could result in some or all of the remaining net operating loss carryforwards expiring unused. However, we will continue to evaluate the remaining available alternatives which would not subject existing tax attributes to an IRC Section 382 limitation. ~~We are in the process of determining which alternatives are most beneficial to us in conjunction with our ongoing negotiations with our debtholders.~~

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

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

									Successor		Predecessor
	Three months ended				Nine months ended				Three months		Three months
	September 30,				September 30,				ended		ended
	2016		2015		2016		2015		June 30, 2017		June 30, 2016
One-time severance and termination benefits	$	89	$	596	$	3,125	$	7,467	$	111	$	—
Professional fees		—		7		103		2,272		4		14
Total cost reduction initiatives expense	$	89	$	603	$	3,228	$	9,739	$	115	$	14

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 market. Accordingly, we were permitted under accounting guidance to omit such disclosure. However, the OTCQB tier of the OTC Markets Group Inc. began quoting our Class A common stock on May 26, 2017, under the symbol “CHPE”. From May 18, 2017, through May 25, 2017, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP”. Our Class B common stock is not listed or quoted on the OTCQB or any other stock exchange or quotation system. In light of these facts, we are presenting basic and diluted EPS for all Successor periods subsequent to our emergence from bankruptcy but will not be presenting EPS for any Predecessor period. EPS for all Successor periods disclosed is based on the 44,982,142 shares that were issued pursuant to the Company’s Reorganization Plan. Outstanding warrants to purchase 140,023 shares of common stock at an exercise price of $36.78 per share could potentially be dilutive for Successor periods. However, these warrants were antidilutive for all Successor periods in 2017, based on average trading prices since our common stock began trading on the over-the-counter market and thus have been excluded from the denominator in computing diluted EPS.

In ~~November 2015,~~March 2016, the FASB issued authoritative guidance ~~aimed at simplifying~~with the objective to simplify several aspects of the accounting for ~~deferred taxes. To simplify presentation, the new guidance requires that all deferred tax assets~~share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholdings and ~~liabilities, along with any related valuation allowance, be classified as noncurrent~~accounting for forfeitures. Classification of these aspects on the ~~balance sheet. As a result, each jurisdiction will now only~~statement of cash flows is also addressed. We have ~~one net noncurrent deferred tax asset or liability. Importantly, the~~adopted this guidance, does not change the existing requirement that only permits offsetting within a jurisdiction – that is, companies are still prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. This guidancewhich was ~~early adopted on a prospective basis during the second quarter of~~effective for fiscal periods beginning after December 15, 2016, and ~~allowed us~~interim periods thereafter, in the current quarter, with no material impact to ~~offset~~ our ~~noncurrent deferred income tax asset with our current deferred income tax liability. Other than the preceding balance sheet change, the adoption~~financial statements or results of operation. We did not have any previously unrecognized excess tax benefits that required an adjustment to the opening balance of retained earnings under the modified retrospective transition method required by the guidance.

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

In August 2014, the FASB issued authoritative guidance that required entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and required additional disclosures if certain criteria were met. The guidance was adopted on December 31, 2016, and other than discussions regarding our emergence from bankruptcy and the related exit financing in

“Note 2 — Chapter 11 reorganization” and “Note 6—Debt”, there were no additional required disclosures as contemplated by this guidance.

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. For all other entities, it is effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted. We expect that adoption of the new guidance may reduce the likelihood that a future transaction would be accounted for as a business combination although such a determination may require a greater degree of judgment.

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ~~FASB recently approved a delay which will make the~~ updated guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. ~~Early~~The new standard allows for either full retrospective adoption, meaning the standard is ~~permitted~~applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only ~~for fiscal years beginning after December 31,~~to the most current period presented. During 2015 and 2016, the FASB released further updates that, among others, provided supplemental guidance and ~~interim periods thereafter.~~clarification to this topic including clarification on principal vs. agent considerations and identifying performance obligations and licensing. We are currently evaluating the effect the new standard and its subsequent updates will have on our financial statements and results of operations. In 2017, we established an implementation team and engaged external advisers to develop a multi-phase plan to assess our business and contracts, as well as any changes to processes to adopt the requirements of the new standard and its related updates. We are currently evaluating our oil and gas marketing contracts for any potential impact.

In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted. We do not expect this guidance to materially impact our financial statements or results of operations.

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.~~thereafter, and should be applied using a modified retrospective approach. Early adoption is permitted. WeBased on an assessment of our current operating leases, which are ~~currently evaluating the effect the new guidance will have on our financial statements and results~~predominantly comprised of ~~operations.~~

~~In March 2016, the FASB issued authoritative guidance with the objective to simplify several aspects of the accounting~~leases for share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholdings and accounting for forfeitures. Classification of these aspects on the statement of cash flows is also addressed. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter. Early adoption is permitted.

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

WeCO₂ compressors, we do not expect this guidance to materially impact our balance sheet or results of operations. 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 and the potential impact, if any, on our financial statements or results of operations ~~in connection with our outstanding awards.~~

In March 2016, the FASB issued authoritative guidance that clarifies that the assessment of whether an embedded contingent put or call option in a financial instrument is clearly and closely related to the debt host requires only an analysis of the four-step decision sequence described in ASC 815. The guidance is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted in any interim period for which financial statements have not been issued, but would be retroactively applied to the beginning of the year that includes the interim period. We do not expect this guidance to materially impact our financial statements or results of operations.from these arrangements.

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. ~~We are currently evaluating the effect the new~~The updated guidance ~~will have on~~impacts our financial statements primarily due to its effect on our accounts receivables. Our history of accounts receivable credit losses almost entirely relates to receivables from joint interest owners in our operated oil and natural gas wells. Based on this history and on mitigating actions we are permitted to take to offset potential losses such as netting past due amounts against revenue and assuming title to the working interest, we do not expect this guidance to materially impact our financial statements or results of operations.

In August 2016, the FASB issued authoritative guidance which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. The guidance is effective for fiscal years beginning after

December 15, 2017, and is required to be adopted using a retrospective approach if practicable. Early adoption is permitted. We do not expect this guidance to have a material impact on our consolidated statement of cash flows.

In May 2017, the FASB issued authoritative guidance which provides clarification on determining which changes to the terms and conditions of share-based payment awards require an entity to apply modification accounting. The guidance is effective for fiscal years, including interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted in any interim period. The guidance should be applied prospectively to an award modified on or after the adoption date. We plan to early adopt this guidance on July 1, 2017. Since we do not currently have any outstanding share-based awards, we do not expect the guidance to materially impact our financial statements or results of operations.

~~Background.~~Bankruptcy petition and emergence. The severe and sustained decline in oil and natural gas prices since mid-2014 has negatively impacted revenues, earnings and cash flows, and our liquidity. As a result of our deteriorating liquidity, there was uncertainty regarding our ability to repay our outstanding debt obligations as they became due, especially in the event of any acceleration of indebtedness, and hence substantial doubt about our ability to continue as a going concern. This doubt was expressed in the audit opinion of our annual consolidated financial statements for the year ended December 31, 2015, and constituted an event of default under our Credit Facility since the covenants under the facility require us to deliver our annual financial statements without a going concern explanatory paragraph.

On March 1 and April 1, 2016, we elected not to make interest payments on our 8.25% Senior Notes and 9.875% Senior Notes, respectively. Under the indenture governing these Senior Notes, the failure to make the interest payments was subject to a 30-day grace period before constituting an event of default. We did not make either interest payment on the Senior Notes within their respective 30-day grace periods and as a result, are currently in default under the indentures governing these Senior Notes. While in default, the outstanding principal and any accrued interest may be called upon which would cause it to be immediately due and payable. Our failure to make such interest payments within the 30-day grace period also resulted in a cross default under our Credit Facility, capital leases and mortgage note.

The defaults discussed above result in cross defaults on our remaining indebtedness and therefore subjected all our debt to potential acceleration in the event that the outstanding amounts are called by our lenders.

Faced with these defaults, we entered into agreements (the “Forbearance Agreements”) with the lenders under our Credit Facility (the “Lenders”) and an ad hoc committee (the “Ad Hoc Committee”) of noteholders collectively holding more than 50% of the Senior Notes outstanding to forbear from exercising remedies on account of the missed interest payments and certain other alleged defaults specified in the Forbearance Agreements through and including May 1, 2016. While the Forbearance Agreements were in effect, we continued to engage in good-faith arm’s-length negotiations regarding a potential restructuring of the Credit Facility and the Senior Notes that would materially delever the Company’s balance sheet and allow us to retain sufficient liquidity to continue to operate our business going forward. In the course of these negotiations, the Company, the Lenders, and the Ad Hoc Committee exchanged and considered, with the assistance of their respective advisors, numerous restructuring proposals.

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

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

Debtor-In-Possession. During the pendency of the Chapter 11 Cases, ~~constitutes an additional event of default under our Credit Facility, Senior Notes, capital leases and mortgage note.~~

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

~~Debtor-In-Possession.~~ ~~We are currently operating~~we operated our business as ~~debtors in possession~~debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. We have filed a variety of first day motions with the Bankruptcy Court that will allow us to continue to operate our business without interruption. These motions are designed primarily to minimize the impact of our bankruptcy filing on our operations, creditors and employees. The Bankruptcy Court ~~has~~ granted all first day motions filed by us ~~and our~~which were designed primarily to minimize the impact of the Chapter 11 ~~Subsidiaries.~~Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we ~~are~~were able to conduct normal business activities and pay ~~the~~all associated obligations for the post-petition period ~~following our bankruptcy filing~~ and ~~are~~we were also authorized to pay and have paid (subject to ~~caps~~limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest ~~holders and partners.~~holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business ~~require~~required the ~~prior~~ approval of the Bankruptcy Court. ~~Final orders on the motions to satisfy our obligations to certain third parties and to forward funds held by us that belong to third parties were granted on June 7, 2016.~~

Automatic Stay. Subject to certain exceptions, under the Bankruptcy Code, the filing of the bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or the filing of other actions against us or our property to recover, collect or secure a claim arising prior to the Petition Date. ~~Creditors are stayed~~Absent an order from ~~taking any actions against us as a result of debt defaults, subject to certain limited exceptions permitted by the Bankruptcy Code.~~

~~Risks Associated with Chapter 11 Proceedings.~~ For the duration of our Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process. As a result of these risks and uncertainties, the number of our outstanding shares of common stock and stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this quarterly report may not accurately reflect our operations, properties and capital plans following our emergence from bankruptcy.

~~Executory Contracts.~~ ~~In particular, subject to certain exceptions, under the Bankruptcy Code, we may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of~~ the Bankruptcy Court, ~~and certain other conditions. Generally, the rejection~~substantially all of ~~an executory contract or unexpired lease is treated as a~~our pre-petition ~~breach of such executory contract or unexpired lease and,~~liabilities were subject to certain exceptions, relieves us of performing future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires us to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease involving us in these financial statements, including where applicable, a quantification of our obligations under any such executory contract or unexpired lease with us is qualified by our rights to reject such executory contract or unexpired leasesettlement under the Bankruptcy Code.

~~Magnitude~~Plan of ~~Potential Claims~~Reorganization.~~. On June 29, 2016, we filed with the Bankruptcy Court schedules and statements setting forth, among other things, our assets and liabilities, subject~~ Pursuant to the assumptions filed in connection therewith (as amended on August 9 and August 18, 2016, the “Schedules and Statements”). We may subsequently decide to further amend or modify our Schedules and Statements.

On June 13, 2016, we filed a motion to set a bar date to assist with the claims reconciliation process. The Bankruptcy Court approved such motion on July 1, 2016, setting the bar date on August 19, 2016, for all potential claimants other than governmental authorities whose bar date is on November 7, 2016. Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In lightterms of the ~~potential number~~Reorganization Plan, which was supported by us, certain lenders under our Prior Credit Facility (collectively, the “Lenders”) and amount of claims filed, the claims resolution process may take considerable time to complete, and we expect that it will continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

~~Effect of Filing on Creditors and Shareholders.~~ Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities and post-petition liabilities must be satisfied in full or consensual agreement reached between parties before thecertain holders of our ~~existing~~Senior Notes (collectively, the “Noteholders”), the following transactions occurred on or around the Effective Date:

Our timing of filing a plan of reorganization will depend on the timing and outcome of numerous other ongoing matters in the Chapter 11 Cases. Although we expect to file a plan of reorganization that provides for emergence from bankruptcy as a going concern, there can be no assurance at this time that we will be able to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions, that satisfies the conditions of the Bankruptcy Code and is confirmed by the Bankruptcy Court, or that any such plan will be implemented successfully.

~~Basis of Accounting.~~ ~~As noted above,~~the uncertainty regarding our ability to meet our debt obligations and the resultant filing of the Chapter 11 Cases raises substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of our Chapter 11 Cases, other than as set forth under “LiabilitiesLiabilities subject to ~~compromise” and “Reorganization items” on the accompanying consolidated financial statements.~~compromise. In particular, the financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to stockholders’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business. We have accounted for the bankruptcy in accordance with ~~Accounting Standards Codification~~ASC 852 ~~Reorganizations~~.

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

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

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

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

The Company’s reorganization value was derived from enterprise value. Enterprise value represents the estimated fair value of an entity's long-term debt and equity. The enterprise value of the Company on the Effective Date, as ~~liabilities subject to compromise may be subject to future adjustments depending on~~approved by the Bankruptcy Court ~~actions, further development with respect to disputed claims, and other events. Additional amounts may be included~~ in liabilities subject to compromise in future periods if executory contracts and unexpired leases are rejected. Conversely, to the extent that such executory contracts or unexpired leases are not rejected and are instead assumed, certain liabilities characterized as subject to compromise may be converted to post-petition liabilities. Becausesupport of the ~~uncertain nature~~Plan, was estimated to be within a range of ~~many~~$1,050,000 to $1,350,000 with a mid-point value of $1,200,000. Based upon the ~~potential claims,~~various estimates and assumptions necessary for fresh start accounting, as further discussed below, the ~~magnitude~~estimated enterprise value was determined to be $1,200,000 before consideration of ~~such claims is not reasonably estimable~~cash and cash equivalents and outstanding debt at ~~this time. We will continue to evaluate these liabilities during~~ the pendency of the Chapter 11 Cases and adjust amounts as necessary. The magnitude of claims and or the adjustments to such claims may be material. Nothing herein constitutes an admission or waiver of any rights.Effective Date.

The following table ~~summarizes~~reconciles the ~~components~~enterprise value to the estimated fair value of ~~“Liabilities subject~~the Successor’s common stock as of the Effective Date:

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

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

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

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

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

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

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

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

The following consolidated balance sheet is as of ~~September 30, 2016:~~March 21, 2017. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Reorganization Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”) as of the Effective Date:

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

We use this category to reflect, where applicable, post-petition revenues, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. We have incurred and will continue to incur significant costs associated with the reorganization. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations. Reorganization items ~~for the three and nine months ended September 30, 2016,~~ are as follows:

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

							Successor			Predecessor
							Period from			Period from
							March 22, 2017			January 1, 2017			Six months
	Nine months ended September 30,						through			through			ended
	2016			2015			June 30, 2017			March 21, 2017			June 30, 2016
Net cash provided by operating activities included:
Cash payments for interest	$	19,899		$	77,437		$	7,273		$	4,105		$	13,158
Interest capitalized		(1,741	)		(8,115	)		(595	)		(248	)		(1,699	)
Cash payments for interest, net of amounts capitalized	$	18,158		$	69,322		$	6,678		$	3,857		$	11,459
Cash payments for income taxes	$	250		$	639		$	150		$	—		$	250
Cash payments for reorganization items	$	4,255		$	—		$	15,997		$	11,405		$	399
Non-cash financing activities included:
Repayment of Credit Facility with proceeds from early termination of derivative contracts (See Note 4)	$	103,560		$	—
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	4,015		$	3,637		$	1,589		$	716		$	1,299
Change in accrued oil and gas capital expenditures	$	(22,543	)	$	(116,237	)	$	14,195		$	5,387		$	(19,474	)

Prior to our emergence from bankruptcy, our debt primarily consisted of the Prior Credit Facility and our Senior Notes. On the Effective Date, our obligations under the Senior Notes which included principal and accrued interest, and previously classified as liabilities subject to compromise, were fully extinguished in exchange for equity in the Successor. In addition, our Prior Credit Facility, previously consisting of a senior secured revolving credit facility, was restructured into the New Credit Facility consisting of the New Revolver and the New Term Loan. On the Effective Date, the entire balance on the Prior Credit Facility in the amount of $444,440 was repaid while we received gross proceeds, before lender fees, representing the opening balances on our New Revolver of $120,000 and a New Term Loan of $150,000. See “Note 6—Debt” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2016, for further details on our pre-emergence debt facilities.

The New Term Loan, which is collateralized by our oil and natural gas properties, is scheduled to mature on March 21, 2021. Interest on the outstanding amount of the New Term Loan will accrue at an interest rate equal to either: (a) the Alternate Base Rate (as defined in the New Credit Facility) plus a 6.75% margin or (b) the Adjusted LIBO Rate (as defined in the New Credit Facility), plus a 7.75% margin with a 1.00% floor on the Adjusted LIBO Rate. As of June 30, 2017, our outstanding borrowings were accruing interest at the Adjusted LIBO Rate which resulted in an interest rate of 8.84%.

~~Note 4: Debt~~We are required to make scheduled, mandatory principal payments in respect of the New Term Loan according to the schedule below, with the remaining outstanding balance due upon maturity:

The New Revolver is a $400,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on March 21, 2021. Availability under our New Revolver is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request an additional borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base on the Effective Date was $225,000 and the first borrowing base redetermination has been set for on or about May 1, 2018. Availability on the New Revolver as of June 30, 2017, after taking into account outstanding borrowings and letters of credit on that date, was $86,172.

Interest on the outstanding amounts under the New Revolver will accrue at an interest rate equal to either (i) the Alternate Base Rate plus a margin that ranges between 2.00% to 3.00% depending on utilization or (ii) the Adjusted LIBO Rate applicable to one, two, three or six month borrowings plus a margin that ranges between 3.00% to 4.00% depending on utilization. In the case that an Event of Default (as defined under the New Credit Facility) occurs, the applicable rate while in default will be the Alternate Base Rate plus an additional 2.00% and plus the applicable margin. As of June 30, 2017, our outstanding borrowings were accruing interest at the ~~dates indicated, debt consisted~~Adjusted LIBO Rate which resulted in an interest rate of 4.63%.

Commitment fees of 0.50% accrue on the unused portion of the ~~following:~~borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the margin used to determine the interest rate applicable to New Revolver borrowings that are based on Adjusted LIBO Rate.

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

The financial covenants require that we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, (2) an Asset Coverage Ratio (as defined in the New Credit Facility) of no less than 1.35 to 1.00, (3) Liquidity (as defined in the New Credit Facility) of at least $25,000 and (4) a Ratio of Total Debt to EBITDAX (as defined in the New Credit Facility) of no greater than 3.5 to 1.0 calculated on a trailing four-quarter basis. We are ~~currently in default~~required to comply with these covenants for each fiscal quarter ending on ~~all our indebtedness. The defaults stem from, among others, our commencement of~~and after March 31, 2017, except for the Chapter 11 Cases, direct defaults as a result of nonpayment of interest, violations of financial covenants and the inclusion of a going concern explanatory paragraph in the audit opinion of our annual financial statements. Moreover, due to our commencement of the Chapter 11 Cases, all of our indebtedness has been accelerated by operation of law.

The Senior Notes are our senior unsecured obligations and rank equally in right of payment with all our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. Pursuant to accounting guidance while in bankruptcy, our Senior Notes and the associated accrued interest have been classified as “Liabilities subject to compromise” on our consolidated balance sheetsAsset Coverage Ratio, for which compliance is required semiannually as of ~~September~~January 1 and July 1 of each year. We were in compliance with these financials covenants as of June 30, ~~2016. We will not accrue interest expense on our~~2017.

Write-off of Senior ~~Notes during the pendency of the Chapter 11 Cases as we do not expect to pay such interest. As a result, reported interest expense is $25,303~~Note issuance costs, discount and ~~$39,641 lower than contractual interest for the three and nine month periods ending September 30, 2016.~~premium

In March 2016, we wrote off the remaining unamortized issuance costs, premium and discount related to our Senior Notes for a net charge of $16,970. These deferred items are typically amortized over the life of the corresponding bond. However, as a result of not paying the interest due on our 2021 Senior Notes by the end of our ~~30-day~~ grace period on March 31, 2016, ~~as discussed in “Note 2—Chapter 11 filing,”~~ we triggered an Event of Default on our Senior Notes. While uncured, the Event of Default effectively ~~allows~~allowed the lender to demand immediate repayment, thus shortening the life of our Senior ~~Notes to the current period.~~Notes. As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount on March 31, 2016, as follows:

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

In April 2010, we entered into an Eighth Restated Credit Agreement (our “Credit Facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. During the nine months ended September 30, 2016, we had additional borrowings of $181,000 and repayments of $103,560 on our Credit Facility. As discussed in “Note 5—Derivative instruments,” our repayment of $103,560 was effectuated by directly offsetting proceeds payable to us from the termination of our derivative contracts against outstanding borrowings under the Credit Facility during the third quarter of 2016. The ability to offset was possible as the previous counterparties to our derivative contracts are also Lenders. As of September 30, 2016, the weighted average interest rate was 5.0% on outstanding borrowings under Credit Facility. This rate represents the Alternate Base Rate (as defined under the Credit Facility) plus the applicable margin. The Company has not recorded the additional 2.0% default margin interest as the Lenders have agreed to waive that amount upon our exit from bankruptcy pursuant to a non-binding agreement between the Lenders and the Ad Hoc Committee.

Availability under our Credit Facility was subject to a borrowing base which is set by the banks semiannually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. We are currently in negotiations, as part of our reorganization, regarding the structure of our exit financing upon emergence from bankruptcy where we believe such financing will include a revolving credit facility subject to a borrowing base.

Subject to certain exceptions, under the Bankruptcy Code, the commencement of the Chapter 11 Cases automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or the filing of other actions against us or our property to recover, collect or secure a claim arising prior to the Petition Date. Creditors are stayed from taking any actions against us as a result of debt defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. There can be no assurances that the agent and lenders will consensually agree to a restructuring of the Credit Facility. Any proposed non-consensual restructuring of the Credit Facility could result in substantial delay in emergence from bankruptcy and there can be no assurances that the Bankruptcy Court would approve such proposed non-consensual restructuring. During the Chapter 11 Cases, we expect to remain current on our interest payments under the Credit Facility to the extent required by order of the Bankruptcy Court.

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool. The lease financing obligations are for ~~84 -month~~84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are approximately $3,181 annually. ~~As discussed previously, our debt defaults and the commencement of the Chapter 11 Cases are events of default under our capital leases.~~

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 ~~previously entered~~enter into various types of derivative instruments, including commodity price swaps, ~~enhanced price swaps,~~ collars, put options, enhanced swaps and basis protection swaps. ~~We also previously entered into~~See “Note 7—Derivative Instruments” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2016, for a description of the various kinds of derivatives we may enter into.

The following table summarizes our crude oil ~~derivative contracts to hedge a portion~~derivatives outstanding as of June 30, 2017:

~~Due to defaults under the master agreements governing our derivative contracts, our~~derivatives outstanding ~~derivative positions were terminated in May 2016 and we have no outstanding derivative contracts~~ as of ~~September~~June 30, 2016. As discussed in “Note 6—Fair value measurements” all the counterparties to our derivative transactions are also financial institutions within the lender group under our Credit Facility. The derivative master agreements with these counterparties generally specify that a default under any of our indebtedness, as well as any bankruptcy filing, is an event of default which may result in early termination of the derivative contracts. Proceeds from the early terminations, inclusive of amounts receivable at the time of termination for previous settlements, totaled $119,303. Of this amount, in the third quarter of 2016, $103,560 was utilized to offset outstanding borrowings under our Credit Facility and the remainder was remitted to the Company.2017:

While we are in default on our indebtedness and have a bankruptcy filing, we will no longer be able to represent that we can comply with the credit default or bankruptcy covenants under any prospective derivative master agreements and thus may not be able to enter into new hedging transactions. We are currently negotiating with the Lenders, most of which were previously counterparties to our derivative contracts, regarding the resumption of hedging activity prior to our potential emergence from bankruptcy. However, there can be no assurance that we will be able to enter into new derivative transactions on terms that are acceptable to us.

All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 6—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.

								Successor							Predecessor
	As of December 31, 2015							June 30, 2017							December 31, 2016
	Assets		Liabilities			Net value		Assets		Liabilities			Net value		Assets		Liabilities			Net value
Natural gas derivative contracts	$	41,328	$	(1,158	)	$	40,170	$	1,466	$	(148	)	$	1,318	$	184	$	(3,658	)	$	(3,474	)
Crude oil derivative contracts		123,068		—			123,068		35,038		—			35,038		—		(9,895	)		(9,895	)
Total derivative instruments		164,396		(1,158	)		163,238		36,504		(148	)		36,356		184		(13,553	)		(13,369	)
Less:
Netting adjustments (1)		1,158		(1,158	)		—		148		(148	)		—		184		(184	)		—
Derivative instruments - current		143,737		—			143,737		23,275		—			23,275		—		(7,525	)		(7,525	)
Derivative instruments - long-term	$	19,501	$	—		$	19,501	$	13,081	$	—		$	13,081	$	—	$	(5,844	)	$	(5,844	)

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

											Successor		Predecessor
											Period from		Period from
	Three months ended				Nine months ended						March 22, 2017		January 1, 2017		Six months
	September 30,				September 30,						through		through		ended
	2016		2015		2016			2015			June 30, 2017		March 21, 2017		June 30, 2016
Change in fair value of commodity price derivatives	$	—	$	30,941	$	(163,238	)	$	(67,883	)	$	3,004	$	46,721	$	(163,238	)
Settlement gains on commodity price derivatives		—		54,474		62,626			157,754			8,355		1,285		62,626
Settlement gains on early terminations of commodity price derivatives		—		—		91,144			15,395			—		—		91,144
Total non-hedge derivative gains (losses)	$	—	$	85,415	$	(9,468	)	$	105,266
Total derivative gains (losses)											$	11,359	$	48,006	$	(9,468	)

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:

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.

~~Our~~As of June 30, 2017, and December 31, 2016, our financial instruments recorded at fair value on a recurring basis ~~consist~~consisted of commodity derivative contracts (see “Note 5—6—Derivative instruments”). We had no Level 1 assets or liabilities. Our derivative contracts classified as Level 2 consisted of commodity price ~~swaps and basis protection~~ swaps which are valued using an income approach. Future cash flows from the ~~derivatives~~commodity price swaps are estimated based on the difference between the fixed contract price and the underlying published forward market ~~price, and are discounted at the LIBOR swap rate.~~price. Our derivative contracts classified as Level 3 consisted of ~~three-way collars, enhanced swaps, and purchased puts.~~collars. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or ~~that of~~ our ~~counterparties~~counterparty credit risk for derivative assets. As discussed in “Note 5—Derivative instruments,” due to defaults under the master agreements governing our derivative contracts, all our outstanding derivative positions were terminated in May 2016 and we have no outstanding derivative contracts as of September 30, 2016.

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

									Successor								Predecessor
	As of December 31, 2015								June 30, 2017								December 31, 2016
	Derivative assets			Derivative liabilities			Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	41,328		$	(1,158	)	$	40,170	$	35,599		$	(148	)	$	35,451	$	184		$	(13,455	)	$	(13,271	)
Significant unobservable inputs (Level 3)		123,068			—			123,068		905			—			905		—			(98	)		(98	)
Netting adjustments (1)		(1,158	)		1,158			—		(148	)		148			—		(184	)		184			—
	$	163,238		$	—		$	163,238	$	36,356		$	—		$	36,356	$	—		$	(13,369	)	$	(13,369	)

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

Changes in the fair value of our derivative instruments, classified as Level 3 in the fair value hierarchy, ~~during~~were as follows for the ~~nine months ended September 30, 2016~~periods presented:

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~~six months of ~~2016~~2017 and ~~2015~~2016 were escalated using an annual inflation rate of ~~2.42%~~2.30% and ~~2.91%~~2.42%, ~~respectively,~~respectively. The estimated future costs to dispose of properties added once we emerged from bankruptcy through June 30, 2017, were discounted, depending on the economic remaining estimated life of the property or the expected timing of the plugging and ~~discounted using~~abandonment activity, with a credit-adjusted risk-free rate ranging from 5.20% to 7.63%. The discount rate used for the six months ended June 30, 2016, was our weighted average credit-adjusted risk-free interest rate of 20.00% ~~and 13.45%, respectively.~~. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 7—8—Asset retirement obligations” for additional information regarding our asset retirement obligations.

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

The carrying value and estimated fair value of our debt, ~~at September 30, 2016, and December 31, 2015,~~ were as follows:

									Successor				Predecessor
	September 30, 2016				December 31, 2015				June 30, 2017				December 31, 2016
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value		Carrying value (1)		Estimated fair value		Carrying value (1)		Estimated fair value
New Revolver									$	138,000	$	138,000	$	—	$	—
New Term Loan										149,567		149,567		—		—
Other secured debt										9,397		9,397		10,029		10,029
9.875% Senior Notes due 2020	$	298,000	$	203,385	$	293,815	$	75,750		—		—		298,000		268,200
8.25% Senior Notes due 2021		384,045		248,746		384,045		96,956		—		—		384,045		344,680
7.625% Senior Notes due 2022		525,910		352,360		530,849		120,478		—		—		525,910		470,689
Other secured debt		10,418		10,418		11,981		11,981

The carrying value of our New Revolver, New Term Loan 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. We have not disclosed the fair value of outstanding amounts under our Prior Credit Facility as of December 31, 2016, as it iswas not practicable to obtain a reasonable estimate of such value while the ~~Company is~~Predecessor was in ~~bankruptcy and the terms of the facility are being negotiated in conjunction with its reorganization.~~bankruptcy.

Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our ~~Credit Facility~~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 ~~senior secured revolving~~ credit ~~facility~~facilities can be offset against amounts owed to such counterparty Lender. As of ~~December 31, 2015,~~June 30, 2017, the counterparties to our open derivative contracts consisted of ~~seven~~four financial ~~institutions, of which all were subject to our rights of offset under our Credit Facility.~~institutions.

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 ~~senior secured revolving~~ credit ~~facility~~facilities that are available to offset our net derivative assets due from counterparties that are ~~Lenders.~~lenders under our credit facilities.

	Offset in the consolidated balance sheets								Gross amounts not offset in the consolidated balance sheets							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 senior secured revolving credit facility			Net amount		Gross assets (liabilities)			Offsetting assets (liabilities)			Net assets (liabilities)			Derivatives (1)		Amounts outstanding under credit facilities			Net amount
As of December 31, 2015
Successor - June 30, 2017
Derivative assets	$	164,396		$	(1,158	)	$	163,238	$	—	$	(103,618	)	$	59,620	$	36,504		$	(148	)	$	36,356		$	—	$	(36,356	)	$	—
Derivative liabilities		(1,158	)		1,158			—		—		—			—		(148	)		148			—			—		—			—
	$	163,238		$	—		$	163,238	$	—	$	(103,618	)	$	59,620	$	36,356		$	—		$	36,356		$	—	$	(36,356	)	$	—


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

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our ~~senior secured revolving~~ credit ~~facility.~~facilities. Payment on our derivative contracts ~~would have been~~could be accelerated in the event of a default on our ~~senior secured revolving credit facility.~~New Credit Facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was ~~$1,158~~$148 at December 31, 2015. As discussed previously, the defaults of our derivative master agreements resulted in the termination of all our contracts in May 2016 and resulted in amounts payable to us by our counterparties.June 30, 2017.

The following table provides a summary of our asset retirement obligation ~~activity during the nine months ended September 30, 2016 and 2015.~~activity:

	Nine months ended September 30,
	2016			2015
Beginning balance	$	48,612		$	47,424
Liability for asset retirement obligations as of December 31, 2016 (Predecessor)							$	72,137
Liabilities incurred in current period		2,554			1,852			535
Liabilities settled and disposed in current period		(1,380	)		(4,886	)		(869	)
Revisions in estimated cash flows		1,461			1,785			181
Accretion expense		2,859			2,727			1,249
Ending balance		54,106			48,902
Liability for asset retirement obligations as of March 21, 2017 (Predecessor)							$	73,233
Fair value fresh-start adjustment							$	(2,757	)
Liability for asset retirement obligations as of March 21, 2017 (Successor)							$	70,476
Liabilities incurred in current period								1,204
Liabilities settled and disposed in current period								(984	)
Revisions in estimated cash flows								385
Accretion expense								1,091
Liability for asset retirement obligations as of June 30, 2017 (Successor)							$	72,172
Less current portion included in accounts payable and accrued liabilities		3,895			2,384			7,184
	$	50,211		$	46,518
Asset retirement obligations, long-term							$	64,988

See “Note 6—7—Fair value measurements” for additional information regarding fair value assumptions associated with our asset retirement obligations.

~~Effective January 1, 2004,~~Prior to our emergence from bankruptcy, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). Under the Phantom Plan, awards vest at the end of five years, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

~~Effective March 1, 2012, we implemented~~had a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success.in effect as an incentive plan for nonexecutive employees. The provisions under our RSU Plan ~~is intended to replace~~are discussed in Note 11 — Deferred compensation in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the ~~Phantom Plan. There are no~~year ended December 31, 2016. As of January 1, 2017, there were 98,596 unvested and outstanding ~~Phantom Plan awards remaining and we do not expect to make any further awards under the Phantom Plan.~~

~~Under the RSU Plan, restricted stock units may be awarded to Participants in an aggregate amount of up to 2% of the~~Restricted Stock Units with a weighted average grant date fair ~~market~~ value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three-year period. RSU awards may also vest following a Participant’s termination of employment in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.

~~A summary of our phantom stock and RSU activity during the nine months ended September 30, 2016, is presented in the following table:~~

Phantom Plan

RSU Plan

Weighted
average
grant date
fair value

Phantom
shares

Vest
date
fair
value

Weighted
average
grant date
fair value

Restricted Stock
Units

Vest
date
fair
value

($ per share)

($ per share)

Unvested and outstanding at January 1, 2016

$
18.62

10,619

$
10.53

269,886

Granted

$
—

—

$
—

—

Vested

$
18.39

(9,729
)

$
—

$
9.01

(140,818
)

$
—

Forfeited

$
21.09

(890
)

$
8.24

(28,769
)

Unvested and outstanding at September 30, 2016

$
—

—

$
7.20

100,299

Due to the severe decline in commodity pricing, which has resulted in a steep decline in our estimated proved reserves, the estimated fair value per RSU as of ~~September 30, 2016, is~~January 1, 2017, was $0.00. ~~The weighted average period until all~~All remaining ~~RSUs vest is 0.6 years.~~unvested awards were cancelled upon our emergence from bankruptcy on the Effective Date.

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

On April 3, 2017, the Company awarded an additional $3,321 under the 2015 Cash LTIP. As of June 30, 2017, the outstanding liability accrued for our 2015 Cash LTIP, based on requisite service provided, was $1,799.

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

The awards granted under the 2010 Plan ~~consist~~consisted of shares that ~~are~~were subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vested conditions (the “Performance Vested” awards).

The Time Vested awards vest in equal annual installments over the five -year vesting period, but may also vest on an accelerated basis in the event of a transaction whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

in the restricted stock agreements). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.

Our 2010 Plan allows participants to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. As a result of this provision, the Time Vested awards are classified as liability awards under accounting guidance and remeasured to fair value at the end of each reporting period. The Performance Vested awards are classified as equity awards and are not remeasured to fair value at the end of each reporting period subsequent to grant date.

~~We have previously modified the vesting conditions of awards granted~~material provisions under the 2010 ~~Plan. Please see~~Plan are discussed in “Note 11—~~Stock-based~~Deferred compensation” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, ~~2015, for a discussion of the modifications.~~2016.

~~A summary of our restricted stock activity during the nine months ended September 30, 2016, is presented below:~~

Time Vested

Performance Vested

Weighted
average
grant date
fair value

Restricted
shares

Vest
date
fair
value

Weighted
average
grant date
fair value

Restricted
shares

($ per share)

($ per share)

Unvested and outstanding at January 1, 2016

$
795.13

13,979

$
278.97

28,448

Granted

$
—

—

$
—

—

Vested

$
798.85

(5,279
)

$
93

$
—

—

Forfeited

$
810.01

(1,773
)

$
293.62

(6,374
)
Unvested and outstanding at September 30, 2016

$
788.48

6,927

$
274.74

22,074

~~During the nine months ended September 30, 2016 and 2015, we repurchased and canceled 2,597 and 5,678 vested shares, respectively.~~ As of result of our bankruptcy, the estimated fair value of our Time Vested restricted awards was $0.00 per share ~~resulting in an aggregate intrinsic value of all outstanding unvested Time Vested restricted shares of $0 as of September 30, 2016.~~since the Petition Date. Furthermore, during the third quarter of 2016, we recorded a cumulative catch up adjustment of ~~$5,985~~ to reverse the aggregate compensation cost associated with our Performance Vested awards in order to reflect a decrease in the probability that requisite service would be achieved for these awards. ~~We anticipate that~~Pursuant to our ~~reorganization under Chapter 11 of the Bankruptcy Code will ultimately result in the cancellation of~~Reorganization Plan, all outstanding restricted shares were cancelled. As this cancellation was not accompanied by the concurrent grant of (or offer to grant) a replacement award or other valuable consideration, it was accounted for as a repurchase for no consideration. Accordingly, any previously unrecognized compensation cost was recognized at the cancellation date.

Chaparral Energy, Inc. and ~~therefore we do not expect any future repurchases~~subsidiaries

A summary of ~~these shares.~~our restricted stock activity for the Predecessor period in 2017 is presented below:

	Time Vested							Performance Vested
	Weighted average grant date fair value		Restricted shares			Vest date fair value		Weighted average grant date fair value		Restricted shares
	($ per share)							($ per share)
Unvested and outstanding at January 1, 2017 - Predecessor	$	790.91		6,667				$	277.33		21,475
Granted	$	—		—				$	—		—
Vested	$	812.91		(2,602	)	$	—	$	—		—
Forfeited	$	785.70		(468	)			$	195.75		(986	)
Cancelled	$	775.66		(3,597	)			$	281.26		(20,489	)
Unvested and outstanding at March 21, 2017 - Predecessor	$	—		—				$	—		—

Compensation cost is calculated net of forfeitures. As allowed by recent accounting guidance, we will recognize the impact of forfeitures ~~which are estimated based~~due to employee terminations on ~~our historical~~expense as they occur instead of incorporating an estimate of such forfeitures. For awards with performance conditions, we will assess the probability that a performance condition will be achieved at each reporting period to determine whether and ~~expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based~~when to recognize compensation ~~cost could be different from what we have recorded in the current period.~~cost.

A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We ~~recognized~~have not incurred stock-based compensation expense from our Effective Date through June 30, 2017, as there were no awards granted during this period and all previously outstanding awards were cancelled on the Effective Date. Stock-based compensation expense is as follows for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,						Predecessor
	2016			2015			2016			2015			Period from January 1, 2017 through March 21, 2017			Three months ended June 30, 2016			Six months ended June 30, 2016
Stock-based compensation cost (credit)	$	(5,705	)	$	(581	)	$	(6,220	)	$	(143	)	$	194		$	383		$	(515	)
Less: stock-based compensation cost capitalized		1,167			(49	)		965			(352	)		(39	)		(77	)		(202	)
Stock-based compensation expense (credit)	$	(4,538	)	$	(630	)	$	(5,255	)	$	(495	)	$	155		$	306		$	(717	)
Payments for stock-based compensation	$	—		$	333		$	49		$	3,977		$	—		$	—		$	49

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

~~Our~~The credit for stock-based compensation ~~expense~~ for ~~periods disclosed includes credits due to~~the six months ended June 30, 2016, was primarily a result of forfeitures from our workforce ~~reductions~~reduction in January 2016 and ~~February 2015,~~ lower valuations of our liability-based ~~awards and the cumulative adjustment on our Performance Vested awards discussed previously.~~awards. As of ~~September~~June 30, ~~2016,~~2017, and December 31, ~~2015,~~2016, accrued payroll and benefits payable included $0 and ~~$81,~~$0, respectively, for stock-based compensation costs expected to be settled within the next twelve months. ~~Unrecognized~~We did not have any unrecognized compensation cost ~~is approximately $244 all~~as of ~~which relates to our Time Vested awards.~~June 30, 2017.

Standby letters of credit (“Letters”) available under our Credit Facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had Letters outstanding totaling $828 as of ~~September~~June 30, ~~2016,~~2017, and December 31, ~~2015.~~2016. When amounts under the Letters are paid by the lenders, interest accrues on the amount paid at the same interest rate applicable to borrowings under the Credit Facility. No amounts were paid by the lenders under the Letters; therefore, we paid no interest on the Letters during the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017 or ~~2015.~~2016.

Chapter 11 Proceedings.Commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016, and the claims remain subject to bankruptcy court jurisdiction. In connection with the proofs of claim asserted during bankruptcy from the proceedings or actions below, we are unable to estimate the amounts that will be allowed bythrough the Bankruptcy ~~Court~~proceedings due to the complexity and number of legal and factual issues presented by the matters and uncertainties with respect to, amongst other things,

the nature of the claims and defenses, the potential size of the ~~class,~~classes, the scope and types of the properties and agreements involved, and the ultimate potential outcomes of the matters. As a result, no reserves ~~have been~~were established within our liabilities ~~subject to compromise~~ in connection with the proceedings and actions described below. To the extent that any of these legal proceedings result in a claim being allowed against us, pursuant to the terms of the Reorganization Plan, such claims will be satisfied through the issuance of new stock in the Company or, if the amount is such claim is below the convenience class threshold, through cash settlement.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor ~~Farms Case”~~Trial Court”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in ~~Oklahoma.~~Oklahoma (“Naylor Farms Case”). The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. Responsive briefs to both motions were filed in the fourth quarter of 2015. ~~The court has not ruled on the motions, and no hearing has been scheduled.~~ On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. In response, on May 23, 2016, the court issued an order administratively closing the case, subject to reopening depending on the disposition of the bankruptcy proceedings. On July 22, 2016, attorneys for the putative class filed a motion in the Bankruptcy Court asking the court to lift the automatic stay and allow the case to proceed in the ~~United States District Court for the Western District of Oklahoma.~~Naylor Trial Court. We did not object to lifting the automatic stay with regard to this case for the limited purpose of allowing the ~~District~~Naylor Trial Court to rule on the pending motion for class ~~certification,~~certification. On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the Plaintiffs originally sought to certify. On January 30, 2017, the Company filed a motion for reconsideration with the Naylor Trial Court, asking the court to rule the class cannot be immediately certified because Plaintiffs did not define dates for class membership. Plaintiffs responded the class should include claims reaching back to December 1, 1999, to which we responded the statute of limitations should limit the beginning of the class period to June 1, 2006. The Naylor Trial Court denied our motion for reconsideration on April 18, 2017, issuing an order certifying the class to include only claims relating back to June 1, 2006. On May 1, 2017, we filed a Petition for Permission to Appeal Class Certification Order with the Tenth Circuit Court of Appeals (the “Tenth Circuit”). Plaintiffs objected, but on June 6, 2017, the Tenth Circuit granted permission to appeal the class certification issue is under consideration by the trial judge in the United States District Court for the Western District of Oklahoma. The plaintiffs’ motion to lift the automatic stay regarding the pending motion for summary judgment is pending in the Bankruptcy Court and is scheduled for a hearing on November 22, 2016. order.

The plaintiffs have indicated ~~if the class is certified,~~ they seek damages in excess of $5,000, which may increase with the passage of time, a majority of which damages would be comprised of interest. In addition to filing claims on behalf of the named plaintiffs and associated parties, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $150,000 in our Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. The Bankruptcy Court heard testimony and arguments regarding class-wide treatment of the claim on February 28, 2017. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs may file a claim on behalf of the class. We appealed the Bankruptcy Court order on June 7, 2017. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims, to which we will also object. Under the Reorganization Plan, the Plaintiffs are identified as a separate class of creditors, Class 8. Class 8 claims are entitled to receive their pro rata share of new stock issued to the holders of general unsecured claims (including claims of the Noteholders). Although the members of Class 8 voted to reject the Plan, the Bankruptcy Court confirmed the Plan on March 10, 2017, without objection by the Plaintiffs. If the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgment or settlement of the unsecured claims would be satisfied through the issuance of new stock in the Company. We continue to dispute the plaintiffs’ allegations, dispute the case meets the requirements for class certification, and ~~anticipate~~are objecting to the ~~claims.~~claims both individually and on a class-wide basis.

Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. OnMay 10, 2013, Amanda Dodson filed a complaint against us in the District Court of Mayes County, Oklahoma, (“Dodson Case”) with an allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include claims for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition,

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

denied the allegations and raised a number of affirmative defenses. At the time we filed our Bankruptcy Petitions, a class had not been certified and discovery had not yet commenced. ~~As the~~The plaintiffs in the Dodson case did not file proofs of claim either for the putative class or the putative class ~~representative, we anticipate any liability related~~representative. The case was voluntarily dismissed without prejudice on July 19, 2017.

Condensed notes to ~~this claim will be discharged.~~consolidated financial statements (unaudited) – continued

Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs challenged leases and drilling permits approved by the Bureau of Indian Affairs without the environmental studies allegedly required under the National Environmental Protection (NEPA). The plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study voidab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. On March 31, 2016, the Court dismissed the case against the federal agencies named as defendants, and therefore against all defendants, as an improper challenge under NEPA and the Administrative Procedures Act. On April 29, 2016, the plaintiffs filed a motion to alter or amend the court’s opinion and vacate the judgment, arguing the court does have jurisdiction to hear the claims and dismissal of the federal defendants does not require dismissal of the oil company defendants. The plaintiffs also filed a motion to file an amended complaint to cure the deficiencies which the court found in the dismissed complaint. Several defendants have filed briefs objecting to plaintiffs’ motions. On May 20, 2016, the Company filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code, and has not responded to the plaintiffs’ motions. After a motion for reconsideration was denied, Plaintiffs filed a Notice of Appeal on December 6, 2016. On December 30, 2016, the Court of Appeals entered an Order Abating Appeal due to pending bankruptcy proceedings of multiple defendants. On January 13, 2017, Plaintiffs responded to the Order Abating Appeal, asking the Court to proceed with the appeal. The ~~court~~Court lifted the stay as to Chaparral on April 13, 2017 and we joined the answer filed by other non-federal defendants which had been filed on March 24, 2017. The Court has not ~~yet ruled.~~ ruled on the appeal.

As the plaintiffs in the Donelson case did not file proofs of claim either for the putative class or the putative class representatives, we anticipate any monetary liability related to this claim will be discharged. We dispute plaintiffs’ allegations and dispute that the case meets the requirements for a class ~~action.~~action.

Lisa West and Stormy Hopson, individually and as class representatives on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On February 18, 2016, an alleged class action was filed against us, as well as several other operators in the District Court of Pottawatomie County, State of Oklahoma (“West Case”), alleging claims on behalf of named plaintiffs and all similarly situated persons having an insurable real property interest in ~~Cleveland, Lincoln, McClain, Okfuskee, Oklahoma, Pontotoc, Pottawatomie and Seminole Counties,~~eight counties in central Oklahoma (the “Class Area”). The plaintiffs allege the oil and gas operations conducted by us and the other defendants have induced or triggered earthquakes in the Class Area. The plaintiffs are asking the court to require the defendants to reimburse plaintiffs and class members for earthquake insurance premiums from 2011 through a future date defined as the time at which the court determines there is no longer a risk that our activities induce or trigger earthquakes, as well as attorney fees and costs and other relief. The plaintiffs ~~have~~did not ~~asked~~ask for damages related to actual property damage which may have occurred. We ~~have~~ responded to the petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. On March 18, 2016, the case was removed to the United States District Court for the Western District of Oklahoma under the Class Action Fairness Act (“CAFA”). On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. On October 14, 2016, the plaintiffs filed an Amended Complaint adding additional defendants and increasing the Class Area to 25 Central Oklahoma counties. Although we are named as a defendant, the Amended Complaint expressly limits its claims against us to those asserted in the original petition unless and until the automatic stay is lifted. Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75,000 in our Chapter 11 Cases. Other defendants have filed motions to dismiss the action based on various theories, as well as motions to strike various allegations and requested relief as unsupported by Oklahoma law. A hearing on the various motions to dismiss and motions to strike was held on May 12, 2017. The judge made various rulings from the bench, including dismissing the complaint for failure to adequately allege causation, but permitting the plaintiffs to amend the complaint to cure the deficiency. Plaintiffs filed a Second Amended Petition on July 18, 2017, adding additional named plaintiffs as putative class representatives. Three additional counties in Oklahoma, including Tulsa, Osage and McClain, were added to the putative class area. The Plaintiffs seek damages for nuisance, negligence, abnormally dangerous activities, and trespass. Due to Chaparral’s bankruptcy, Plaintiffs specifically limit alleged damages related to Chaparral’s disposal activities occurring after our emergence from bankruptcy on March 21, 2017. We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case.

Lisa Griggs and April Marler, on behalf of themselves and other Oklahoma citizens similarly situated v. New Dominion, L.L.C. et al. On July 21, 2017, an alleged class action was filed against us, as well as several other operators, in the District Court of Logan County, State of Oklahoma. The named plaintiffs assert claims on behalf of themselves and Oklahoma citizens owning a home or business between March 30, 2014, and the present in eight counties in central Oklahoma, including Logan, Payne, Lincoln, Oklahoma, Canadian, Kingfisher, Garfield and Noble Counties. The plaintiffs allege disposal of saltwater produced during oil and gas operations

conducted by us and the other defendants have induced or triggered earthquakes in the Class Area, and that each defendant has liability under theories of ultra-hazardous activities, negligence, nuisance, and trespass. The plaintiffs have asked the court to award unspecified compensatory and punitive damages, along with pre-judgment and post-judgment interest.

With regard to Chaparral, the plaintiffs allege our activities induced earthquakes occurring prior to the time we filed our Bankruptcy petition. The plaintiffs did not file a proof of claim related to these claims. We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the plaintiffs are entitled to recovery under our Reorganization Plan, and are vigorously defending the case.

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

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to CO₂ recycle compressors at our EOR facilities and office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase obligations primarily relate to ~~contracts~~a contract for the purchase of CO₂and drilling rig services. ~~In May 2016, we took delivery of an additional CO~~₂ ~~compressor for which we have entered into an 84 month lease with monthly payments of $23.~~ Other than ~~additional~~

~~Chaparral Energy, Inc.~~changes to our credit facility (see “Note 5—Debt”) and ~~subsidiaries~~

~~Condensed notes to consolidated financial statements (unaudited) – continued~~

~~debt borrowings during~~ the ~~year~~discharge of our Senior Notes and certain general unsecured claims pursuant our ~~new compressor lease discussed above, there were no~~Reorganization Plan (see “Note 3—Chapter 11 reorganization”), the only other material ~~changes~~change to our contractual commitments since December 31, ~~2015.~~2016, relates to our contracts for drilling rig services. As of June 30, 2017, our obligations under our drilling rig contracts were approximately $3,060.

The following discussion and analysis is intended to assist ~~you~~ in understanding our ~~business~~financial condition and results of operations ~~together with our present financial condition. This section~~for the three months ended June 30, 2017 (Successor), and 2016 (Predecessor), the periods of March 22, 2017, through June 30, 2017 (Successor) and January 1, 2017, through March 21, 2017 (Predecessor), and the six months ended June 30, 2016 (Predecessor). The information should be read in conjunction with our unaudited consolidated financial statements and the ~~accompanying~~ notes thereto included ~~elsewhere~~ in this ~~report.~~quarterly report as well as the information included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, though as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh-start accounting. References to "Successor" relate to the financial position and results of operations of the reorganized company subsequent to March 21, 2017. References to "Predecessor" relate to the financial position and results of operations of the Company prior to, and including, March 21, 2017.

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

Founded in 1988 and headquartered in Oklahoma City, we are a ~~pure play~~ Mid-Continent independent oil and natural gas exploration and production company. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids-rich STACK play, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage and Woodford formations. ~~In addition, we~~We also have significant ~~holdings in the Mississippi Lime play and a leadership position in~~production from CO₂ EOR ~~where we are the third largest CO~~₂ ~~EOR operator in the United States based on the number of active projects. This position is~~methods underscored by our activity in the North Burbank Unit in Osage County, Oklahoma, which is the single largest oil recovery unit in the state. ~~We are currently operating our business~~Our reserves as ~~debtors in possession in accordance with the applicable provisions~~ of ~~the Bankruptcy Code.~~December 31, 2016, were 43% proved developed, 74% crude oil, 17% natural gas and 9% natural gas liquids.

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

Generally, our producing properties have declining production rates. Our December 31, ~~2015,~~2016, reserve estimates reflect that our production rate on current proved developed ~~producing reserve~~ properties will decline at annual rates of approximately ~~18%~~15%, ~~15%~~13%, and ~~10%~~15% for the next three years. To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

Oil and natural gas prices fluctuate widely. We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The prices we receive for our oil and natural gas production affect our:

~~The severe~~Bankruptcy petition and sustained decline in oil and natural gas prices since mid-2014 has negatively impacted revenues, earnings and cash flows, and our liquidity. As a result of our deteriorating liquidity, there was and continues to be uncertainty regarding our ability to repay our outstanding debt obligations as they became due, especially in the event of any acceleration of indebtedness, and hence substantial doubt about our ability to continue as a going concern. This doubt was expressed in the audit opinion of our annual consolidated financial statements for the year ended December 31, 2015, and constituted an event of default under our Credit Facility since the covenants under the facility require us to deliver our annual financial statements without a going concern explanatory paragraph.

emergence.On March 1 and April 1, 2016, we elected not to make interest payments on our 8.25% Senior Notes and 9.875% Senior Notes, respectively. Under the indenture governing these Senior Notes, the failure to make the interest payments was subject to a 30-day grace period before constituting an event of default. We did not make either interest payment on the Senior Notes within their respective 30-day grace periods and as a result, are currently in default under the indentures governing these Senior Notes.

The defaults discussed above resulted in cross defaults on our remaining indebtedness and therefore subjected all our debt to potential acceleration in the event that the outstanding amounts are called by our lenders.

Faced with these defaults, we entered into agreements (the “Forbearance Agreements”) with the lenders under our Credit Facility (the “Lenders”) and an ad hoc committee (the “Ad Hoc Committee”) of noteholders collectively holding more than 50% of the Senior Notes outstanding to forbear from exercising remedies on account of the missed interest payments and certain other alleged defaults specified in the Forbearance Agreements through and including May 1, 2016. While the Forbearance Agreements were in effect, we continued to engage in good-faith arm’s-length negotiations regarding a potential restructuring of the Credit Facility and the Senior Notes that would improve our liquidity. In the course of these negotiations, the Company, the Lenders, and the Ad Hoc Committee exchanged and considered, with the assistance of their respective advisors, numerous restructuring proposals.

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

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

Debtor-In-Possession. During the pendency of the Chapter 11 Cases, ~~constitutes an additional event of default under our Credit Facility, Senior Notes, capital leases and mortgage note.~~

~~We are currently operating~~we operated our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. We have filed a variety of first day motions with the Bankruptcy Court that will allow us to continue to operate our business without interruption. These motions are designed primarily to minimize the impact of our bankruptcy filing on our operations, creditors and employees. The Bankruptcy Court ~~has~~ granted all first day motions filed by us ~~and our~~which were designed primarily to minimize the impact of the Chapter 11 ~~Subsidiaries.~~Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we ~~not only are~~were able to conduct normal business activities and pay ~~the~~all associated obligations for the post-petition period ~~following our bankruptcy filing,~~and we ~~are~~were also authorized to pay and have paid (subject to ~~caps~~limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest ~~holders and partners.~~holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business ~~require~~required the ~~prior~~ approval of the Bankruptcy Court. ~~Final orders on the motions to satisfy our obligations to certain third parties and to forward funds held by us that belong to third parties were granted on June 7, 2016.~~

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

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

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

Upon our emergence from bankruptcy, on March 21, 2017, we adopted fresh-start accounting in accordance with the ~~duration~~provisions set forth in Accounting Standards Codification 852, Reorganizations, as (i) the Reorganization Value of our ~~Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject~~assets immediately prior to the ~~risks~~date of confirmation was less than the post-petition liabilities and ~~uncertainties associated~~allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the ~~Chapter 11 process,~~fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as ~~described~~of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we will have a new basis in ~~Item 1A, “Risk Factors.”~~our assets and liabilities. As a result of ~~these risks~~the adoption of fresh-start reporting and ~~uncertainties,~~ the ~~number of our outstanding shares of common stock and stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome~~effects of the ~~Chapter 11 Cases, and~~implementation of the ~~description of~~Plan, our ~~operations, properties and capital plans included in this quarterly report~~unaudited consolidated financial statements subsequent to March 21, 2017, may not ~~accurately reflect~~be comparable to our ~~operations, properties and capital plans following our emergence from bankruptcy.~~

In particular, subject to certain exceptions, under the Bankruptcy Code, we may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves us of performing future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires us to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease involving us in theseunaudited consolidated financial statements ~~including where applicable, a quantification of our obligations under any~~prior to March 21, 2017, as such, ~~executory contract or unexpired lease with us is qualified by our rights~~"black-line" financial statements are presented to ~~reject such executory contract or unexpired lease under~~distinguish between the ~~Bankruptcy Code.~~

On June 13, 2016, we filed a motion to set a bar date to assist with the claims reconciliation process. The Bankruptcy Court approved such motion on July 1, 2016, setting the bar date on August 19, 2016, for all potential claimants other than governmental authorities whose bar date is on November 7, 2016. Through the claims resolution process, differences in amounts scheduled by usPredecessor and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the potential number and amount of claims filed, the claims resolution process may take considerable time to complete, and we expect that it will continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

On September 30, 2016, the Company, certain members of a steering committee of the Lenders and the Ad Hoc Committee reached a non-binding agreement in principle regarding a potential restructuring of the Company’s debt (a “Restructuring” ) in conjunction with the Company’s plan to reorganize through a plan of reorganization, which are further disclosed in our Current Report on Form 8-K filed on September 30, 2016. Provisions of the potential Restructuring include that the plan of reorganization will provide for, among other things, the full equitization of the Debtors’ approximately $1.2 billion of outstanding unsecured notes for 100% of the new ownership interests in the reorganized debtors, subject to dilution from (i) a $50 million rights offering to be backstopped by certain of the Company’s noteholders, (ii) an incentive plan for the benefit of new management of the reorganized debtors, and (iii) additional terms acceptable to the Lenders and the Ad Hoc Committee. The potential Restructuring also contemplates that the Lenders’ claims against the Company will be partially paid down on the effective date of the Debtors’ plan of reorganization, with the remaining $375 million outstanding to be restructured into a four-year, $225 million first-out revolving loan and $150 million second-out term loan. The exit financing will require us to enter into derivative contracts to hedge our future estimated production volumes from proved developed producing reserves at a minimum level of 80% in the first year, 60% in the second year and 40% in the third year. The potential Restructuring is subject to execution and delivery of definitive documentation, and there can be no assurances that such definitive documentation will be finalized or that the terms and conditions thereof will not differ materially from the terms and conditions of the potential Restructuring.

Successor companies. In order to ~~successfully exit bankruptcy,~~facilitate the discussion and analysis herein, we ~~will need~~have addressed the Predecessor and Successor periods discretely and have provided comparative analysis, to ~~propose, and obtain confirmation by~~ the Bankruptcy Court of, a plan (or plans) of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization would, among other things, resolve our pre-petition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from bankruptcy.

We have the exclusive right for 120 days after the Petition Date to file a plan of reorganization subject to extension for cause. If the Exclusive Filing Period lapses, any party in interest may file a plan of reorganization for any of the Debtors. On October 13, 2016, the Bankruptcy Court approved our motion to extend the Exclusive Filing Period to November 9, 2016, and we expect to request a further extension.

The timing of filing a plan of reorganization by us will depend on the timing and outcome of numerous other ongoing matters in the Chapter 11 Cases. Although we expect to file a plan of reorganization that provides for emergence from bankruptcy as a going concern, there can be no assurance at this time that we will be able to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions, that satisfies the conditions of the Bankruptcy Code and is confirmed by the Bankruptcy Court, or that any such plan will be implemented successfully.

~~We have accounted for the bankruptcy in accordance with Accounting Standards Codification 852,~~ ~~Reorganizations~~ (“ASC 852”), in preparing our financial statements. The financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. In accordance with ASC 852, our financial statements include amounts classified as liabilities subject to compromise which represent pre-petition obligations that we anticipate will be allowed as claims in our bankruptcy case. Our financial statements also reflect “Reorganization items, net” comprising of any post-petition revenues, expenses, gains and losses that are the result of the reorganization of the business. We have incurred and will continue to incur significant costs associated with the reorganization.extent practical, where appropriate.

Price ~~Uncertainty~~uncertainty and the ~~Full-Cost Ceiling Impairment~~full-cost ceiling impairment

We deal with volatility in commodity prices primarily by ~~maintaining~~insuring our overall cost structure is competitive and supportive in a $40/bbl to $60/bbl oil price environment. In addition, we maintain flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price ~~volatility, as well as by aggressively pursuing cost reductions in a market downturn. In the past, we have~~volatility. We also ~~dealt~~deal with price volatility by hedging a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. ~~As a result of our bankruptcy, all our commodity price derivatives~~We currently have ~~been terminated~~derivative contracts in place for oil and ~~we do not have outstanding hedges at this time.~~natural gas production in 2017, 2018 and 2019 (see Item 3. Quantitative and Qualitative Disclosures About Market Risk).

Price volatility also impacts our business through the full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending

on the balance sheet date. ~~As a result of the recent industry downturn, the~~The average price utilized in our ceiling test calculation over the past 12 months ~~has generally followed a pattern of decline~~is as follows:

As ~~the decline in average crude oil prices has slowed~~discussed above, our application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the ~~recent quarter coupled~~carrying value of our oil and natural gas properties being restated based on their fair value. The estimated fresh start fair value along with ~~a minor~~adjustments for activity between March 21, 2017, and June 30, 2017, as well as the increase in SEC average prices resulted in carrying values that were below the ~~average natural gas price, we did not incur any~~full cost ceiling ~~test impairment during~~at the ~~third quarter~~end of ~~2016, in contrast to the ceiling test impairments previously recorded during~~ the first and second ~~quarter~~quarters of ~~2016 totaling $281.1 million.~~

~~Since~~2017 and thus ceiling test write-downs were not required during the ~~prices used in the cost ceiling are based on a trailing 12-month period, the full impact~~first six months of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the price change on the financial statements over several reporting periods. 2017.

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

Our financial and operating performance, outside of transactions related to our emergence from bankruptcy, in the ~~third~~second quarter of ~~2016~~2017 includes the following highlights:

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

We announced on April 28, 2017, that during the remainder of 2017, we will be pursuing strategic alternatives for our EOR assets as we shift our strategy and portfolio to focus solely on our more profitable STACK Area. In that regard, we retained CIBC Griffis & Small as an advisor to assist in marketing our EOR assets. We received bids for the assets at the end of the second quarter of 2017 and are currently evaluating those bids.

During the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, we incurred capital expenditures of ~~$101~~$114.8 million. This included expenditure for completing two wells drilled in the previous year, drilling and completing nine wells, and drilling an additional four wells to be completed in the second half of 2017, as well as participating in outside operated wells, all within our STACK play. We began the year with one rig, increasing to two rigs during the first quarter and both are still currently ~~anticipate exceeding~~deployed. We also incurred capital expenditures within our ~~2016 total~~Active EOR Areas for continuing CO₂ purchases, developing our North Burbank Unit and efficiently producing our other units experiencing production decline. We have increased our 2017 capital budget, ~~by approximately $18~~previously set at $145.9 million, ~~or 17% primarily~~to a range of $185 million to $200 million due to increased ~~spending on~~activity in our STACK play. The increased capital budget is a result of the success of our operated drilling program where we will increase the number of operated wells drilled, increased activity from other STACK operators resulting in an increase of our outside operated drilling and completion expenditures and cost inflationary pressures. In addition, we have expanded our leasehold acquisition budget as we have been successful in acquiring STACK acreage ~~acquisitions as described below, partially offset by reduced spending within~~in our ~~EOR Project Areas. Our operated~~core operating areas at attractive prices and ~~outside-operated drilling activity within our E&P Areas was predominantly focused within our STACK play and included drilling and completing 10 operated wells as well as completing 5 operated wells~~we have taken advantage of that ~~were drilled in the prior year. Upon completion of our planned drilling activity, we discontinued utilization of our rig in June 2016 although we~~opportunity. We plan to ~~recommence drilling in December 2016. We expect~~fund our capital budget with a combination of cash flows from operations, borrowings under our credit facility and proceeds from the sale of non-core assets of approximately $25 million to ~~exceed~~$30 million.

On May 26, 2017, the OTCQB tier of the OTC Markets Group, Inc. began quoting our ~~drilling budget~~Class A common stock 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”. No established public trading market existed for ~~2016 by approximately $7 million primarily due~~our Class A common stock prior to ~~increased spending to drill~~that date. Our Class B common stock is not listed or quoted on the OTCQB or any other stock exchange or quotation system, and ~~complete outside-operated wells in our STACK play. Meanwhile,~~ we have ~~incurred $12 million in acquisitions of leasehold acreage in~~not applied for such listing. Although our Class A common stock is quoted on the ~~STACK with further acquisitions planned during~~OTCQB, trading and quotations on the ~~fourth quarter of 2016. We anticipate exceeding our annual budget for leasehold acquisition as~~stock have been limited and sporadic.

Pursuant to the ~~additional acquisitions were undertaken to add or extend acreage in areas of the STACK~~Registration Rights Agreement, on June 7, 2017, we filed a Registration Statement on Form S-1 (the

~~where we have experienced encouraging drilling results. Capital activity within~~“Registration Statement”) with the SEC, which registered for resale from time to time offerings by the selling stockholders named in the Registration Statement of up to 20,418,108 shares of our ~~EOR Project Areas for 2016 has been primarily focused on~~Class A common stock, including up to 3,505,724 shares of Class A common stock issuable upon the conversion of shares of Class B common stock and 140,023 shares of Class A common stock issuable upon exercise of warrants, and 3,505,724 shares of our ~~North Burbank Unit for infrastructure build out, development~~Class B common stock. On June 22, 2017, the Registration Statement was declared effective by the SEC. We did not sell any shares of ~~a limited number~~our common stock pursuant to the Registration Statement and will not receive any proceeds from the sale of ~~additional patterns, continuing CO~~₂ ~~injection and field maintenance, and to a lesser extent on CO~~₂ ~~purchases for~~shares of our ~~other Active EOR units.~~common stock by the selling stockholders.

Three months ended

Nine months ended

September 30,

Percent

September 30,

Percent

Production volume (Mboe)

2016

2015

change

2016

2015

change

E&P Areas:

Mississippi Lime

304

501

(39.3
)%

1,023

1,688

(39.4
)%
STACK - Meramec

196

26

653.8
%

408

102

300.0
%
STACK - Osage

188

120

56.7
%

577

416

38.7
%
STACK - Oswego

101

113

(10.6
)%

333

317

5.0
%
STACK - Woodford

123

101

21.8
%

431

334

29.0
%
Panhandle Marmaton

81

122

(33.6
)%

266

497

(46.5
)%
Legacy Production Areas

446

612

(27.1
)%

1,385

1,917

(27.8
)%
Total E&P Areas

1,439

1,595

(9.8
)%

4,423

5,271

(16.1
)%
EOR Project Areas:

Active EOR Projects

511

562

(9.1
)%

1,602

1,669

(4.0
)%
Potential EOR Projects

244

295

(17.3
)%

761

918

(17.1
)%
Total EOR Project Areas

755

857

(11.9
)%

2,363

2,587

(8.7
)%
Total

2,194

2,452

(10.5
)%

6,786

7,858

(13.6
)%

	Successor		Predecessor
Production volume (MBoe)	Three months ended June 30, 2017		Three months ended June 30, 2016		Percent change
STACK Areas		831		709		17.2	%
Active EOR Projects		521		526		(1.0	)%
Other		827		1,077		(23.2	)%
Total		2,179		2,312		(5.8	)%

We have recently realigned ~~the plays within~~ our ~~E&P Areas~~operating plays/areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. ~~E&P Areas include the following plays: the STACK, Mississippi Lime, Panhandle Marmaton and Legacy Production Areas.~~ Please see Items 1. and 2. Business and Properties of our Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, for a discussion of ~~our plays.~~operating areas.

Production ~~in our E&P Areas~~ decreased for the three ~~and nine~~ months ended ~~September~~June 30, ~~2016,~~2017, compared to the prior year ~~periods~~period primarily due to ~~the natural decline~~production declines in all of our ~~wells and~~areas outside the ~~overall decrease in~~STACK. Areas outside the STACK, other than our drilling activity due to the current low price environment. The production decline was most pronounced in our Mississippi Lime and Panhandle Marmaton plays and in our Legacy Production Areas for which we have not allocated significant drilling capital in the past year. Meanwhile, production across most our STACK play has increased as a result of our recent focus to drill and develop the area.

Our EOR Project Areas include both currently Active EOR Projects and Potential EOR Projects. Potential EOR Projects have no current EOR production or reserves while Active EOR Project areas include properties that have proved EOR reserves or ongoing EOR operations. There were slight production declines inNorth Burbank Unit located within our Active EOR Projects, ~~for~~experienced declining production due to a decrease in development activity. In contrast, production in our STACK play increased due to our capital spending dedicated to developing this area with a resulting operated 12 wells that came online during the ~~three~~period and ~~nine months ended September 30, 2016, compared to the prior year periods as~~participation in additional outside-operated wells. In our Active EOR Areas, increases ~~from~~in production at our North Burbank Unit as a result of ~~continued development~~ongoing investment partially mitigated the decreases experienced at our Booker, Camrick and ~~response were more than offset~~Farnsworth units.

Our total net production for the six months ended June 30, 2017, which was comprised of 2,406 MBoe for the Successor period and 1,796 MBoe for the Predecessor period, also declined from the prior year period. The changes are driven by ~~production declines~~the same factors as described above, where capital spending in the STACK and in our ~~other units. Production decreases~~North Burbank Unit resulted in production increases that partially mitigated the natural decline in all of our Other areas. Furthermore, a severe ice storm in the Oklahoma Panhandle in early 2017 had an adverse impact on our oil production in our ~~Potential~~Active EOR ~~Projects were due to natural decline~~ and ~~a lack of development due to the current low pricing environment.~~Other areas.

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

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

	Successor		Predecessor
	Three months ended June 30, 2017		Three months ended June 30, 2016		Increase (Decrease)			Percent change
Commodity sales (in thousands):
Oil	$	57,598	$	53,714	$	3,884			7.2	%
Natural gas		9,669		6,773		2,896			42.8	%
Natural gas liquids		6,781		5,503		1,278			23.2	%
Total commodity sales	$	74,048	$	65,990	$	8,058			12.2	%
Production:
Oil (MBbls)		1,234		1,271		(37	)		(2.9	)%
Natural gas (MMcf)		3,598		4,041		(443	)		(11.0	)%
Natural gas liquids (MBbls)		345		368		(23	)		(6.3	)%
MBoe		2,179		2,312		(133	)		(5.8	)%
Average daily production (Boe/d)		23,945		25,407		(1,462	)		(5.8	)%
Average sales prices (excluding derivative settlements):
Oil per Bbl	$	46.68	$	42.26	$	4.42			10.5	%
Natural gas per Mcf	$	2.69	$	1.68	$	1.01			60.1	%
NGLs per Bbl	$	19.66	$	14.95	$	4.71			31.5	%
Average sales price per Boe	$	33.98	$	28.54	$	5.44			19.1	%

	Three months ended										Nine months ended
	September 30,				Increase /			Percent			September 30,				Increase /			Percent			Successor		Predecessor
	2016		2015		(Decrease)			change			2016		2015		(Decrease)			change			Period from March 22, 2017 through June 30, 2017		Period from January 1, 2017 through March 21, 2017		Six months ended June 30, 2016
Commodity sales (in thousands):
Oil	$	50,391	$	58,353	$	(7,962	)		(13.6	)%	$	141,170	$	206,948	$	(65,778	)		(31.8	)%	$	63,828	$	51,847	$	90,779
Natural gas		10,018		11,402		(1,384	)		(12.1	)%		24,141		36,534		(12,393	)		(33.9	)%		10,454		9,140		14,123
Natural gas liquids		5,438		4,757		681			14.3	%		14,765		18,319		(3,554	)		(19.4	)%		7,574		5,544		9,327
Total commodity sales	$	65,847	$	74,512	$	(8,665	)		(11.6	)%	$	180,076	$	261,801	$	(81,725	)		(31.2	)%	$	81,856	$	66,531	$	114,229
Production:
Oil (MBbls)		1,177		1,328		(151	)		(11.4	)%		3,693		4,283		(590	)		(13.8	)%		1,368		1,036		2,516
Natural gas (MMcf)		3,912		4,624		(712	)		(15.4	)%		12,053		14,386		(2,333	)		(16.2	)%		3,942		3,046		8,141
Natural gas liquids (MBbls)		365		353		12			3.4	%		1,084		1,177		(93	)		(7.9	)%		381		252		719
MBoe		2,194		2,452		(258	)		(10.5	)%		6,786		7,858		(1,072	)		(13.6	)%		2,406		1,796		4,592
Average daily production (Boe/d)		23,848		26,652		(2,804	)		(10.5	)%		24,766		28,784		(4,018	)		(14.0	)%		23,822		22,450		25,231
Average sales prices (excluding derivative settlements):
Oil per Bbl	$	42.81	$	43.94	$	(1.13	)		(2.6	)%	$	38.23	$	48.32	$	(10.09	)		(20.9	)%	$	46.66	$	50.05	$	36.08
Natural gas per Mcf	$	2.56	$	2.47	$	0.09			3.6	%	$	2.00	$	2.54	$	(0.54	)		(21.3	)%	$	2.65	$	3.00	$	1.73
NGLs per Bbl	$	14.90	$	13.48	$	1.42			10.5	%	$	13.62	$	15.56	$	(1.94	)		(12.5	)%	$	19.88	$	22.00	$	12.97
Average sales price per Boe	$	30.01	$	30.39	$	(0.38	)		(1.3	)%	$	26.54	$	33.32	$	(6.78	)		(20.3	)%	$	34.02	$	37.04	$	24.88

Our ~~total~~ commodity sales ~~decreased during~~for the ~~three month period~~quarter ended ~~September~~June 30, ~~2016, compared to~~2017, were higher than the prior year quarter, ~~primarily as a result of a decrease in the average price~~ and production volume sold of crude oil. A decline in production volume sold of natural gas also contributed to the decrease. These decreases were partially offset by increases in the average price and production volume sold of natural gas liquids as well as a slight increase in the price of natural gas.

~~Our~~our total commodity sales ~~decreased during~~for the ~~nine month~~ period ~~ended September~~from January 1 - March 21 and March 22 - June 30, ~~2016, compared to~~2017 were higher than the prior year period due to increases in prices on all commodities offset partially by production declines as a result of decreases in the average prices and production volumes sold of all commodities. Changes in our production compared to the prior year periods are discussed in the preceding section above while the impact of price and production volume changes on our commodity sales is disclosed in the table below.

	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2016 vs. 2015						2016 vs. 2015						2017 vs. 2016						2017 vs. 2016
(in thousands)	Sales change			Percentage change in sales			Sales change			Percentage change in sales			Sales change			Percentage change in sales			Sales change			Percentage change in sales
Change in oil sales due to:
Prices	$	(1,327	)		(2.2	)%	$	(37,270	)		(18.0	)%	$	5,448			10.1	%	$	28,937			31.8	%
Production	$	(6,635	)		(11.4	)%	$	(28,508	)		(13.8	)%	$	(1,564	)		(2.9	)%	$	(4,041	)		(4.4	)%
Total change in oil sales	$	(7,962	)		(13.6	)%	$	(65,778	)		(31.8	)%	$	3,884			7.2	%	$	24,896			27.4	%
Change in natural gas sales due to:
Prices	$	372			3.3	%	$	(6,468	)		(17.7	)%	$	3,638			53.8	%	$	7,471			52.8	%
Production	$	(1,756	)		(15.4	)%	$	(5,925	)		(16.2	)%	$	(742	)		(11.0	)%	$	(2,000	)		(14.1	)%
Total change in natural gas sales	$	(1,384	)		(12.1	)%	$	(12,393	)		(33.9	)%	$	2,896			42.8	%	$	5,471			38.7	%
Change in natural gas liquids sales due to:
Prices	$	519			10.9	%	$	(2,107	)		(11.5	)%	$	1,622			29.5	%	$	4,907			52.5	%
Production	$	162			3.4	%	$	(1,447	)		(7.9	)%	$	(344	)		(6.3	)%	$	(1,116	)		(11.9	)%
Total change in natural gas liquids sales	$	681			14.3	%	$	(3,554	)		(19.4	)%	$	1,278			23.2	%	$	3,791			40.6	%

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

Due to defaults under ~~the~~our derivative master agreements ~~governing~~stemming from our ~~derivative contracts, all~~bankruptcy, our outstanding derivative positions were ~~early-terminated~~terminated in May ~~2016 and we have no outstanding derivative contracts as of September 30,~~ 2016. ~~The master agreement defaults were the result of our debt defaults and our bankruptcy petition.~~ Proceeds from the early terminations, inclusive of amounts receivable for previous settlements, totaled $119.3 ~~million of which $103.6 million were utilized to offset outstanding borrowings under~~million. In December 2016, an agreement was reached with our ~~Credit Facility and the remainder was remitted to the Company during the third quarter of 2016.~~

While we are in default on our indebtedness and have a bankruptcy filing, we will no longer be able to represent that we can comply with the credit default or bankruptcy covenants under any prospective derivative master agreements and thus may not be able to enter into new hedging transactions. We are currently negotiating with the Lenders, most of which were previously counterparties to our derivative contracts,lenders regarding the resumption of hedging activity prior to our ~~potential~~ emergence from ~~bankruptcy. However, subsequent to the initial hedges that are required under our potential Restructuring, there can be no assurance that~~bankruptcy and thus we ~~will be able to enter~~began entering into new derivative ~~transactions~~instruments.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The table below presents information about the effects of derivative settlements on ~~terms that are acceptable~~realized prices during 2017. We have not presented comparative information for the 2016 periods as such information is not meaningful due to ~~us.~~the effect of early terminations of outstanding contracts discussed above.

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

			Successor		Predecessor
			June 30,		December 31,
(in thousands)	December 31, 2015		2017		2016
Derivative assets:
Derivative assets (liabilities):
Crude oil derivatives	$	123,068	$	35,038	$	(9,895	)
Natural gas derivatives		40,170		1,318		(3,474	)
Net derivative assets	$	163,238
Net derivative assets (liabilities)			$	36,356	$	(13,369	)

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

Three months ended September 30,

2016

2015

(in thousands)

Non-cash
fair value
adjustment

Settlement
gains

Total gain
(loss)

Non-cash
fair value
adjustment

Settlement
gains

Total gain
(loss)

Non-hedge derivative gains:

Crude oil derivatives

$
—

$
—

$
—

$
22,728

$
49,040

$
71,768

Natural gas derivatives

—

—

—

8,213

5,434

13,647

Non-hedge derivative gains

$
—

$
—

$
—

$
30,941

$
54,474

$
85,415

	Successor				Predecessor
	Three months ended June 30, 2017				Three months ended June 30, 2016
(in thousands)	Non-cash fair value adjustment		Settlement gains		Non-cash fair value adjustment			Settlement gains
Derivative gains (losses):
Crude oil derivatives	$	15,765	$	6,269	$	(90,953	)	$	74,760
Natural gas derivatives		1,046		394		(36,731	)		31,524
Derivative gains (losses)	$	16,811	$	6,663	$	(127,684	)	$	106,284

	Nine months ended September 30,															Successor				Predecessor
	2016								2015							Period from March 22, 2017 through June 30, 2017				Period from January 1, 2017 through March 21, 2017				Six months ended June 30, 2016
(in thousands)	Non-cash fair value adjustment			Settlement gains		Total gain (loss)			Non-cash fair value adjustment			Settlement gains		Total gain (loss)		Non-cash fair value adjustment		Settlement gains		Non-cash fair value adjustment		Settlement gains		Non-cash fair value adjustment			Settlement gains
Non-hedge derivative (losses) gains:
Derivative gains (losses):
Crude oil derivatives	$	(123,068	)	$	113,852	$	(9,216	)	$	(73,357	)	$	149,871	$	76,514	$	2,115	$	7,961	$	42,819	$	1,192	$	(123,068	)	$	113,852
Natural gas derivatives		(40,170	)		39,918		(252	)		5,474			23,278		28,752		889		394		3,902		93		(40,170	)		39,918
Non-hedge derivative (losses) gains	$	(163,238	)	$	153,770	$	(9,468	)	$	(67,883	)	$	173,149	$	105,266
Derivative gains (losses)																$	3,004	$	8,355	$	46,721	$	1,285	$	(163,238	)	$	153,770

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

	Three months ended September 30,				Increase /			Percent			Nine months ended September 30,				Increase /			Percent			Successor		Predecessor
	2016		2015		(Decrease)			change			2016		2015		(Decrease)			change			Three months ended June 30, 2017		Three months ended June 30, 2016		Increase (Decrease)			Percent change
Lease operating expenses (in thousands, except per Boe data):
E&P Areas	$	8,642	$	10,461	$	(1,819	)		(17.4	)%	$	26,986	$	37,370	$	(10,384	)		(27.8	)%
EOR Project Areas	$	13,649	$	14,420	$	(771	)		(5.3	)%		41,476		46,551	$	(5,075	)		(10.9	)%
STACK Areas																					$	3,213	$	3,098	$	115			3.7	%
Active EOR Project Areas																						9,079		8,968		111			1.2	%
Other																						10,767		10,690		77			0.7	%
Total lease operating expense	$	22,291	$	24,881	$	(2,590	)		(10.4	)%	$	68,462	$	83,921	$	(15,459	)		(18.4	)%	$	23,059	$	22,756	$	303			1.3	%
Lease operating expenses per Boe:
E&P Areas	$	6.01	$	6.56	$	(0.55	)		(8.4	)%	$	6.10	$	7.09	$	(0.99	)		(14.0	)%
EOR Project Areas	$	18.08	$	16.83	$	1.25			7.4	%	$	17.55	$	17.99	$	(0.44	)		(2.4	)%
STACK Areas																					$	3.87	$	4.37	$	(0.50	)		(11.4	)%
Active EOR Project Areas																					$	17.43	$	17.05	$	0.38			2.2	%
Other																					$	13.02	$	9.93	$	3.09			31.1	%
Lease operating expenses per Boe	$	10.16	$	10.15	$	0.01			0.1	%	$	10.09	$	10.68	$	(0.59	)		(5.5	)%	$	10.58	$	9.84	$	0.74			7.5	%

	Successor		Predecessor
	Period from March 22, 2017 through June 30, 2017		Period from January 1, 2017 through March 21, 2017		Six months ended June 30, 2016
Lease operating expenses (in thousands, except per Boe data):
STACK Areas	$	3,579	$	2,247	$	5,622
Active EOR Project Areas		10,548		8,488		18,410
Other		13,191		9,206		22,139
Total lease operating expense	$	27,318	$	19,941	$	46,171
Lease operating expenses per Boe:
STACK Areas	$	3.93	$	3.43	$	3.44
Active EOR Project Areas	$	18.22	$	19.07	$	17.52
Other	$	14.38	$	13.25	$	10.03
Lease operating expenses per Boe	$	11.35	$	11.10	$	9.44

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices. Our EOR projects are more expensive to operate than traditional industry operations due to the nature of operations along with the costs of recovery and recycling of ~~CO2.~~CO₂.

Lease operating ~~expenses at both~~expense is not comparable across the time periods presented above in part due to our ~~E&P Areas~~recognition of bonus expense. Provisions set by the Bankruptcy Court during the pendency of our bankruptcy prevented us from paying bonuses in the ordinary course of business. Pursuant to these provisions, we did not accrue bonuses during 2016 and ~~EOR Project Areas decreased on an absolute dollar basis~~ during the entire pendency of our bankruptcy. Upon emergence, we recognized expense for the entire amount of our 2016 fiscal year bonus (paid in March 2017) as well as accrued a pro rata portion of our 2017 fiscal year bonus. We resumed accruing bonuses in the ordinary course of business during the second quarter of 2017. The bonus expense component of lease operating expense is disclosed in the table below:

Lease operating expense for the three months ~~and nine months~~ ended ~~September~~June 30, ~~2016,~~2017, of $23.1 million were higher compared to the prior year quarter primarily due to the bonus expense described above. Absent the bonus accrual, lease operating expenses for the three months ended June 30, 2017, were flat compared to the three months ended June 30, 2016.

Lease operating expense for the six months ended June 30, 2017, which were comprised of $27.3 million and $19.9 million for the Successor and Predecessor periods, ~~primarily~~respectively, were relatively flat compared to the prior year period. Absent the accrual for bonuses, lease operating expense would have been flat for our STACK play and lower for our Active EOR and Other areas. Lease operating expenses for our Active EOR and Other areas decreased as a result of recent shut-ins of higher cost ~~reductions~~underperforming wells and operational efficiencies. Lease operating expenses for our STACK Areas were flat where the additional costs of oil field goods

and services as a result of new wells coming online in 2016 and 2017 were offset by cost savings from ~~third party service providers and~~ improved ~~operational~~ efficiencies, which ~~included temporary shut-in~~resulted in expense being approximately unchanged from period to period. Increased production, improved efficiencies and economies of ~~marginal wells due to the current low price environment and limiting workovers to wells that meet~~scale in this area also resulted in a ~~minimum payout threshold. Lower production volumes during the current year period also contributed to the~~ decrease in ~~expense.~~cost on a Boe basis from 2016 to 2017.

Three months ended
September 30,

Increase /

Percent

Nine months ended
September 30,

Increase /

Percent

2016

2015

(Decrease)

change

2016

2015

(Decrease)

change

Transportation and processing expenses
(in thousands)

$
2,429

$
1,902

$
527

27.7
%

$
6,493

$
6,246

$
247

4.0
%
Transportation and processing expenses
per Boe

$
1.11

$
0.78

$
0.33

42.3
%

$
0.96

$
0.79

$
0.17

21.5
%

	Successor		Predecessor
	Three months ended June 30, 2017		Three months ended June 30, 2016		Increase (Decrease)		Percent change
Transportation and processing expenses (in thousands)	$	3,067	$	2,185	$	882		40.4	%
Transportation and processing expenses per Boe	$	1.41	$	0.95	$	0.46		48.4	%

Transportation and processing expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and processing costs of gas into natural gas liquids. ~~Our transportation~~Transportation and processing ~~costs increased during~~expenses of $3.1 million for the three ~~and nine~~ months ended ~~September~~June 30, ~~2016,~~2017, were higher compared to the ~~same period in 2015 primarily due~~three months ended June 30, 2016, as a result of higher per unit costs associated with our non-operated wells and a larger proportion of gas production subject to fee based processing arrangements as opposed to percentage of proceeds (“POP”) arrangements. These factors also similarly impacted our expenses for the six months ended June 30, 2017, comprised of $3.4 million and $2.0 million for the Successor and Predecessor periods, which were higher ~~fees on our new STACK operated wells coming online.~~compared to the six months ended June 30, 2016.

	Three months ended September 30,				Increase /			Percent			Nine months ended September 30,				Increase /			Percent			Successor		Predecessor
	2016		2015		(Decrease)			change			2016		2015		(Decrease)			change			Three months ended June 30, 2017		Three months ended June 30, 2016		Increase (Decrease)		Percent change
Production taxes (in thousands)	$	2,174	$	2,795	$	(621	)		(22.2	)%	$	6,812	$	11,123	$	(4,311	)		(38.8	)%	$	3,383	$	2,882	$	501		17.4	%
Production taxes per Boe	$	0.99	$	1.14	$	(0.15	)		(13.2	)%	$	1.00	$	1.42	$	(0.42	)		(29.6	)%	$	1.55	$	1.25	$	0.30		24.0	%

Production taxes ~~decreased~~on a dollar and per Boe basis for the ~~nine~~three months ended ~~September~~for the periods in 2017 and in aggregate for the periods from January 1 – March 21 and March 22 – June 30, 2017, were higher than the periods in 2016 ~~compared~~as a result of higher commodity prices which increased revenues.

In May 2017, the Oklahoma legislature passed bills that would effectively increase production taxes on certain producing wells and units in the state. The bills end all production tax rebates for EOR operations and increases the rate on horizontal wells spudded on or prior to ~~the prior year period due~~July 1, 2015. These bills, which took effect in July 2017, will result in an estimated increase in our production taxes of approximately $1.6 million related to ~~lower severance taxes attributable to lower revenues combined with a decrease~~production in ~~ad valorem taxes attributable to lower valuation of~~ our ~~oil~~Active EOR Areas and gas properties. We expect ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, to fluctuate throughout the year as valuations and county tax rates are finalized, with an overall decrease when comparing full-year 2016 to full-year 2015 primarily due to lower estimated valuations$0.6 million on our ~~oil and gas properties.~~

	Successor		Predecessor
	Three months ended June 30, 2017		Three months ended June 30, 2016		Increase (Decrease)			Percent change
DD&A (in thousands):
Oil and natural gas properties	$	27,549	$	30,230	$	(2,681	)		(8.9	)%
Property and equipment		2,332		1,807		525			29.1	%
Accretion of asset retirement obligation		970		927		43			4.6	%
Total DD&A	$	30,851	$	32,964	$	(2,113	)		(6.4	)%
DD&A per Boe:
Oil and natural gas properties	$	13.09	$	13.48	$	(0.39	)		(2.9	)%
Other fixed assets	$	1.07	$	0.78	$	0.29			37.2	%
Total DD&A per Boe	$	14.16	$	14.26	$	(0.10	)		(0.7	)%

	Three months ended September 30,				Increase /			Percent			Nine months ended September 30,				Increase /			Percent			Successor		Predecessor
	2016		2015		(Decrease)			change			2016		2015		(Decrease)			change			Period from March 22, 2017 through June 30, 2017		Period from January 1, 2017 through March 21, 2017		Six months ended June 30, 2016
DD&A (in thousands):
Oil and natural gas properties	$	26,839	$	49,522	$	(22,683	)		(45.8	)%	$	86,083	$	164,694	$	(78,611	)		(47.7	)%	$	30,583	$	22,193	$	59,244
Property and equipment		1,772		1,580		192			12.2	%		5,454		6,273		(819	)		(13.1	)%		2,591		1,473		3,682
Accretion of asset retirement obligation		1,013		925		88			9.5	%		2,859		2,727		132			4.8	%		1,091		1,249		1,846
Total DD&A	$	29,624	$	52,027	$	(22,403	)		(43.1	)%	$	94,396	$	173,694	$	(79,298	)		(45.7	)%	$	34,265	$	24,915	$	64,772
DD&A per Boe:
Oil and natural gas properties	$	12.23	$	20.20	$	(7.97	)		(39.5	)%	$	12.69	$	20.96	$	(8.27	)		(39.5	)%	$	13.16	$	13.05	$	13.30
Other fixed assets	$	1.27	$	1.02	$	0.25			24.5	%	$	1.23	$	1.15	$	0.08			7.0	%	$	1.08	$	0.82	$	0.80
Total DD&A per Boe	$	13.50	$	21.22	$	(7.72	)		(36.4	)%	$	13.92	$	22.11	$	(8.19	)		(37.0	)%	$	14.24	$	13.87	$	14.10

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

DD&A onis not comparable between Successor and Predecessor periods as a result our implementation of fresh start accounting upon emergence from bankruptcy whereupon the carrying value of our proved oil and ~~natural~~ gas properties ~~decreased for~~and tangible property on our balance sheet was restated to fair value. The restatement resulted in an increase in the ~~three months ended September 30, 2016, compared to~~full cost amortization base which impacted the prior year quarter of which $5.2 million was due to a decrease in production and $17.5 million was due to a lower rate per equivalent unit of production. DD&A on oil and natural gas properties decreased for the nine months ended September 30, 2016, compared to the prior year period of which $22.5 million was due to a decrease in production and $56.1 million was due to a lower rate per equivalent unit of production. Our DD&A rate per equivalent unit of production ~~was lower as~~for the ~~full cost amortization base, which consists~~period subsequent to March 21, 2017. Notwithstanding a lack of ~~future development costs plus the carrying value of~~comparability, overall oil and natural gas ~~properties, is substantially~~DD&A was impacted by the production decline compared to the prior year periods, which resulted in lower ~~in 2016 following $1.5 billion in ceiling-test impairments that were recorded in 2015 and $281.1 million recorded~~DD&A during the ~~first half of 2016.~~periods in 2017 compared to the prior year period.

	Three months ended September 30,				Increase /			Nine months ended September 30,				Increase /			Successor		Predecessor
	2016		2015		(Decrease)			2016		2015		(Decrease)			Three months ended June 30, 2017		Three months ended June 30, 2016		Increase / (Decrease)
Asset impairments (in thousands):
Loss on impairment of other assets															$	—	$	1,259	$	(1,259	)
Loss on impairment of oil and natural gas assets	$	—	$	737,758	$	(737,758	)	$	281,079	$	955,320	$	(674,241	)		—		203,183		(203,183	)
Loss on impairment of other assets		202		—		202			1,461		13,311		(11,850	)

Oil and natural gas asset impairments. The ceiling test calculation for our oil and natural gas properties dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. The average price utilized in our ceiling test calculation over the past 12 months has generally followed ~~a pattern~~the following pattern:

As discussed above, our application of ~~decline reflective of the industry downturn as follows:~~

~~As the decline in average crude oil prices has slowed~~fresh start accounting to our balance sheet on March 21, 2017, resulted in the ~~recent quarter coupled with a minor increase in the average natural gas price, we did not incur any ceiling test impairment during the third quarter~~carrying value of 2016, in contrast to the ceiling test impairments previously recorded during the first and second quarter of 2016 totaling $281.1 million. The ceiling test impairments for the three and nine months ended September 30, 2015, were largely the result of price decline.

~~The magnitude of~~ our ~~ceiling test write-downs were also impacted by impairments of unevaluated non-producing leasehold, which resulted in a transfer of amounts from unevaluated~~ oil and natural gas properties tobeing restated based on their fair value. The estimated fresh start fair value along with adjustments for activity between March 21, 2017 and the end of the second quarter of 2017, as well as the increase in SEC average prices from year-end 2016 resulted in carrying values that were below the full cost ~~amortization base. Impairments~~ceiling at the end of ~~non-producing leasehold of $54.7 million were recorded~~the first and second quarters, and thus ceiling test write-downs have not been required during the first ~~nine~~six months of 2017. The ceiling test impairment for the three months and six months ended June 30, 2016, ~~compared to $108.4 million during the first nine months of 2015. The impairments in 2016 and 2015~~ were ~~recorded as a result of changes in our drilling plans~~primarily due to the ~~low pricing environment and lower than expected results for certain exploratory activities which resulted~~decrease in ~~certain undeveloped properties not expected to be developed before lease expiration.~~SEC prices.

Impairment of other assets. Our impairment ~~losses~~loss for ~~the nine months ended September 30, 2015, consists of write-downs of $6.0 million related to impairments of our stacked drilling rigs and $7.3 million related~~2016 was due to a lower of cost or market adjustment on our equipment inventory. ~~Our impairment losses for the three and nine months ended September 30, 2016, were due to lower of cost or market adjustments on our equipment inventory.~~

We own four stacked drilling rigs of which one was last utilized in January 2015 while the remaining three have been stacked for three to four years. The deterioration in commodity prices that began in mid-2014 resulted in reduced drilling activity causing the value of such equipment to decline while utilizing third party equipment became more cost effective. This led to the Company impairing the value of the rigs to their estimated fair value. In October 2016, we entered into an agreement for the sale of our four drilling rigs for an aggregate price of $2.0 million with a scheduled closing in January 2017.

The industry conditions described above also have also led to lower demand for our inventory equipment resulting in obsolescence and lower market prices. These factors resulted in the lower of cost or market adjustments we have recorded on our equipment inventory.

Three months ended
September 30,

Increase /

Percent

Nine months ended
September 30,

Increase /

Percent

2016

2015

(Decrease)

change

2016

2015

(Decrease)

change

G&A and cost reduction initiatives
   (in thousands):

Gross G&A expenses before Performance Vested stock adjustment

$
7,836

$
10,144

$
(2,308
)

(22.8
)%

$
24,695

$
34,668

$
(9,973
)

(28.8
)%
Performance Vested stock adjustment (1)

(4,761
)

—

(4,761
)

—

(4,761
)

—

(4,761
)

—

Capitalized exploration and
   development costs

(1,556
)

(2,755
)

1,199

(43.5
)%

(5,122
)

(8,825
)

3,703

(42.0
)%
Net G&A expenses

1,519

7,389

(5,870
)

(79.4
)%

14,812

25,843

(11,031
)

(42.7
)%
Cost reduction initiatives

89

603

(514
)

(85.2
)%

3,228

9,739

(6,511
)

(66.9
)%
Liability management expenses

—

—

—

—

9,396

—

9,396

—

Net G&A, cost reduction initiatives
  and liability management expenses

$
1,608

$
7,992

$
(6,384
)

(79.9
)%

$
27,436

$
35,582

$
(8,146
)

(22.9
)%
Average G&A expense per Boe

$
0.69

$
3.01

$
(2.32
)

(77.1
)%

$
2.18

$
3.29

$
(1.11
)

(33.7
)%
Average G&A, cost reduction initiatives and liability management expense per Boe

$
0.73

$
3.26

$
(2.53
)

(77.6
)%

$
4.04

$
4.53

$
(0.49
)

(10.8
)%

~~(1)~~

A cumulative catch up adjustment was recorded during the third quarter of 2016 to reverse the aggregate compensation cost associated with our Performance Vested restricted stock awards in order to reflect a decrease in the probability that that requisite service would be achieved for these awards. The amount disclosed above is net of any capitalization related to the adjustment.

	Successor			Predecessor
(in thousands)	Three months ended June 30, 2017			Three months ended June 30, 2016			Increase / (Decrease)			Percent change
G&A and cost reduction initiatives:
Gross G&A expenses	$	10,577		$	8,474		$	2,103			24.8	%
Capitalized exploration and development costs		(1,604	)		(1,670	)		66			(4.0	)%
Net G&A expenses		8,973			6,804			2,169			31.9	%
Cost reduction initiatives		115			14			101			721.4	%
Liability management expenses		—			3,807			(3,807	)		(100.0	)%
Net G&A, cost reduction initiatives and liability management expenses	$	9,088		$	10,625		$	(1,537	)		(14.5	)%
Average G&A expense per Boe	$	4.12		$	2.94		$	1.18			40.1	%
Average G&A, cost reduction initiatives and liability management expense per Boe	$	4.17		$	4.60		$	(0.43	)		(9.3	)%

	Successor			Predecessor
(in thousands)	Period from March 22, 2017 through June 30, 2017			Period from January 1, 2017 through March 21, 2017			Six months ended June 30, 2016
G&A and cost reduction initiatives:
Gross G&A	$	18,086		$	8,117		$	16,859
Capitalized exploration and development costs		(3,369	)		(1,274	)		(3,566	)
Net G&A expenses		14,717			6,843			13,293
Cost reduction initiatives		121			629			3,139
Liability management expenses		—			—			9,396
Net G&A, cost reduction initiatives and liability management expenses	$	14,838		$	7,472		$	25,828
Average G&A expense per Boe	$	6.12		$	3.81		$	2.89
Average G&A, cost reduction initiatives and liability management expense per Boe	$	6.17		$	4.16		$	5.62

Net G&A expense is not comparable across the time periods presented above in part due to our recognition of bonus expense. Provisions set by the Bankruptcy Court during the pendency of our bankruptcy prevented us from paying bonuses in the ordinary course of business. Pursuant to these provisions, we did not accrue bonuses during 2016 and during the entire pendency of our bankruptcy. Upon emergence, we recognized expense for the entire amount of our 2016 fiscal year bonus (paid in March 2017) as well as accrued a pro rata portion of our 2017 fiscal year bonus. We resumed bonus accrual in the ordinary course of business during the second quarter of 2017. The bonus expense component of net G&A expense is disclosed in the table below:

Gross G&A ~~expenses decreased during~~expense for the three months ~~and nine months~~ ended ~~September~~June 30, ~~2016, compared to~~2017, of $10.6 million was higher than the prior year ~~periods,~~quarter primarily due to ~~reductions~~the bonus expense described above, an increase in ~~payroll~~professional fees and an increase in costs associated with our 2015 Long-Term Cash Incentive Plan (“LTIP”). Professional fees were higher during the current quarter primarily due to costs associated with the preparation and ~~professional fees. Payroll related costs were lower primarily~~filing of the Registration Statement. LTIP expense increased as a result of ~~lower headcount subsequent to our workforce reductions~~an additional award grant made in ~~the current and prior year. As disclosed in the table above, our net G&A expense was impacted~~April 2017. These increases were partially offset by ~~a catch up adjustment associated with our Performance Vested restricted stock that led to~~ a reduction in salaries and stock-based compensation expense.

Gross G&A expense of $18.1 million and $8.1 million for the periods from March 22 – June 30 and January 1 – March 21, 2017, respectively, was higher in total compared to the prior year period primarily due to the bonus expense described above, an increase in professional fees, an increase in LTIP expense and increased stock-based compensation expense. Professional fees were higher during the current year primarily due to consulting fees and expenses associated with the Registration Statement. LTIP expense increased as a result of an additional award grant made in April 2017. These increases were partially offset by a reduction in salaries.

Capitalized exploration and development costs ~~decreased~~were relatively flat between the three months ended June 30, 2017 compared to the three months ended June 30, 2016. Total capitalized exploration and development costs of $3.4 million and $1.3 million for the periods from March 22 - June 30 and January 1 – March 21, 2017, respectively, increased compared to the six months ended June 30, 2016, primarily due to the ~~overall decrease in G&A as well as a lower proportion~~impact of ~~costs subject to capitalization as we have reduced our exploration, acquisition and development activities in this low commodity price environment.~~the bonus adjustment described above.

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the deterioration of commodity prices. We implemented workforce reductions during both the current year and prior year periods and therefore recorded one-time severance and termination benefits in connection with the layoffs. The remaining cost reduction expense is a result of ~~third party legal and~~ professional services we ~~have~~ engaged to assist in these initiatives as ~~follows:~~follows (in thousands):

	Three months ended				Nine months ended				Successor		Predecessor
	September 30,				September 30,				Period from		Period from
	2016		2015		2016		2015		March 22, 2017		January 1, 2017		Six months
(in thousands)
									through		through		ended
									June 30, 2017		March 21, 2017		June 30, 2016
One-time severance and termination benefits	$	89	$	596	$	3,125	$	7,467	$	112	$	608	$	3,036
Professional fees		—		7		103		2,272		9		21		103
Total cost reduction initiatives expense	$	89	$	603	$	3,228	$	9,739	$	121	$	629	$	3,139

Liability management expenses include third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our bankruptcy petition. Such costs, to the extent that they were incremental and directly related to our bankruptcy, were recorded as “Reorganization items, net” on our consolidated statement of operations subsequent to the Petition Date.

~~Although we recorded net losses~~The income tax expense that was recognized for the ~~three~~Predecessor and ~~nine months ended September 30, 2016, we~~Successor periods in our consolidated statement of operations is a result of current Texas margin tax on gross revenues less certain deductions. We did not record any ~~corresponding~~net deferred tax

benefit in the Predecessor and Successor periods in 2017 as any deferred tax asset arising from the ~~loss~~benefit is ~~currently not believed to be realizable and is therefore~~ reduced by a valuation allowance. At September 30, 2016, our valuation allowance is $580.3 million which reduces our net deferred tax assets to zero value as we continue to believe that it is more likely than not that we will not realize the deferred tax assets primarily related to our cumulative net operating losses. Income tax recognized for the three and nine months ended September 30, 2016, is a result of current Texas margin tax at a rate on gross revenues less certain deductions. Please see “Note 10—Income Taxes” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, which contains additional information about our income taxes.

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

	Three months ended						Nine months ended
	September 30,						September 30,						Successor			Predecessor
(in thousands)	2016			2015			2016			2015			Three months ended June 30, 2017			Three months ended June 30, 2016
New Credit Facility													$	1,487		$	—
New Term Loan including amortization of discount														3,465			—
Senior Notes	$	—		$	26,734		$	36,902		$	80,149			—			10,965
Credit Facility		5,705			2,435			18,034			7,378
Bank fees and other interest		1,773			1,272			4,048			3,790
Prior Credit Facility														—			8,908
Bank fees, other interest and amortization of issuance costs														640			903
Capitalized interest		(42	)		(1,843	)		(1,741	)		(8,115	)		(541	)		(623	)
Total interest expense	$	7,436		$	28,598		$	57,243		$	83,202		$	5,051		$	20,153
Average borrowings (including amounts subject to compromise)	$	1,680,976		$	1,686,974		$	1,729,923		$	1,702,818		$	303,845		$	1,782,051

Total interest expense ~~for~~is not comparable across the time periods disclosed above. During the three ~~and nine~~ months ended ~~September~~June 30, ~~2016, was lower than~~2017 and from March 22 to June 30, 2017, we incurred interest related to our New Term Loan and New Revolver whereas these facilities had not been established prior to our emergence from bankruptcy. During the ~~prior year periods as a result of lower~~period from January 1 to March 21, 2017, we incurred interest ~~expense~~related to our Prior Credit Facility but did not record any interest on our Senior Notes as we ceased accruing interest on our Senior Notes upon the filing of our bankruptcy petition. ~~This reduction~~During the three and six months ended June 30, 2016, we incurred interest related to our Senior Notes and Prior Credit Facility.

Interest expense in ~~expense~~2017 which included $5.1 million, $5.7 million and $5.9 million for three months ended June 30, 2017, the period from March 22 – June 30, 2017 and the period from January 1 – March 21, 2017, respectively, was ~~partially offset by an increase~~lower than comparable periods in ~~interest on our Credit Facility~~2016 primarily due to ~~increased levels~~lower debt balances and the absence of ~~borrowing and higher~~ interest ~~rates.~~expense on the Senior Notes in the current year periods. We also had a reduction in capitalized interest ~~as a result of a~~due to the lower carrying amount of unevaluated purchased non-producing leasehold subsequent to the leasehold impairments recorded in ~~2015 and~~ 2016. As a result of applying fresh start accounting upon our emergence from bankruptcy, the carrying value of our unevaluated non-producing leasehold was significantly increased to reflect the fair value of our acreage in the STACK. In future periods subsequent to the adoption of fresh start accounting, we will not be capitalizing interest related to the fresh start gross up of the carrying value of unevaluated acreage as capitalized interest will only be calculated based on the carrying value of actual purchased leasehold.

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

Reorganization items reflect, where applicable, ~~post-petition revenues,~~ expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business. WeAs a result of our emergence from bankruptcy, we have ~~incurred~~also recorded gains on the settlement of liabilities subject to compromise and ~~will continue~~gains from restating our balance sheet to ~~incur significant costs associated with the reorganization. The amount~~fair values under fresh start accounting. These adjustments are discussed in “Note 3—Fresh start accounting” in Item 1. Financial Statements of ~~these~~this report. These costs, which are ~~being expensed as incurred,~~presented below, are expected to significantly affect our results of ~~operations.~~operations (in thousands):

					Successor		Predecessor
					Three months		Three months
	Three months ended		Nine months ended		ended		ended
	September 30, 2016				June 30, 2017		June 30, 2016
Professional fees	$	4,268	$	9,623	$	1,070	$	5,355
Claims for non-performance of executory contract		1,236		1,236
Total reorganization items	$	5,504	$	10,859	$	1,070	$	5,355

Historically, our primary sources of liquidity have been cash generated from our operations, ~~debt,~~borrowings under our credit facility, private equity sales and proceeds from asset dispositions. On February 11, 2016, we borrowed $141.0 million under our Credit Facility which represented substantially all the remaining undrawn amount that was available under the Credit Facility at that time. Since the Petition Date, our principal sources of liquidity have been limited to cash flow from operations and cash on hand. During the pendency of our Chapter 11 Cases, the Lenders have consented to theOur primary use of cash ~~collateral, subject to certain terms and conditions. In addition to the cash requirements necessary~~flow has been to fund ~~ongoing operations, we have incurred and will continue to incur significant professional fees and other costs in connection with the preparation and administration of the Chapter 11 Cases.~~

Our liquidity is greatly impacted by commodity prices for which we have no control over. Beginning in mid 2014 and continuing into the present, oil, natural gas and NGL prices declined significantly and are expected to fluctuate in the future. Historically, we dealt with volatility in commodity prices primarily through the use of derivative contracts as part of our commodity price risk management program. However, our debt defaults and our commencement of the Chapter 11 Cases were events of default under our derivative master agreements thereby providing our derivative counterparties the right to terminate all our derivative positions. As discussed previously, all our outstanding derivative contracts were terminated in May 2016 and we currently do not have any future production hedged. Proceeds from the early terminations, inclusive of amounts receivable for previous settlements, totaled $119.3 million of which $103.6 million were utilized to offset outstanding borrowings under our Credit Facility and the remainder was remitted to us during the third quarter of 2016.

While we are in default on our indebtedness and have a bankruptcy filing, we will no longer be able to represent that we can comply with the credit default or bankruptcy covenants under any prospective derivative master agreements and thus may not be able to enter into new hedging transactions. We are currently negotiating with the Lenders, most of which were previously counterparties to our derivative contracts, regarding the resumption of hedging activity prior to our potential emergence from bankruptcy. However, subsequent to the initial hedges that are required under our potential Restructuring, there can be no assurance that we will be able to enter into new derivative transactions on terms that are acceptable to us.

As of September 30, 2016, we held cash and cash equivalents of $189.4 million and our outstanding debt was $1.7 billion, which included $1.2 billion of Senior Notes classified as liabilities subject to compromise and $444 million under our Credit Facility. Our cash and cash equivalents as of November 4, 2016, was approximately $180.6 million with no significant change in debt. Although we believe that our cash flow from operations and cash on hand will be adequate to meet the operating cost of our existing business, there are no assurances that our cash flow from operations and cash on hand will be sufficient to continue to fund our operations or to allow us to continue as a going concern until a Chapter 11 plan is confirmed by the Bankruptcy Court or another alternative restructuring transaction is approved by the Bankruptcy Court and consummated. Our long-term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a Chapter 11 plan has been confirmed, if at all, by the Bankruptcy Court. If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to significantly reduce, delay or eliminate capital expenditures implement further cost reductions, seek other financing alternatives or seek the sale of some or all of our assets. If we are unsuccessful in developing reserves and adding production through our capital program or our cost-cutting efforts are too overreaching, the value ofused to develop our oil and natural gas ~~properties~~activities and to meet day-to day operating expenses. Upon emergence from bankruptcy, our primary sources of liquidity are cash flows from operations, borrowings under our New Credit Facility and proceeds from derivative settlements. Other potential sources of liquidity in the next twelve months include proceeds from sales of non-core assets. Our cash balance as of June 30, 2017, was $17.3 million and we had borrowing availability under our New Revolver of $86.2 million. As of August 9, 2017, our cash balance was approximately $23.2 million with $153.0 million outstanding on our New Revolver and borrowing availability of $71.2 million. We believe that we have sufficient liquidity to fund our capital expenditures and day to day operations for the next 12 months.

Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. The level of our hedging activity and duration of the instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our ~~financial condition~~operating strategy. We currently have derivative contracts in place for oil and ~~results of operations could be adversely affected.~~natural gas production in 2017, 2018 and 2019 (see Item 3. Quantitative and Qualitative Disclosures About Market Risk).

There can be no assurances regarding our ability to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions that satisfies the conditions of the Bankruptcy Code and, is approved by the Bankruptcy Court.

	Nine months ended
	September 30,						Increase /			Percent			Successor			Predecessor
(in thousands)	2016			2015			(Decrease)			change			Period from March 22, 2017 through June 30, 2017			Period from January 1, 2017 through March 21, 2017			Six months ended June 30, 2016
Cash flows (used in) provided by operating activities	$	23,120		$	29,644		$	(6,524	)		(22.0	)%	$	6,491		$	14,385		$	(8,565	)
Cash flows used in investing activities		(28,401	)		(64,803	)		36,402			(56.2	)%		(50,914	)		(28,010	)		(13,567	)
Cash flows provided by financing activities		177,577			41,450			136,127			328.4	%
Net increase (decrease) in cash during the period	$	172,296		$	6,291		$	166,005		*
Cash flows (used in) provided by financing activities														16,567			(127,732	)		178,670
Net (decrease) increase in cash during the period													$	(27,856	)	$	(141,357	)	$	156,538

Our cash flows from operating activities is derived substantially from the production and sale of oil and natural gas. Our cash flows from operating activities ~~was lower in~~for the ~~current~~six months ended June 30, 2017, which included inflows of $6.5 million for Successor period and $14.4 million for the Predecessor period, increased over the prior year as a result of an increase in revenues and lower ~~revenues from price and production declines~~interest payments in the current year coupled with ~~restructuring costs we incurred~~a paydown of payables in ~~connection with our bankruptcy.~~the prior year. These ~~decreases~~increases were partially offset by ~~a $57.5 million reduction of interest paid from foregoing certain interest payments on~~the additional expenses related to our ~~Senior Notes coupled with decreases in our cash operating expenses.~~capital restructuring and bankruptcy.

When available, we use the net cash provided by operations to partially fund our acquisition, exploration and development activities. With limited cash flows from operating activities due to low commodity prices, ~~and constraints imposed on us while in bankruptcy,~~ our capital expenditures ~~for the nine months ended September 30, 2016,~~in 2017 were also funded by ~~settlement proceeds from~~the settlements of our derivative ~~instruments.~~contracts, borrowings under our New Revolver and cash on hand.

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

Our actual costs incurred, including costs that we have accrued for during the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, and our budgeted ~~2016~~2017 capital expenditures for oil and natural gas properties are summarized in the table below.

			EOR Project				2016 Capital Expenditures		Successor		Predecessor
(in thousands)	E&P Areas		Areas		Total		Budget (1) (2)		Period from March 22, 2017 through June 30, 2017		Period from January 1, 2017 through March 21, 2017		2017 Capital Expenditures Budget (1) (2)
Acquisitions	$	11,991	$	—	$	11,991		7,427	$	16,136	$	3,431		24,000
Drilling		51,107		—		51,107		50,710		45,684		20,754		116,000
Enhancements		6,041		18,180		24,221		25,711		9,097		6,821		32,000
Pipeline and field infrastructure		—		4,502		4,502		12,476		2,711		3,015		6,000
CO₂ purchases		—		9,570		9,570		13,116		3,814		3,308		13,000
Total	$	69,139	$	32,252	$	101,391	$	109,440	$	77,442	$	37,329	$	191,000
Operational area:
STACK										60,756		25,467		139,000
Active EOR Areas										14,418		9,707		39,000
Other										2,268		2,155		13,000
Total									$	77,442	$	37,329	$	191,000

We have increased our 2017 capital budget, previously set at $145.9 million, to a range of $185 million to $200 million due to increased activity in our STACK play. The increased capital budget is a result of the success of our operated drilling program where we will increase the number of operated wells drilled, increased activity from other STACK operators resulting in an increase of our outside operated drilling and completion expenditures and cost inflationary pressures. In addition, we have expanded our leasehold acquisition budget as we have been successful in acquiring STACK acreage in our core operating areas at attractive prices and we have taken advantage of that opportunity. We plan to fund our capital budget with a combination of cash flows from operations, borrowings under our credit facility and proceeds from the sale of non-core assets of approximately $25 million to $30 million.

Net cash used in investing activities during the ~~nine months ended September~~Successor period from March 22 – June 30, ~~2016,~~2017 was comprised of cash outflows for capital expenditure of ~~$120.0~~$61.2 million ~~and was~~ partially offset by cash inflows from derivative settlement receipts of ~~$90.6~~$8.4 million and from asset ~~dispositions~~sales of ~~$1.0~~$1.9 million. Our cash outflows for capital expenditure is greater than our actual costs incurred for the period, disclosed in the table above, as a result of payments in the current period for expenditures accrued at the end of the prior year. Net cash used in investing activities during the ~~nine~~Predecessor period from January 1 to March 21, 2017, was comprised of cash outflows for capital expenditure of $31.2 million partially offset by cash inflows from derivative settlement receipts of $1.3 million and from asset sales of $1.9 million. Net cash used investing activities during the six months ended ~~September~~June 30, ~~2015,~~2016, of the Predecessor, was comprised primarily of cash outflows for capital expenditure of ~~$267.2~~$88.9 million partially offset by cash inflows from derivative settlement receipts of ~~$173.1~~$74.8 million and ~~proceeds~~ from asset ~~dispositions~~sales of ~~$29.3~~$0.5 million. Cash outlays for capital expenditures were significantly higher than costs incurred in the 2015 period as it included a significant paydown of accounts payable for expenditures accrued at the end 2014.

Cash flows from financing activities during the Successor period from March 22 to June 30, 2017, is comprised primarily of cash inflows of $18.0 million from ~~debt~~ borrowings under our New Revolver partially offset by repayments of $1.4 million on debt and capital leases. Cash flows used in financing activities during the Predecessor period from January 1 to March 21, 2017, is comprised primarily of cash outflows ~~from~~for repayments of debt and capital ~~leases. During~~leases of $445.4 million and payment of $2.4 million in debt issuance costs partially offset by cash inflows of $270.0 million from new borrowings and $50.0 million from the ~~nine~~ issuance of equity. The large repayments and borrowings of debt during the Predecessor period in 2017 reflect the extinguishment of our Prior Credit Facility and establishment of our New Credit Facility pursuant to our Reorganization Plan. Cash flows from financing activities during the six

months ended ~~September~~June 30, 2016 ~~we borrowed~~included borrowings of $181.0 million on our debt and ~~made~~ repayments of ~~$1.6~~$2.3 million on our debt and $1.9 million on our capital leases. The cash repayments for debt during the nine months ended September 30, 2016, do not reflect a repayment of $103.6 million that was effectuated by directly offsetting proceeds from the early termination of our derivative contracts against the outstanding balance on our Credit Facility. During the nine months

~~ended September 30, 2015, we borrowed $120.0 million on our debt and made repayments of $75.4 million on our debt and $1.8 million on our~~ capital leases.

(in thousands)

September 30,
2016

December 31,
2015

9.875% Senior Notes due 2020, net of discount of $0 and $4,185, respectively (1)

$
—

$
293,815

8.25% Senior Notes due 2021 (1)

—

384,045

7.625% Senior Notes due 2022, including premium of $0 and $4,939, respectively (1)

—

530,849

Credit Facility (2)

444,440

367,000

Real estate mortgage notes (2)

9,735

10,182

Installment notes (2)

683

1,799

Capital lease obligations (2)

17,577

19,437

$
472,435

$
1,607,127

	Successor			Predecessor
	June 30,			December 31,
(in thousands)	2017			2016 (1)
New Revolver	$	138,000		$	—
New Term Loan, net of $698 of discount as of June 30, 2017		148,869			—
Prior Credit Facility		—			444,440
Real estate and equipment notes		9,397			10,029
Capital lease obligations		15,665			16,946
Unamortized debt issuance costs		(1,546	)		(2,303	)
	$	310,385		$	469,112

Substantially all of our indebtedness is currently in default as a result of: (i) our commencement of the Chapter 11 Cases, (ii) our nonpayment of interest on the Senior Notes, (iii) the going concern audit opinion in our recent annual financial statements and (iv) violation of certain financial covenants. Moreover, due to our commencement of the Chapter 11 Cases, all of our indebtedness has been accelerated by operation of law. Please see “Note 6—Debt” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2015, for a discussion of material terms governing our Senior Notes and Credit Facility.

~~Our financial statements include amounts classified as liabilities~~ subject to compromise which represent our estimates of pre-petition obligations that will be allowed as claims in our bankruptcy case. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. Because the uncertain nature of many of the potential claims has not been determined at this time, the magnitude of such claims is not reasonably estimable at this time. We will continue to evaluate these liabilities during the pendency of the Chapter 11 Cases and adjust amounts as necessary. The magnitude of claims and or the adjustments to such claims may be material. Nothing herein constitutes an admission or waiver of any rights.

The following table summarizes the components of “Liabilities subject to compromise” included on our Consolidated Balance Sheet ~~as of September 30, 2016:~~immediately prior to emergence on March 21, 2017:

	September 30, 2016
(in thousands)			March 21, 2017
Accounts payable and accrued liabilities	$	9,740	$	6,687
Accrued payroll and benefits payable		5,133		3,949
Revenue distribution payable		4,690		3,050
Senior Notes and associated accrued interest		1,267,265		1,267,410
Liabilities subject to compromise	$	1,286,828	$	1,281,096

Our Credit Facility, which matures on November 1, 2017, had an outstanding balance of $444.4 million as of September 30, 2016. The balance as of September 30, 2016, reflects a partial repayment of $103.6 million during the third quarter of 2016 utilizing proceeds from the early termination of all our outstanding derivative contracts. As a result of defaults, there is currently no availability under this facility.

As discussed earlier, ~~our current negotiations regarding~~claims from the ~~structure of our exit financing~~Senior Notes and associated interest along with approximately $2.4 million in general unsecured claims were settled upon emergence ~~from bankruptcy contemplates~~through the issuance of Successor common stock. The remaining claims were either paid or reinstated in full.

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

New Term Loan. The loan, which is collateralized by our oil and natural gas properties, is scheduled to mature on March 21, 2021. Interest on the outstanding amount of the New Term Loan will accrue at an interest rate equal to either: (a) the Alternate Base Rate (as defined in the New Credit Facility) plus a 6.75% margin or (b) the Adjusted LIBO Rate (as defined in the New Credit Facility), plus a 7.75% margin with a 1.00% floor on the Adjusted LIBO Rate. We are required to make scheduled, mandatory principal payments in the amount of $1.2 million in calendar 2017, $1.5 million in 2018, $3.8 million in 2019 and $6.8 million in 2020 with the remaining outstanding balance due upon maturity.

New Revolver. The New Revolver is a $400.0 million facility collateralized by our oil and natural gas properties and is scheduled to mature on March 21, 2021. Availability under our New Revolver is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base ofon the Effective Date was $225.0 million ~~augmented by a four-year $150.0 million term loan.~~and the first borrowing base redetermination has been set for on or about May 1, 2018.

~~Subject to certain exceptions,~~Interest on the outstanding amounts under the ~~Bankruptcy Code,~~New Revolver will accrue at an interest rate equal to either (i) the ~~commencement~~Alternative Base Rate plus a margin that ranges between 2.00% to 3.00% depending on utilization or (ii) the Adjusted LIBO Rate applicable to one, two three or six month borrowings plus a margin that ranges between 3.00% to 4.00% depending on utilization. In the case that an Event of Default (as defined under the New Credit Facility) occurs, the applicable rate while in default will be the Alternative Base Rate plus an additional 2.00% and plus the applicable margin.

Commitment fees of 0.50% accrue on the unused portion of the ~~Chapter 11 Cases automatically enjoined,~~borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or ~~stayed,~~premium. Letter of credit fees will accrue at 0.125% plus the ~~continuation of most judicial or administrative proceedings or~~margin used to determine the ~~filing of other actions against us or~~interest rate applicable to New Revolver borrowings that are based on Adjusted LIBO Rate.

If the outstanding borrowings under our ~~property~~New Revolver were to ~~recover, collect or secure a claim arising prior to~~exceed the ~~Petition Date. Creditors are stayed from taking any actions against us~~borrowing base as a result of ~~debt defaults, subject~~a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days or (2) commencing within 45 days to repay the deficiency in equal monthly installments over a six -month period or (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency.

The New Credit Facility contains certain ~~limited exceptions permitted by~~thresholds on the ~~Bankruptcy Code. There~~amount of oil and gas properties that can be ~~no assurances that~~disposed of within a specified timeframe before triggering mandatory prepayments. Upon the ~~agent and~~consummation of a Triggering Disposition (as defined in the ~~Lenders~~New Credit Facility) the borrowing base will ~~consensually agree~~be automatically decreased by an amount equal to the ~~potential Restructuring or other restructuring~~borrowing base value assigned to the oil and gas properties disposed of. Additionally, 100% of the ~~Credit Facility. Should we~~net proceeds received from the Triggering Disposition would be ~~unable~~required to ~~reach an agreement with~~be used to prepay the ~~agent and~~New Term Loan minus any amounts required to cure a borrowing base deficiency from the ~~Lenders, any proposed non-consensual restructuring of~~decrease in the borrowing base.

The New Credit Facility ~~could result~~contain covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our New Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others. The financial covenants require that we maintain: (1) a Current Ratio (as defined in ~~substantial delay~~the New Credit Facility) of no less than 1.00 to 1.00, (2) an Asset Coverage Ratio (as defined in ~~emergence from bankruptcy~~the New Credit Facility) of no less than 1.35 to 1.00, (3) Liquidity (as defined in the New Credit Facility) of at least $25.0 million and ~~there can be~~(4) a Ratio Total Debt to EBITDAX (as defined in the New Credit Facility) of no ~~assurances that~~greater than 3.5 to 1.0 calculated on a trailing four-quarter basis. We are required to comply with these covenants for each fiscal quarter ending on and after March 31, 2017, except for the ~~Bankruptcy Court would approve such proposed non-consensual restructuring. During the Chapter 11 Cases, we expect to remain current on~~Asset Coverage Ratio, for which compliance is required semiannually. We were in compliance with our ~~interest payments~~financial covenants under the New Credit Facility ~~to the extent required by order~~as of ~~the Bankruptcy Court.~~June 30, 2017.

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million through the sale and subsequent leaseback of existing compressors owned by us. The ~~carrying value of these compressors is included in our oil and natural gas full cost pool. The~~ lease financing obligations are for ~~84 -month~~84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal ~~payments~~ and interest ~~expense. As discussed previously, our debt defaults and the commencement~~expense based on a weighted average implicit interest rate of ~~the Chapter 11 Cases~~3.8%. Minimum lease payments are ~~events of default under our capital leases.~~$3.2 million annually.

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to CO₂ recycle compressors at our EOR facilities and office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase obligations primarily relate to contracts for the purchase of CO₂ and drilling rig services. ~~In May 2016, we took delivery of an additional CO~~₂ ~~compressor for which we have entered into an 84 month lease with monthly payments of $23,000.~~

Other than ~~additional debt borrowings during~~changes to our credit facility and the ~~year~~discharge of our Senior Notes and certain general unsecured claims pursuant our ~~new compressor lease discussed above, there were no~~Reorganization Plan, the only other material ~~changes~~change to our contractual commitments since December 31, ~~2015.~~2016, relates to our contracts for drilling rig services. As of June 30, 2017, our obligations under our drilling rig contracts were approximately $3.1 million.

Our off-balance sheet arrangements as of June 30, 2017, include warrants to purchase 140,023 shares of Successor common stock with an exercise price of $36.78 per share and expiring on June 30, 2018. These warrants embody a contract that would have been accounted for as a derivative instrument except that they are both indexed to our own stock and classified in stockholders equity.

~~The~~Although not directly comparable between Successor and Predecessor, we believe that the following ~~were~~discussion of material changes in our balance ~~sheet:~~sheet may be useful:

September 30,

December 31,

(in thousands)

2016

2015

Change

Assets

Cash and cash equivalents

$
189,361

$
17,065

$
172,296

Accounts receivable

41,273

79,000

(37,727
)
Derivative instruments

—

163,238

(163,238
)
Total oil and natural gas properties

532,871

798,837

(265,966
)
Deferred income taxes—noncurrent

—

53,914

(53,914
)
Other assets

8,253

27,694

(19,441
)
Liabilities

Accounts payable and accrued liabilities

32,003

66,222

(34,219
)
Long-term debt and capital leases, classified as current

472,435

1,607,127

(1,134,692
)
Deferred income taxes—current

—

53,914

(53,914
)
Liabilities subject to compromise

1,286,828

—

1,286,828

•

The increase in cash was primarily due to the $181.0 million drawing under our Credit Facility during the first quarter of 2016 which represented substantially all the remaining undrawn amount that was available under the Credit Facility at that time.

	Successor		Predecessor
	June 30,		December 31,
(in thousands)	2017		2016			Change
Assets
Cash and cash equivalents	$	17,267	$	186,480		$	(169,213	)
Accounts receivable, net		59,901		46,226			13,675
Derivative instruments		36,356		—			36,356
Property and equipment		53,902		41,347			12,555
Total oil and natural gas properties		1,236,039		555,184			680,855
Liabilities
Accounts payable and accrued liabilities		64,495		42,442			22,053
Long-term debt and capital leases, classified as current		4,813		469,112			(464,299	)
Long-term debt and capital leases, less current maturities		305,572		—			305,572
Derivative instruments		—		13,369			(13,369	)
Liabilities subject to compromise		—		1,284,144			(1,284,144	)
Total stockholders' equity (deficit)		950,745		(1,042,153	)		1,992,898

Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our Credit Facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

We define adjusted EBITDA as net income, adjusted to exclude (1) asset impairments, (2) interest and other financing costs, net of capitalized interest, (3) income taxes, (4) depreciation, depletion and amortization, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, (9) upfront premiums paid on settled derivative contracts, (10) impairment charges, (11) ~~expenses associated with our cost reduction initiatives, transition, business optimization and other restructuring charges not to exceed $25.0 million on a cumulative basis, (12)~~ other significant, unusual non-cash charges, ~~and (13)~~(12) proceeds from any early monetization of derivative contracts with a scheduled maturity date more than 12 months following the date of such monetization—this exclusion is consistent with our prior treatment, for EBITDA reporting, of any large monetization of derivative ~~contracts.~~contracts and (13) certain expenses related to our cost reduction initiatives, reorganization and fresh start accounting activities for which our lenders have permitted us to exclude when calculating covenant compliance based on the prevailing provisions under our credit facility at that time.

The following ~~table provides~~tables provide a reconciliation of ~~our~~ net ~~loss~~income (loss) to adjusted EBITDA for the specified periods:

	Successor			Predecessor
(in thousands)	Three months ended June 30, 2017			Three months ended June 30, 2016
Net income (loss)	$	21,365		$	(256,654	)
Interest expense		5,051			20,153
Income tax expense		37			92
Depreciation, depletion, and amortization		30,851			32,964
Non-cash change in fair value of derivative instruments		(16,811	)		127,684
Upfront premiums paid on settled derivative contracts		—			(15,290	)
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date excluded from EBITDA		—			(12,810	)
Interest income		(5	)		(61	)
Stock-based compensation expense		—			306
Loss on sale of assets		863			1
Loss on impairment of assets		—			204,442
Restructuring, reorganization and other		1,185			14
Adjusted EBITDA	$	42,536		$	100,841

	Successor			Predecessor
(in thousands)	Period from March 22, 2017 through June 30, 2017			Period from January 1, 2017 through March 21, 2017			Six months ended June 30, 2016
Net income (loss)	$	1,682		$	1,041,959		$	(395,060	)
Interest expense		5,701			5,862			49,807
Income tax expense		38			37			224
Depreciation, depletion, and amortization		34,265			24,915			64,772
Non-cash change in fair value of derivative instruments		(3,004	)		(46,721	)		163,238
Gain on settlement of liabilities subject to compromise		—			(372,093	)		—
Fresh start accounting adjustments		—			(641,684	)		—
Upfront premiums paid on settled derivative contracts		—			—			(20,608	)
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date excluded from EBITDA		—			—			(12,810	)
Interest income		(5	)		(133	)		(90	)
Stock-based compensation expense		—			155			(717	)
Loss (gain) on sale of assets		863			(206	)		(66	)
Loss on impairment of assets		—			—			282,338
Write-off of debt issuance costs, discount and premium		—			1,687			16,970
Restructuring, reorganization and other		1,811			24,297			3,139
Adjusted EBITDA	$	41,351		$	38,075		$	151,137

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

Three months ended September 30,

Nine months ended September 30,

(in thousands)

2016

2015

2016

2015

Net loss

$
(5,491
)

$
(647,142
)

$
(400,551
)

$
(831,930
)
Interest expense

7,436

28,598

57,243

83,202

Income tax expense (benefit)

(59
)

(48,776
)

165

(161,314
)
Depreciation, depletion, and amortization

29,624

52,027

94,396

173,694

Non-cash change in fair value of non-hedge derivative instruments

—

(30,941
)

163,238

67,883

Upfront premiums paid on settled derivative contracts

—

—

(20,608
)

—

Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date excluded from EBITDA

—

—

(12,810
)

—

Interest income

(50
)

(21
)

(140
)

(168
)
Stock-based compensation expense

(4,538
)

(20
)

(5,254
)

(32
)
Loss (gain) on sale of assets

195

(77
)

128

(1,448
)
Loss on impairment of assets

202

737,758

282,540

968,631

Write-off of Senior Note issuance costs, discount and premium

—

—

16,970

—

Cost reduction initiatives expense

89

603

3,228

9,739

Adjusted EBITDA

$
27,408

$
92,009

$
178,545

$
308,257

(dollars in thousands)	June 30, 2017
Current assets per GAAP	$	108,409
Plus—Availability under New Revolver		86,172
Less—Short-term derivative instruments		(23,275	)
Current assets as adjusted	$	171,306
Current liabilities per GAAP	$	92,630
Less—Current asset retirement obligation		(7,184	)
Less—Current maturities of long term debt		(4,813	)
Current liabilities as adjusted	$	80,633
Current ratio per GAAP		1.17
Current ratio for loan compliance (1)		2.12

For a discussion of our critical accounting policies, which remain unchanged, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations ” in our Annual Report on Form 10-K for the year ended December 31, ~~2015.~~2016.

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

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

Commodity prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our New Credit Facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, our gross revenues from oil and natural gas sales would change approximately ~~$4.8~~$3.0 million for each $1.00 change in oil and natural gas liquid prices and ~~$1.2~~$0.7 million for each $0.10 change in natural gas prices.

~~In the past, we have entered into various types of derivative instruments, including commodity price swaps, costless collars, put options, and basis protection swaps to~~To mitigate a portion of our exposure to fluctuations in commodity ~~prices. Our debt defaults~~prices, we enter into various types of derivative instruments, which in the past have included commodity price swaps, collars, put options, enhanced swaps and ~~the commencement~~basis protection swaps. We do not apply hedge accounting to any of our ~~Chapter 11 Cases were events of default under our~~ derivative ~~master agreements thereby providing our derivative counterparties the right to terminate all our derivative positions.~~instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Derivative gains (losses)” in the consolidated statements of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Please see “Note 6—Derivative instruments” in “Item 1. Financial statements” of this report for further discussion of our derivative instruments.

Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions ~~were terminated~~continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in ~~May, 2016. While we~~closing or restructuring a position before the settlement date are ~~in default on our indebtedness and have a bankruptcy filing, we will no longer be able~~identical to ~~represent that we can comply with the credit default or bankruptcy covenants under any prospective derivative master agreements and thus may not be able~~those reviewed when deciding to enter into ~~new hedging transactions. We are currently negotiating with~~ the ~~Lenders, most~~original derivative position.

The fair value of ~~which were previously counterparties~~our outstanding derivative instruments at June 30, 2017, was a net asset of $36.4 million. Based on our outstanding derivative instruments as of June 30, 2017, summarized below, a 10% increase in the June 30, 2017, forward curves used to mark-to-market our derivative ~~contracts, regarding the resumption~~instruments would have decreased our position to a net asset of ~~hedging activity prior~~$7.5 million, while a 10% decrease would have increased our net asset position to ~~our potential emergence from bankruptcy. However, subsequent to the initial hedges that~~$65.2 million.

Our outstanding oil derivative instruments as of June 30, 2017, are required under our potential Restructuring, there can be no assurance that we will be able to enter into new derivative transactions on terms that are acceptable to us. Please see “Liquidity and capital resources” in Item 2.summarized below:

			Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls		Swaps		Purchased puts		Sold calls
July - September 2017
Oil swaps		883	$	54.97	$	—	$	—
October - December 2017
Oil swaps		883	$	54.97	$	—	$	—
January - March 2018
Oil swaps		540	$	54.92	$	—	$	—
Oil collars		45	$	—	$	50.00	$	60.50
April - June 2018
Oil swaps		546	$	54.92	$	—	$	—
Oil collars		46	$	—	$	50.00	$	60.50
July - September 2018
Oil swaps		515	$	54.92	$	—	$	—
Oil collars		46	$	—	$	50.00	$	60.50
October - December 2018
Oil swaps		515	$	54.92	$	—	$	—
Oil collars		46	$	—	$	50.00	$	60.50
January - March 2019
Oil swaps		333	$	54.26	$	—	$	—
April - June 2019
Oil swaps		337	$	54.26	$	—	$	—
July - September 2019
Oil swaps		321	$	54.26	$	—	$	—
October - December 2019
Oil swaps		321	$	54.26	$	—	$	—

~~Management’s Discussion and Analysis~~Our outstanding natural gas derivative instruments as of ~~Financial Condition and Results of Operations for a discussion on the impact of our master agreement defaults on our derivative portfolio and our ability to hedge.~~June 30, 2017, are summarized below:

Period and type of contract	Volume BBtu		Weighted average fixed price per MMBtu
July - September 2017
Natural gas swaps		2,342	$	3.34
October - December 2017
Natural gas swaps		2,250	$	3.33
January - March 2018
Natural gas swaps		1,530	$	3.03
April - June 2018
Natural gas swaps		1,433	$	3.03
July - September 2018
Natural gas swaps		1,449	$	3.03
October - December 2018
Natural gas swaps		1,449	$	3.03
January - March 2019
Natural gas swaps		819	$	2.86
April - June 2019
Natural gas swaps		828	$	2.86
July - September 2019
Natural gas swaps		838	$	2.86
October - December 2019
Natural gas swaps		837	$	2.86

Interest rates. As of ~~September~~June 30, ~~2016,~~2017, borrowings bear interest at the ~~Alternate Base~~Adjusted LIBO Rate, as defined under the New Credit Facility, plus the applicable margin. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $287.6 million, equal to the balance under our New Credit Facility as of ~~$444.4 million,~~June 30, 2017, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be ~~$4.4~~$2.9 million.

WeAs required by Rule 13a-15(b) of the Exchange Act, we have ~~established~~evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures ~~to ensure that material information relating to us, including our consolidated subsidiaries, is made known to~~(as defined in Rules 13a-15(e) and 15d-15(e) under the ~~officers who certify our financial reports and to other members of senior management and the board of directors. Based on their evaluation~~Exchange Act) as of the end of the period covered by this ~~quarterly report,~~Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures ~~(as defined~~were effective as of June 30, 2017, at the reasonable assurance level.

Changes in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

There ~~were~~have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time.

Please see “Note 9—10—Commitments and contingencies” in Item 1. Financial Statements of this report for a discussion of our material legal proceedings. In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

During 2017, there have been no material changes in our risk factors disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016, and in Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, except for the following:

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. As a result, our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.

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

The trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the ~~risks and uncertainties associated with~~following:

There is a limited trading market for our securities and the ~~ability~~market price of ~~third parties~~our securities is subject to volatility.

Upon our emergence from bankruptcy, our old common stock was cancelled and we issued new common stock. Our common stock is not listed on any national or regional securities exchange. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Reorganization Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described under this “Risk Factors” and elsewhere in this report. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. The common stock may be traded only infrequently in transactions arranged through brokers or otherwise, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant

sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

There is currently no active public trading market for our Class A common stock or our Class B common stock. Therefore, the holders of our common stock may be unable to liquidate their investment in our common stock.

Our Class A common stock is quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. Although our Class A common stock is quoted on the OTCQB, trading has been irregular and with low volumes and therefore the market price of our Class A common stock may be difficult to ascertain. Our Class B common stock is not listed or quoted on the OTCQB or any other stock exchange or quotation system, and we have not applied for such listing. Further, in the event we were to seek ~~and obtain court approval to terminate contracts and other agreements with us;~~

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 Cases could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 Cases will have on our business, financial condition and results of operations.

~~We believe it is highly likely that the shares~~quotation system would accept any of our ~~existing~~Class B common stock ~~will be cancelled in our Chapter 11 Cases.~~

~~We have a significant amount of indebtedness that is senior to our existing common stock in our capital structure.~~for listing. As a result, ~~we believe that it is highly likely that the shares of our existing common stock will be cancelled~~investors in our ~~Chapter 11 Cases and investors will receive little to no recovery on account of such shares.~~

~~Operating under Bankruptcy Court protection for a long period of time may harm our business.~~

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the proceedings related to the Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating under Bankruptcy Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the proceedings related to the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our businesses successfully and will seek to establish alternative commercial relationships.

Furthermore, so long as the proceedings related to the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 proceeding. The Chapter 11 proceedings may also require us to seek debtor-in-possession financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any securities ~~in the Debtor could become further devalued or become worthless.~~

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 proceedings.

We may not be able to ~~obtain confirmation of a Chapter 11 Plan of Reorganization.~~

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization (“Plan”), solicit and obtainresell their shares at or above the requisite acceptances of such a plan and fulfill other statutory conditions for confirmation of such a plan, which have not occurred to date. The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding our plan.

We may not receive the requisite acceptances of constituencies in the proceedings related to the Chapter 11 proceedings to confirm our Plan. Even if the requisite acceptances of our Plan are received, the Bankruptcy Court may not confirm such a plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejectionpurchase price paid by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock).

If a Chapter 11 plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

~~Even if a Chapter 11 Plan of Reorganization is consummated, we will continue to face risks.~~

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes in our industry, potential revaluing of our assets due to Chapter 11 proceedings, changes in consumer demand for, and acceptance of, our oil and gas and increasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that a confirmed Chapter 11 plan of reorganization will achieve our stated goals.

In addition, at the outset of the Chapter 11 proceedings, the Bankruptcy Code gives the Debtor the exclusive right to propose the Plan and prohibits creditors, equity security holders and others from proposing a plan. We have currently retained the exclusive right to propose the Plan. If the Bankruptcy Court terminates that right, however, or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of the Plan in order to achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the proceedings related to the Chapter 11 Cases. Adequate funds may not be available when neededthem or may not be ~~available on favorable terms.~~

We have substantial liquidity needs and may be required to seek additional financing. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to replace our proved reserves or to maintain current production levels and generate revenue will be limited.

Our principal sources of liquidity historically have been cash flow from operations, sales of oil and natural gas properties, borrowings under our Credit Facility, and issuances of debt securities. Our capital program will require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations remains depressed or decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and proved reserves over time. In addition, drilling activity may be directed by our partners in certain areas and we may have to forfeit acreage if we do not have sufficient capital resources to fund our portion of expenses.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirement necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to Chapter 11 Cases until we are able to ~~emerge from our Chapter 11 proceedings.~~

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things; (i) our ability to comply with the terms and conditions of any cash collateral order entered by the Bankruptcy Court in connection with the Chapter 11 proceedings, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction, and (v) the cost, duration and outcome of the Chapter 11 proceedings. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that cash on hand and cash flow from operation is not sufficient to meet our liquidity needs, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is availableresell them at all. ~~Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.~~

~~In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.~~

If the Bankruptcy Court finds that it would be in the best interest of creditors and/or the Company, the Bankruptcy Court may convert our Chapter 11 bankruptcy case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate the Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a Chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a disorderly fashion over a short period of time rather than reorganizing or selling in a controlled manner the Company’s businesses as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with cessation of operations.

~~We may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results or operations.~~

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to May 10, 2016, or before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the terms of the plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

~~Our financial results may be volatile and may not reflect historical trends.~~

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

Transfers of our equity, or issuances of equity in connection with our Chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have federal net operating loss carryforwards of approximately $441 million as of December 31, 2015. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation.

Please see “Note 2—Chapter 11 ~~filing”~~reorganization” in Item 1. Financial Statements of this report for a discussion of our default upon senior securities.

The exhibits listed below in the Exhibit Index, following the Signatures page, are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

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

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

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)

Class	Number of Shares		~~shares~~
Class A Common Stock, $0.01 par value	~~333,686~~	37,110,630
Class B Common Stock, $0.01 par value	~~344,859~~
~~Class C Common Stock, $0.01 par value~~	~~209,882~~
~~Class E Common Stock, $0.01 par value~~	~~504,276~~
~~Class F Common Stock, $0.01 par value~~	1
~~Class G Common Stock, $0.01 par value~~	27,871,512

		Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements		67
Consolidated ~~balance sheets as of September 30, 2016 (unaudited) and December 31, 2015~~Balance Sheets		67
Consolidated ~~statements~~Statements of ~~operations for the three and nine months ended September 30, 2016, and 2015 (unaudited)~~		8
~~Consolidated statements of cash flows for the nine months ended September 30, 2016, and 2015 (unaudited)~~Operations		9
~~Condensed notes to consolidated financial statements (unaudited)~~Consolidated Statements of Stockholders' Equity (Deficit)		1011
Consolidated Statements of Cash Flows		12
Condensed Notes to Consolidated Financial Statements		13
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		2937
Overview		2937
Results of ~~operations~~Operations		3341
Liquidity and ~~capital resources~~Capital Resources		4051
Non-GAAP ~~financial measure~~Financial Measure and ~~reconciliation~~Reconciliation		4455
Critical ~~accounting policies~~Accounting Policies		4557
Recent ~~accounting pronouncements~~Accounting Pronouncements		4557
Item 3. Quantitative and Qualitative Disclosures about Market Risk		4557
Item 4. Controls and Procedures		4659
Part II. OTHER INFORMATION
Item 1. Legal Proceedings		4659
Item 1A. Risk Factors		4660
Item 3. Defaults Upon Senior Securities		4961
Item 5. Other Information		4961
Item 6. Exhibits		5061
Signatures		5162

	•	~~EOR Project Areas.~~Areas where we are currently ~~injecting,~~or where we plan to inject and/or ~~have potential for injection of CO2~~recycle CO₂ as a means of oil recovery.

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

Bankruptcy Court	United States Bankruptcy Court for the District of Delaware

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.

Developed acreage	The number of acres that are assignable to productive wells.

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 ~~recovery. These Areas~~after Secondary Recovery.

Prior Credit Facility	Eighth Restated Credit Agreement, dated as of April 12, 2010, by and among us, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent and each of the Lenders named therein, as amended.

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.

MMcf/d	Millions of cubic feet per day.

Natural gas liquids (NGLs)	Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ~~our active EOR Project Areas~~propane, butane, isobutane, pentane, hexane and ~~potential EOR Project Areas.~~natural gasoline.

New Credit Facility	Ninth Restated Credit Agreement, dated as of March 21, 2017, by and among, 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.

Proved developed reserves	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved reserves	The quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Proved undeveloped reserves	Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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

Registration Rights Agreement	Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein.

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

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

STACK	An acronym standing for Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko Basin of Oklahoma in which we operate.

Undeveloped acreage	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

Unit	The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.


Large ~~Accelerated Filer~~accelerated filer	☐	Accelerated ~~Filer~~filer	☐


Non-accelerated filer (Do not check if a smaller reporting company)	☒

Smaller reporting company	☐

~~Non-Accelerated Filer~~	☒	~~Smaller Reporting Company~~Emerging growth company	☐

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

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

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

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

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

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

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

Total payments for 2017	$	1,183
Total payments for 2018		1,500
Total payments for 2019		3,750
Total payments for 2020		6,750
Total mandatory payments	$	13,183

	September 30, 2016		December 31, 2015
9.875% Senior Notes due 2020, net of discount of $0 and $4,185, respectively (1)	$	—	$	293,815
8.25% Senior Notes due 2021 (1)		—		384,045
7.625% Senior Notes due 2022, including premium of $0 and $4,939, respectively (1)		—		530,849
Credit Facility (2)		444,440		367,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 3.16% to 5.46%, due August 2021 through December 2028; collateralized by real property (2)		9,735		10,182
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.00%, due October 2016 through February 2018; collateralized by automobiles, machinery and equipment (2)		683		1,799
Capital lease obligations (2)		17,577		19,437
Total debt, net		472,435		1,607,127
Less current portion		472,435		1,607,127
Total long-term debt, net	$	—	$	—

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

	Phantom Plan							RSU Plan
	Weighted average grant date fair value		Phantom shares			Vest date fair value		Weighted average grant date fair value		Restricted Stock Units			Vest date fair value
	($ per share)							($ per share)
Unvested and outstanding at January 1, 2016	$	18.62		10,619				$	10.53		269,886
Granted	$	—		—				$	—		—
Vested	$	18.39		(9,729	)	$	—	$	9.01		(140,818	)	$	—
Forfeited	$	21.09		(890	)			$	8.24		(28,769	)
Unvested and outstanding at September 30, 2016	$	—		—				$	7.20		100,299

	Year-end		First quarter		Second quarter		Third quarter
	2015		2016		2016		2016
Crude oil ($ per barrel)	$	50.28	$	46.26	$	43.12	$	41.68
Natural gas ($ per Mmbtu)	$	2.58	$	2.39	$	2.23	$	2.28
Natural gas liquids ($ per barrel)	$	15.84	$	14.86	$	13.92	$	14.03

	Third quarter 2016		Year-end 2016		First quarter 2017		Second quarter 2017
Crude oil ($ per Bbl)	$	41.68	$	42.75	$	47.61	$	48.95
Natural gas ($ per MMBtu)	$	2.28	$	2.49	$	2.73	$	3.01
Natural gas liquids ($ per Bbl)	$	14.03	$	13.47	$	17.14	$	20.07

(in thousands)	September 30, 2016		December 31, 2015
9.875% Senior Notes due 2020, net of discount of $0 and $4,185, respectively (1)	$	—	$	293,815
8.25% Senior Notes due 2021 (1)		—		384,045
7.625% Senior Notes due 2022, including premium of $0 and $4,939, respectively (1)		—		530,849
Credit Facility (2)		444,440		367,000
Real estate mortgage notes (2)		9,735		10,182
Installment notes (2)		683		1,799
Capital lease obligations (2)		17,577		19,437
	$	472,435	$	1,607,127

CHAPARRAL ENERGY, INC.

By:		/s/ K. Earl Reynolds
Name:		K. Earl Reynolds
Title:		Chief Executive Officer
		(Principal Executive Officer)

By:		/s/ Joseph O. Evans
Name:		Joseph O. Evans
Title:		Chief Financial Officer and Executive Vice President
		(Principal Financial Officer and Principal Accounting Officer)

Exhibit No.		Description

3.1*		~~Second~~Third Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. ~~(the “Company”), dated as of April 12, 2010.~~ (Incorporated by reference to Exhibit 3.1 toof the Company’s ~~Annual~~Current Report on Form ~~10-K~~8-K filed on ~~April 14, 2010)~~March 27, 2017)

3.2*		~~Second~~ Amended and Restated Bylaws of ~~the Company, dated as of April 12, 2010.~~Chaparral Energy, Inc. (Incorporated by reference to Exhibit 3.2 toof the Company’s ~~Annual~~Current Report on Form ~~10-K~~8-K filed on ~~April 14, 2010)~~March 27, 2017)

4.1*		Registration Rights Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on March 27, 2017)

4.2*		Warrant Agreement dated as of March 21, 2017, among Chaparral Energy, Inc. and Computershare Inc. as warrant agent (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on March 27, 2017)

4.3*		Stockholders Agreement, dated as of March 21, 2017, by and among Chaparral Energy, Inc. and the Stockholders named therein (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed on March 27, 2017)

31.1		Certification by ~~Chief~~Principal Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2		Certification by ~~Chief~~Principal Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

32.1		Certification by ~~Chief~~Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of ~~Chief~~Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

~~CHAPARRAL ENERGY, INC.~~

~~By:~~		~~/s/ Mark A. Fischer~~
~~Name:~~		~~Mark A. Fischer~~
~~Title:~~		~~Chief Executive Officer~~
		~~(Principal Executive Officer)~~

~~By:~~		~~/s/ Joseph O. Evans~~
~~Name:~~		~~Joseph O. Evans~~
~~Title:~~		~~Chief Financial Officer and~~ ~~Executive Vice President~~
		~~(Principal Financial Officer and~~ ~~Principal Accounting Officer)~~

~~Exhibit No.~~		~~Description~~

3.1*		Second Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

3.2*		~~Second Amended and Restated Bylaws of the Company, dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)~~

~~31.1~~		~~Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act~~

~~31.2~~		~~Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act~~

~~32.1~~		~~Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~

~~32.2~~		~~Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~

~~101.INS~~		~~XBRL Instance Document~~

~~101.SCH~~		~~XBRL Taxonomy Extension Schema Document~~

~~101.CAL~~		~~XBRL Taxonomy Extension Calculation Linkbase Document~~

~~101.DEF~~		~~XBRL Taxonomy Extension Definition Linkbase Document~~

~~101.LAB~~		~~XBRL Taxonomy Extension Label Linkbase Document~~

~~101.PRE~~		~~XBRL Taxonomy Extension Presentation Linkbase Document~~