UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended ~~September~~June 30, ~~2020~~2021


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

For the transition period from to

Commission file number 001-37907


			EXTRACTION OIL & GAS, INC.
			(Exact name of registrant as specified in its charter)


Delaware		46-1473923
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

370 17th Street
Suite ~~5300~~5200
Denver,	Colorado	80202
(Address of principal executive offices)		(Zip Code)

(720) 557-8300

(Registrant’s telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of exchange on which registered

Common Stock, par value $0.01

XOG

NASDAQ Global Select Market

~~Securities registered pursuant to Section 12(b) of the Act: None.~~

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

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

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

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

Large Accelerated Filer

☐

Accelerated Filer

☒☐

Non-Accelerated Filer

☐☒

Smaller Reporting Company

☒

Emerging Growth Company

☐

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

Indicate by check mark whether the registrant ~~is a shell company (as defined in Rule 12b-2~~has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange ~~Act).~~Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☐☒ No ☒☐

The total number of shares of common stock, par value $0.01 per share, outstanding as of ~~November~~August 6, ~~2020~~2021 was ~~138,371,578.~~

25,840,663.

Table of Contents

EXTRACTION OIL & GAS, INC.

TABLE OF CONTENTS


		Page
PART I—FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements (Unaudited)	2
	Condensed Consolidated Balance Sheets ~~as of~~ ~~September~~ 30 ~~, 20~~20 ~~and December 31, 201~~9	2
	Condensed Consolidated Statements of Operations ~~for the three~~ ~~and~~ ~~ninemonths ended~~ ~~September~~ 30 ~~, 20~~20 ~~and 201~~9	3
	Condensed Consolidated Statements of Cash Flows ~~for theninemonths endedSeptember~~ ~~30, 2020~~ ~~and 20~~19	45
	Condensed Consolidated Statements of Changes in Stockholders’ ~~Equity and Noncontrolling Interest for the three~~Equit ~~and~~ ~~ninemonths endedSeptember~~ 30 ~~, 20~~20 ~~and 20~~19y	56
	Notes to the Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4132
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	6558
Item 4.	Controls and Procedures	6658

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	6759
Item 1A.	Risk Factors	6759
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	6859
Item 3.	Defaults upon Senior Securities	6859
Item 4.	Mine Safety Disclosures	6959
Item 5.	Other Information	6959
Item 6.	Exhibits	6961
	Signatures	7062

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

~~(Debtor-In-Possession)~~

(Unaudited)

September 30,
2020 December 31,
2019
ASSETS
Current Assets:
Cash and cash equivalents $ 121,165 $ 32,382
Accounts receivable, net
Trade 53,485 32,009
Oil, natural gas and NGL sales 54,349 105,103
Inventory, prepaid expenses and other 48,951 36,702
Commodity derivative asset 32,625 17,554
Total Current Assets 310,575 223,750
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties 4,718,471 4,530,934
Unproved oil and gas properties 334,971 524,214
Wells in progress 140,290 149,733
Less: accumulated depletion, depreciation, amortization and impairment charges (3,218,591) (2,985,983)
Net oil and gas properties 1,975,141 2,218,898
Gathering systems and facilities, net of accumulated depreciation 0 315,777
Other property and equipment, net of accumulated depreciation 71,379 72,542
Net Property and Equipment 2,046,520 2,607,217
Non-Current Assets:
Commodity derivative asset 0 13,229
Other non-current assets 13,476 82,761
Total Non-Current Assets 13,476 95,990
Total Assets $ 2,370,571 $ 2,926,957
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 38,481 $ 190,864
Revenue payable 38,544 108,493
Production taxes payable 2,503 115,489
Commodity derivative liability 676 1,998
Accrued interest payable 5,369 20,625
Asset retirement obligations 0 27,058
DIP Credit Facility—Note 6 110,000 0
Credit Facility—Note 6 453,746 0
Total Current Liabilities 649,319 464,527
Non-Current Liabilities:
Credit Facility 0 470,000
Senior Notes, net of unamortized debt issuance costs 0 1,085,777
Production taxes payable 17,116 98,740
Commodity derivative liability 0 108
Other non-current liabilities 0 54,579
Asset retirement obligations 0 68,850
Total Non-Current Liabilities 17,116 1,778,054
Liabilities Subject to Compromise 2,109,446 0
Total Liabilities 2,775,881 2,242,581
Commitments and Contingencies—Note 14
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized, 185,280 issued and outstanding 189,840 175,639
Stockholders' Equity (Deficit):
Common stock, $0.01 par value; 900,000,000 share authorized; 138,370,948 and 137,657,922 issued and outstanding, respectively 1,336 1,336
Treasury stock, at cost, 38,859,078 shares (170,138) (170,138)
Additional paid-in capital 2,140,364 2,156,383
Accumulated deficit (2,566,712) (1,743,208)
Total Extraction Oil & Gas, Inc. Stockholders' Equity (Deficit) (595,150) 244,373
Noncontrolling interest 0 264,364
Total Stockholders' Equity (Deficit) (595,150) 508,737
Total Liabilities and Stockholders' Equity $ 2,370,571 $ 2,926,957

~~THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF~~


	Successor		Predecessor
	June 30, 2021		December 31, 2020
ASSETS
Current Assets:
Cash and cash equivalents	$	34,427	$	205,890
Accounts receivable, net
Trade	25,649		13,266
Oil, natural gas and NGL sales	74,786		63,429
Inventory, prepaid expenses and other	20,249		36,382
Commodity derivative asset	0		6,971
Total Current Assets	155,111		325,938
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	1,016,374		4,743,463
Unproved oil and gas properties	132,386		220,380
Wells in progress	2,129		129,058
Less: accumulated depletion, depreciation, amortization and impairment charges	(89,876)		(3,459,689)
Net oil and gas properties	1,061,013		1,633,212
Other property and equipment, net of accumulated depreciation and impairment charges	55,565		56,701
Net Property and Equipment	1,116,578		1,689,913
Non-Current Assets:
Other non-current assets	15,139		9,348
Total Non-Current Assets	15,139		9,348
Total Assets	$	1,286,828	$	2,025,199
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	97,470	$	80,082
Revenue payable	134,948		49,376
Production taxes payable	59,454		2,595
Commodity derivative liability	78,915		2,147
Accrued interest payable	795		692
Asset retirement obligations	13,976		0
DIP Credit Facility—Note 4	0		106,727
Prior Credit Facility—Note 4	0		453,747
Current tax liability	2,100		0
Total Current Liabilities	387,658		695,366
Non-Current Liabilities:
RBL Credit Facility—Note 4	90,000		0
Production taxes payable	50,945		33,627
Commodity derivative liability	3,302		0
Other non-current liabilities	14,677		0
Asset retirement obligations	74,738		0
Total Non-Current Liabilities	233,662		33,627
Liabilities Subject to Compromise	0		2,143,497
Total Liabilities	621,320		2,872,490
Commitments and Contingencies—Note 12	0		0
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized, 185,280 issued and outstanding as of December 31, 2020	0		191,754
Stockholders' Equity (Deficit):
Predecessor common stock, $0.01 par value; 900,000,000 shares authorized; 136,588,900 issued and outstanding as of December 31, 2020	—		1,336
Successor common stock, $0.01 par value; 900,000,000 shares authorized; 25,836,944 issued and outstanding as of June 30, 2021	258		—
Predecessor treasury stock, at cost, 38,859,078 shares as of December 31, 2020	0		(170,138)
Additional paid-in capital	552,152		2,140,499
Retained earnings (accumulated deficit)	113,098		(3,010,742)
Total Stockholders' Equity (Deficit)	665,508		(1,039,045)
Total Liabilities and Stockholders' Equity	$	1,286,828	$	2,025,199

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

Table of Contents

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Successor		Predecessor
	For the Three Months Ended June 30,		For the Three Months Ended June 30,
	2021		2020
Revenues:
Oil sales	$	139,110	$	36,290
Natural gas sales	39,469		16,019
NGL sales	45,048		10,820
Total Revenues	223,627		63,129
Operating Expenses:
Lease operating expense	13,736		22,984
Transportation and gathering	21,554		26,306
Production taxes	10,911		4,679
Exploration and abandonment expenses	3,586		62,661
Depletion, depreciation, amortization and accretion	50,090		82,620
Impairment of long-lived assets	170		960
General and administrative expense	10,918		25,148
Other operating expenses	5,380		13,209
Total Operating Expenses	116,345		238,567
Operating Income (Loss)	107,282		(175,438)
Other Income (Expense):
Commodity derivative loss	(75,839)		(69,301)
Reorganization items, net	0		(26,919)
Interest expense	(2,170)		(20,314)
Other income	46		38
Total Other Income (Expense)	(77,963)		(116,496)
Income (Loss) Before Income Taxes	29,319		(291,934)
Income tax expense	(4,775)		0
Net Income (Loss)	$	24,544	$	(291,934)
Net income attributable to noncontrolling interest	0		0
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	24,544		(291,934)
Adjustments to reflect Series A Preferred Stock dividends and accretion of discount	0		(5,818)
Net Income (Loss) Available to Common Shareholders, Basic and Diluted	$	24,544	$	(297,752)
Income (Loss) Per Common Share—Note 11
Basic	$	0.95	$	(2.16)
Diluted	$	0.93	$	(2.16)
Weighted Average Common Shares Outstanding
Basic	25,777		138,163
Diluted	26,429		138,163

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

Table of Contents

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(~~Debtor-In-Possession)~~In thousands, except per share data)

(Unaudited)


											Successor		Predecessor
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					For the Period from January 21 through June 30,		For the Period from January 1 through January 20,		For the Six Months Ended June 30,
		2020		2019		2020		2019			2021		2021		2020
Revenues:	Revenues:									Revenues:
Oil sales	Oil sales	$	111,072	$	151,042	$	271,581	$	501,591	Oil sales	$	239,657	$	27,137	$	160,509
Natural gas sales	Natural gas sales	24,413		16,801		62,734		74,385		Natural gas sales	156,804		7,806		38,321
NGL sales	NGL sales	22,741		9,099		50,753		44,940		NGL sales	76,607		8,099		28,013
Gathering and compression	Gathering and compression	0		0		1,473		0		Gathering and compression	0		0		1,473
Total Revenues	Total Revenues	158,226		176,942		386,541		620,916		Total Revenues	473,068		43,042		228,316
Operating Expenses:	Operating Expenses:									Operating Expenses:
Lease operating expense	Lease operating expense	12,401		22,979		65,775		68,445		Lease operating expense	24,391		2,555		53,374
Midstream operating expenses		0		0		3,935		0
Transportation and gathering	Transportation and gathering	50,166		6,922		99,258		29,142		Transportation and gathering	44,742		6,256		49,092
Production taxes	Production taxes	1,696		9,711		19,828		46,419		Production taxes	32,351		3,294		18,133
Exploration and abandonment expenses	Exploration and abandonment expenses	9,762		13,245		184,903		32,725		Exploration and abandonment expenses	4,345		316		175,141
Depletion, depreciation, amortization and accretion	Depletion, depreciation, amortization and accretion	85,306		114,996		243,977		352,134		Depletion, depreciation, amortization and accretion	88,665		16,133		158,670
Impairment of long lived assets		0		0		1,736		11,233
Gain on sale of property and equipment		0		(1,011)		0		(1,329)
Impairment of long-lived assets										Impairment of long-lived assets	170		0		1,736
General and administrative expense	General and administrative expense	11,605		27,445		47,350		85,835		General and administrative expense	18,458		2,211		35,744
Other operating expenses	Other operating expenses	9,766		0		75,549		0		Other operating expenses	9,262		1,107		69,719
Total Operating Expenses	Total Operating Expenses	180,702		194,287		742,311		624,604		Total Operating Expenses	222,384		31,872		561,609
Operating Loss		(22,476)		(17,345)		(355,770)		(3,688)
Operating Income (Loss)										Operating Income (Loss)	250,684		11,170		(333,293)
Other Income (Expense):	Other Income (Expense):									Other Income (Expense):
Commodity derivative gain (loss)	Commodity derivative gain (loss)	(9,673)		87,956		184,041		39,383		Commodity derivative gain (loss)	(104,325)		(12,586)		193,714
Loss on deconsolidation of Elevation Midstream, LLC	Loss on deconsolidation of Elevation Midstream, LLC	0		0		(73,139)		0		Loss on deconsolidation of Elevation Midstream, LLC	0		0		(73,139)
Reorganization items, net	Reorganization items, net	(501,073)		0		(527,992)		0		Reorganization items, net	0		873,908		(26,919)
Interest expense(1)		(7,388)		(23,224)		(49,059)		(54,791)
Interest expense(1)										Interest expense(1)	(5,203)		(1,534)		(41,672)
Other income	Other income	3		1,337		615		3,332		Other income	42		12		612
Total Other Income (Expense)	Total Other Income (Expense)	(518,131)		66,069		(465,534)		(12,076)		Total Other Income (Expense)	(109,486)		859,800		52,596
Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	(540,607)		48,724		(821,304)		(15,764)		Income (Loss) Before Income Taxes	141,198		870,970		(280,697)
Income tax expense	Income tax expense	0		(14,800)		(2,200)		(900)		Income tax expense	(28,100)		0		(2,200)
Net Income (Loss)	Net Income (Loss)	$	(540,607)	$	33,924	$	(823,504)	$	(16,664)	Net Income (Loss)	$	113,098	$	870,970	$	(282,897)
Net income attributable to noncontrolling interest	Net income attributable to noncontrolling interest	0		5,776		6,160		13,849		Net income attributable to noncontrolling interest	0		0		6,160
Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	(540,607)		28,148		(829,664)		(30,513)		Net Income (Loss) Attributable to Extraction Oil & Gas, Inc.	113,098		870,970		(289,057)
Adjustments to reflect Series A Preferred Stock dividends and accretion of discount	Adjustments to reflect Series A Preferred Stock dividends and accretion of discount	(1,865)		(4,403)		(14,201)		(13,079)		Adjustments to reflect Series A Preferred Stock dividends and accretion of discount	0		(418)		(12,336)
Net Income (Loss) Available to Common Shareholders, Basic and Diluted	Net Income (Loss) Available to Common Shareholders, Basic and Diluted	$	(542,472)	$	23,745	$	(843,865)	$	(43,592)	Net Income (Loss) Available to Common Shareholders, Basic and Diluted	$	113,098	$	870,552	$	(301,393)
Income (Loss) Per Common Share (Note 13)
Basic and diluted		$	(3.92)	$	0.17	$	(6.11)	$	(0.28)
Income (Loss) Per Common Share—Note 11										Income (Loss) Per Common Share—Note 11
Basic										Basic	$	4.41	$	6.37	$	(2.18)
Diluted										Diluted	$	4.31	$	6.37	$	(2.18)
Weighted Average Common Shares Outstanding	Weighted Average Common Shares Outstanding									Weighted Average Common Shares Outstanding
Basic and diluted		138,348		137,789		138,080		155,847
Basic										Basic	25,655		136,589		137,945
Diluted										Diluted	26,262		136,589		137,945

_______________

(1)Absent the automatic stay described in Note 6—8—Long-Term Debt, to the Company’s consolidated financial statements in its Annual Report on Form 10-K for the year ended December 31, 2020, interest expense for the ~~three and nine months ended September 30, 2020~~Predecessor period January 1, 2021 to January 20, 2021 would have ~~been $24.6~~included an additional $3.7 million related to 2024 and ~~$69.2 million, respectively.~~2026 Senior Notes.

~~THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF~~

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~The accompanying notes are an integral part of these condensed consolidated financial statements.

Table of Contents

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(~~Debtor-In-Possession)~~

(In thousands)

(Unaudited)

For the Nine Months Ended September 30,
2020 2019
Cash flows from operating activities:
Net loss $ (823,504) $ (16,664)
Reconciliation of net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion 243,977 352,134
Abandonment and impairment of unproved properties 179,022 26,166
Impairment of long lived assets 1,736 11,233
Gain on sale of property and equipment 0 (319)
Gain on sale of assets of unconsolidated subsidiary 0 (1,010)
Gain on repurchase of 2026 Senior Notes 0 (10,486)
Amortization of debt issuance costs 3,345 3,799
Non-cash lease expense 10,549 7,739
Non-cash reorganization items, net 13,398 0
Contract asset 12,317 22,175
Commodity derivatives gain (184,041) (39,383)
Settlements on commodity derivatives 76,992 (18,527)
Premiums paid on commodity derivatives 0 (2,852)
Earnings in unconsolidated subsidiaries (480) (1,217)
Loss on deconsolidation of Elevation Midstream, LLC 73,139 0
Distributions from unconsolidated subsidiaries 0 2,630
Deferred income tax expense 2,200 900
Stock-based compensation 4,462 39,306
Changes in current assets and liabilities:
Accounts receivable—trade (19,384) (1,395)
Accounts receivable—oil, natural gas and NGL sales 50,754 16,293
Inventory, prepaid expenses and other (26,868) 1,078
Accounts payable and accrued liabilities 62,668 (6,469)
Accrued damages for rejected and settled contracts 494,398 0
Revenue payable (6,986) (21,723)
Production taxes payable (16,311) 12,211
Accrued interest payable 16,420 (4,977)
Asset retirement expenditures (18,750) (14,081)
Net cash provided by operating activities 149,053 356,561
Cash flows from investing activities:
Oil and gas property additions (218,382) (526,187)
Sale of property and equipment 11,147 41,982
Gathering systems and facilities additions, net of cost reimbursements 4,193 (169,180)
Other property and equipment additions (3,574) (32,575)
Investment in unconsolidated subsidiaries (10,033) (22,487)
Distributions from unconsolidated subsidiary, return of capital 0 569
Sale of assets of unconsolidated subsidiary 0 1,010
Net cash used in investing activities (216,649) (706,868)
Cash flows from financing activities:
Borrowings under Credit Facility 200,500 375,000
Repayments under Credit Facility (70,000) (110,000)
Borrowings under DIP Credit Facility 35,000 0
Repurchase of 2026 Senior Notes 0 (39,325)
Repurchase of common stock 0 (137,743)
Payment of employee payroll withholding taxes (120) (1,164)
Dividends on Series A Preferred Stock 0 (8,164)
Debt issuance costs and other financing fees (1,273) (2,055)
Proceeds from issuance of Preferred Units 0 99,000
Preferred Unit issuance costs 0 (2,500)
Net cash provided by financing activities 164,107 173,049
Effect of deconsolidation of Elevation Midstream, LLC (7,728) 0
Increase (decrease) in cash and cash equivalents 88,783 (177,258)
Cash, cash equivalents at beginning of period 32,382 234,986
Cash, cash equivalents at end of the period $ 121,165 $ 57,728
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities $ 38,898 $ 158,178
Cash paid for interest $ 34,188 $ 71,878
Cash paid for reorganization items, net $ 10,454 $ 0
Accretion of beneficial conversion feature of Series A Preferred Stock $ 5,452 $ 4,915
Preferred Units commitment fees and dividends paid-in-kind $ 6,160 $ 13,849
Series A Preferred Stock dividends paid-in-kind $ 8,749 $ 0
Derivative unwinds decreasing the Credit Facility $ 96,065 $ 0
Draw on letter of credit increasing the Credit Facility $ 24,311 $ 0


	Successor		Predecessor
	For the Period from January 21 through June 30,		For the Period from January 1 through January 20,		For the Six Months Ended June 30,
	2021		2021		2020
Cash flows from operating activities:
Net income (loss)	$	113,098	$	870,970	$	(282,897)
Reconciliation of net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	88,665		16,133		158,670
Abandonment and impairment of unproved properties	2,441		0		169,559
Impairment of long-lived assets	170		0		1,736
Amortization of debt issuance costs	909		113		3,190
Non-cash lease expense	2,073		264		8,986
Non-cash reorganization items, net	0		(902,653)		13,270
Non-cash discount on rights offering	1,792		0		0
Contract asset	0		0		12,317
Commodity derivatives loss (gain)	104,325		12,586		(193,714)
Settlements on commodity derivatives	(21,168)		542		65,447
Earnings in unconsolidated subsidiaries	0		0		(480)
Loss on deconsolidation of Elevation Midstream, LLC	0		0		73,139
Deferred income tax expense	0		0		2,200
Stock-based compensation	4,945		302		2,560
Changes in current assets and liabilities:
Accounts receivable—trade	(10,455)		(598)		(16,998)
Accounts receivable—oil, natural gas and NGL sales	(10,088)		(1,269)		56,828
Inventory, prepaid expenses and other	15,164		(778)		(12,289)
Accounts payable and accrued liabilities	(71,405)		16,192		64,981
Revenue payable	7,195		18,529		(18,924)
Production taxes payable	(86,261)		(13,750)		(23,019)
Accrued interest payable	795		(692)		15,565
Current tax liability	2,100		0		0
Asset retirement expenditures	(2,526)		(545)		(16,173)
Net cash provided by operating activities	141,769		15,346		83,954
Cash flows from investing activities:
Oil and gas property additions	(55,098)		(9,120)		(193,334)
Acquired oil and gas properties	(5,491)		0		0
Sale of property and equipment	20,253		0		11,147
Gathering systems and facilities additions, net of cost reimbursements	0		0		4,193
Other property and equipment additions	(837)		0		(3,386)
Investment in unconsolidated subsidiaries	0		0		(10,033)
Net cash used in investing activities	(41,173)		(9,120)		(191,413)
Cash flows from financing activities:
Borrowings under Prior Credit Facility—Note 4	0		0		200,500
Repayments under Prior Credit Facility—Note 4	0		(453,872)		(70,000)
Borrowings under DIP Credit Facility—Note 4	0		0		15,000
Repayments under DIP Credit Facility—Note 4	0		(106,727)		0
Borrowings under RBL Credit Facility—Note 4	60,000		265,000		0
Repayments under RBL Credit Facility—Note 4	(243,746)		0		0
Proceeds from issuance of common stock	7,000		200,473		0
Payment of employee payroll withholding taxes	0		0		(120)
Debt issuance costs and other financing fees	(85)		(6,328)		(22)
Net cash provided by (used in) financing activities	(176,831)		(101,454)		145,358
Effect of deconsolidation of Elevation Midstream, LLC	0		0		(7,728)
Increase (decrease) in cash and cash equivalents	(76,235)		(95,228)		30,171
Cash, cash equivalents and restricted cash at beginning of period	110,662		205,890		32,382
Cash, cash equivalents and restricted cash at end of period	$	34,427	$	110,662	$	62,553
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities	$	32,736	$	16,320	$	64,751
Cash paid for income taxes	26,000		0		0
Cash paid for interest	3,600		2,245		26,955
Cash paid for reorganization items, net	45,600		6,545		3,787
Accretion of beneficial conversion feature of Series A Preferred Stock	0		418		3,587
Preferred Units commitment fees and dividends paid-in-kind	0		0		6,160
Series A Preferred Stock dividends paid-in-kind	0		0		8,749
Derivative unwinds reducing the Prior Credit Facility	0		0		96,065
Draw on letter of credit increasing the RBL Credit Facility	8,746		0		0
Draw on letter of credit increasing the Prior Credit Facility	0		125		0
General unsecured claims within accounts payable and accrued liabilities settled with common stock	13,818		0		0
Backstop Commitment Agreement premium within accounts payable and accrued liabilities settled with common stock	0		23,866		0

~~THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF~~

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~The accompanying notes are an integral part of these condensed consolidated financial statements.

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EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY AND NONCONTROLLING INTEREST

(~~Debtor-In-Possession)~~

(In thousands)

(Unaudited)

Common Stock Treasury Stock Additional Paid in Capital Accumulated Deficit Extraction Oil & Gas, Inc. Stockholders' Equity (Deficit) Noncontrolling Interest Total Stockholders' Equity (Deficit)
Shares Amount Shares Amount Amount
Balance at January 1, 2020 176,517 $ 1,336 38,859 $ (170,138) $ 2,156,383 $ (1,743,208) $ 244,373 $ 264,364 $ 508,737
Preferred Units commitment fees & dividends paid-in-kind — — — — (6,160) — (6,160) 6,160 —
Series A Preferred Stock dividends — — — — (4,748) — (4,748) — (4,748)
Accretion of beneficial conversion feature on Series A Preferred Stock — — — — (1,770) — (1,770) — (1,770)
Restricted stock issued, net of tax withholdings and other 234 — — — (35) — (35) — (35)
Net income — — — — — 9,037 9,037 — 9,037
Effects of deconsolidation of Elevation Midstream, LLC — — — — — — — (270,524) (270,524)
Balance at March 31, 2020 176,751 $ 1,336 38,859 $ (170,138) $ 2,143,670 $ (1,734,171) $ 240,697 $ 0 $ 240,697
Stock-based compensation — — — — 2,560 — 2,560 — 2,560
Series A Preferred Stock dividends — — — — (4,001) — (4,001) — (4,001)
Accretion of beneficial conversion feature on Series A Preferred Stock — — — — (1,817) — (1,817) — (1,817)
Restricted stock issued, net of tax withholdings and other 452 — — — (85) — (85) — (85)
Net loss — — — — — (291,934) (291,934) — (291,934)
Balance at June 30, 2020 177,203 $ 1,336 38,859 $ (170,138) $ 2,140,327 $ (2,026,105) $ (54,580) $ 0 $ (54,580)
Stock-based compensation — — — — 1,902 — 1,902 — 1,902
Accretion of beneficial conversion feature on Series A Preferred Stock — — — — (1,865) — (1,865) — (1,865)
Restricted stock issued, net of tax withholdings and other 27 — — — 0 — 0 — 0
Net loss — — — — — (540,607) (540,607) — (540,607)
Balance at September 30, 2020 177,230 $ 1,336 38,859 $ (170,138) $ 2,140,364 $ (2,566,712) $ (595,150) $ 0 $ (595,150)


	Common Stock			Treasury Stock			Additional Paid in Capital		Retained Earnings (Accumulated Deficit)		Extraction Oil & Gas, Inc. Stockholders' Equity (Deficit)		Noncontrolling Interest		Total Stockholders' Equity (Deficit)
	Shares	Amount		Shares	Amount								Amount
Balance at January 1, 2021 (Predecessor)	175,448	$	1,336	38,859	$	(170,138)	$	2,140,499	$	(3,010,742)	$	(1,039,045)	$	0	$	(1,039,045)
Stock-based compensation	—	—		—	—		302		—		302		—		302
Accretion of beneficial conversion feature on Series A Preferred Stock	—	—		—	—		(418)		—		(418)		—		(418)
Net income	—	—		—	—		—		870,970		870,970		—		870,970
Cancellation of Predecessor equity	(175,448)	(1,336)		(38,859)	170,138		(2,140,383)		2,139,772		168,191		—		168,191
Issuance of Successor equity	24,729	247		—	—		504,205		—		504,452		—		504,452
Issuance of Successor warrants	—	—		—	—		20,403		—		20,403		—		20,403
Balance at January 20, 2021 (Predecessor)	24,729	$	247	0	$	0	$	524,608	$	0	$	524,855	$	0	$	524,855


Balance at January 21, 2021 (Successor)	24,729	$	247	0	$	0	$	524,608	$	0	$	524,855	$	0	$	524,855
Stock-based compensation	—	—		—	—		2,174		—		2,174		—		2,174
Net income	—	—		—	—		—		88,554		88,554		—		88,554
Issuance of Successor equity for general unsecured claims	543	5		—	—		11,083		—		11,088		—		11,088
Issuance of Successor equity for rights offering	431	5		—	—		8,787		—		8,792		—		8,792
Balance at March 31, 2021 (Successor)	25,703	$	257	0	$	0	$	546,652	$	88,554	$	635,463	$	0	$	635,463
Stock-based compensation	—	—		—	—		2,771		—		2,771		—		2,771
Net income	—	—		—	—		—		24,544		24,544		—		24,544
Issuance of Successor equity for general unsecured claims	134	1		—	—		2,729		—		2,730		—		2,730
Balance at June 30, 2021 (Successor)	25,837	$	258	0	$	0	$	552,152	$	113,098	$	665,508	$	0	$	665,508

~~THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF~~

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Table of Contents~~


Balance at January 1, 2020 (Predecessor)																				Balance at January 1, 2020 (Predecessor)		176,517			$	1,336	38,859	$	(170,138)	$	2,156,383	$	(1,743,208)	$	244,373	$	264,364	$	508,737
Preferred Units commitment fees & dividends paid-in-kind																				Preferred Units commitment fees & dividends paid-in-kind		—			—		—	—		(6,160)		—		(6,160)		6,160		—
Series A Preferred Stock dividends																				Series A Preferred Stock dividends		—			—		—	—		(4,748)		—		(4,748)		—		(4,748)
Accretion of beneficial conversion feature on Series A Preferred Stock																				Accretion of beneficial conversion feature on Series A Preferred Stock		—			—		—	—		(1,770)		—		(1,770)		—		(1,770)
Restricted stock issued, net of tax withholdings and other																				Restricted stock issued, net of tax withholdings and other		234			—		—	—		(35)		—		(35)		—		(35)
Net income																				Net income		—			—		—	—		—		9,037		9,037		—		9,037
Effects of deconsolidation of Elevation Midstream, LLC																				Effects of deconsolidation of Elevation Midstream, LLC		—			—		—	—		—		—		—		(270,524)		(270,524)
Balance at March 31, 2020 (Predecessor)																				Balance at March 31, 2020 (Predecessor)		176,751			$	1,336	38,859	$	(170,138)	$	2,143,670	$	(1,734,171)	$	240,697	$	0	$	240,697
Stock-based compensation																				Stock-based compensation		—			—		—	—		2,560		—		2,560		—		2,560
Series A Preferred Stock dividends																				Series A Preferred Stock dividends		—			—		—	—		(4,001)		—		(4,001)		—		(4,001)
Accretion of beneficial conversion feature on Series A Preferred Stock																				Accretion of beneficial conversion feature on Series A Preferred Stock		—			—		—	—		(1,817)		—		(1,817)		—		(1,817)
Restricted stock issued, net of tax withholdings and other																				Restricted stock issued, net of tax withholdings and other		452			—		—	—		(85)		—		(85)		—		(85)
Net loss																				Net loss		—			—		—	—		—		(291,934)		(291,934)		—		(291,934)
Balance at June 30, 2020 (Predecessor)																				Balance at June 30, 2020 (Predecessor)		177,203			$	1,336	38,859	$	(170,138)	$	2,140,327	$	(2,026,105)	$	(54,580)	$	0	$	(54,580)

	Common Stock			Treasury Stock			Additional Paid in Capital				Accumulated Deficit			Extraction Oil & Gas, Inc. Stockholders' Equity		Noncontrolling Interest		Total Stockholders' Equity
	Shares	Amount		Shares	Amount								Amount
Balance at January 1, 2019	176,210	$	1,678	4,543	$	(32,737)			$	2,153,661				$	(375,788)	$	1,746,814			$	147,872		$	1,894,686
Preferred Units issuance costs	—	—		—	—		—				—			—		(10)		(10)
Preferred Units commitment fees & dividends paid-in-kind	—	—		—	—		(3,975)				—			(3,975)		3,975		0
Stock-based compensation	0	—		—	—		13,008				—			13,008		—		13,008
Series A Preferred Stock dividends	—	—		—	—		(2,721)				—			(2,721)		—		(2,721)
Accretion of beneficial conversion feature on Series A Preferred Stock	—	—		—	—		(1,596)				—			(1,596)		—		(1,596)
Repurchase of common stock	—	(77)		7,824	(32,135)		—				—			(32,212)		—		(32,212)
Restricted stock issued, net of tax withholdings	270	—		—	—		(454)				—			(454)		—		(454)
Net loss	—	—		—	—		0				(94,032)			(94,032)		—		(94,032)
Balance at March 31, 2019	176,480	$	1,601	12,367	$	(64,872)	$	2,157,923			$	(469,820)		$	1,624,832	$	151,837	$	1,776,669
Preferred Units issuance costs and discount	—	—		—	—		—				—			—		10		10
Preferred Units commitment fees & dividends paid-in-kind	—	—		—	—		(4,098)				—			(4,098)		4,098		0
Stock-based compensation	0	—		—	—		14,957				—			14,957		—		14,957
Series A Preferred Stock dividends	—	—		—	—		(2,722)				—			(2,722)		—		(2,722)
Accretion of beneficial conversion feature on Series A Preferred Stock	—	—		—	—		(1,637)				—			(1,637)		—		(1,637)
Repurchase of common stock	—	(217)		21,685	(84,067)		—				—			(84,284)		—		(84,284)
Restricted stock issued, net of tax withholdings	108	—		—	—		(128)				—			(128)		—		(128)
Net income	—	—		—	—		—				43,444			43,444		—		43,444
Balance at June 30, 2019	176,588	$	1,384	34,052	$	(148,939)	$	2,164,295			$	(426,376)		$	1,590,364	$	155,945	$	1,746,309
Preferred Units issued	—	—		—	—		—				—			—		99,000		99,000
Preferred Units issuance costs	—	—		—	—		—				—			—		(2,500)		(2,500)
Preferred Units commitment fees & dividends paid-in-kind	—	—		—	—		(5,776)				—			(5,776)		5,776		0
Stock-based compensation	—	—		—	—		11,387				—			11,387		—		11,387
Series A Preferred Stock dividends	—	—		—	—		(2,721)				—			(2,721)		—		(2,721)
Accretion of beneficial conversion feature on Series A Preferred Stock	—	—		—	—		(1,682)				—			(1,682)		—		(1,682)
Repurchase of common stock	—	(48)		4,807	(21,199)		—				—			(21,247)		—		(21,247)
Restricted stock issued, net of tax withholdings	344	—		—	—		(582)				—			(582)		—		(582)
Net income	—	—		—	—		—				33,924			33,924		—		33,924
Balance at September 30, 2019	176,932	$	1,336	38,859	$	(170,138)	$	2,164,921			$	(392,452)		$	1,603,667	$	258,221	$	1,861,888

~~THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF~~

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~The accompanying notes are an integral part of these condensed consolidated financial statements.

Table of Contents

EXTRACTION OIL & GAS, INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~(DEBTOR-IN-POSSESSION)~~

Note 1—Business and Organization

Extraction Oil & Gas, Inc. (the ~~"Company"~~“Company” or ~~"Extraction")~~“Extraction” is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and natural gas liquids (“NGLs”) reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the ~~"DJ Basin"~~“DJ Basin”) of ~~Colorado, as well as the construction and support of midstream assets to gather crude oil, natural gas and water production.~~Colorado. As described below in the section titled “Voluntary Reorganization under Chapter 11 of the Bankruptcy Code ~~below,~~,” during the second quarter of 2020, the Company filed for bankruptcy and, as a result, was delisted from the NASDAQ Global Select Market on June 25, 2020 and began trading on the Pink Open Market under the symbol ~~"XOGAQ."~~“XOGAQ.” Also described below, on January 20, 2021 the Company emerged from bankruptcy as a reorganized entity and, as a result, was relisted on the NASDAQ Global Select Market on January 21, 2021 and began trading under the symbol “XOG.”

To facilitate our financial statement presentations, the Company refers to the post-emergence reorganized company in these condensed consolidated financial statements and footnotes as the “Successor Company” for periods subsequent to January 20, 2021 and to the pre-emergence company as the “Predecessor Company” for periods on or prior to January 20, 2021. This delineation between Predecessor Company periods and Successor Company periods is shown in the condensed consolidated financial statements, certain tables within the footnotes to the condensed consolidated financial statements and other parts of this Quarterly Report on Form 10-Q (“Quarterly Report”) through the use of a black line, calling out the lack of comparability between periods.

Bonanza Creek Energy, Inc. Merger and Crestone Peak Merger

As previously disclosed, on May 9, 2021, Bonanza Creek Energy, Inc. (“Bonanza Creek”) and Extraction signed a merger agreement (the “BCEI Merger Agreement”) for an all-stock merger of equals (the “BCEI Merger”). On June 6, 2021, Extraction entered into a merger agreement, by and among Bonanza Creek, Raptor Condor Merger Sub 1, Inc., a Delaware corporation and a wholly owned subsidiary of BCEI, Raptor Condor Merger Sub 2, LLC, a Delaware limited liability company and a wholly owned subsidiary of BCEI, Crestone Peak Resources LP, a Delaware limited partnership, CPPIB Crestone Peak Resources America Inc., a Delaware corporation (“Crestone Peak”), Crestone Peak Resources Management LP, a Delaware limited partnership (the “Crestone Peak Merger Agreement”). The Crestone Peak Merger Agreement, among other things, provides for Bonanza Creek’s acquisition of Crestone Peak (the “Crestone Peak Merger”). The closing of the Crestone Peak Merger is expressly conditioned on the closing of the BCEI Merger. Upon completion of the BCEI Merger and Crestone Peak Merger, the combined company will be named Civitas Resources, Inc. (“Civitas”). Following the BCEI Merger and Crestone Peak Merger, Bonanza Creek President and Chief Executive Officer, Eric Greager, will serve as President and CEO of Civitas. Other senior leadership positions will be filled by current executives of Bonanza Creek and Extraction. As designated in the BCEI Merger agreement, of the six named officers, three will be from Bonanza Creek and three from Extraction. Extraction Chairman of the Board of Directors (“Board”), Ben Dell, will serve as Chairman of Civitas, and Bonanza Creek and Extraction will each nominate four directors, and CPP Investments will nominate one director to Civitas’ diverse, nine-member Board. The Company anticipates the BCEI Merger will be completed during the latter half of 2021.

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

As previously disclosed, on June 14, 2020 (the “Petition Date”), Extraction and its wholly owned subsidiaries (collectively, the “Debtors”), filed voluntary petitions for relief under chapter 11 ("(“Chapter ~~11"~~11”) of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The ~~Debtor's~~Debtors’ Chapter 11 cases (the “Chapter 11 Cases”) ~~are being~~were jointly administered under the caption In In re Extraction Oil & Gas., et al. Case No. 20-11548 (CSS).

The Debtors continue to operate their businesses and manage their properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Debtors continue to operate as an ongoing business in accordance with the previously approved Bankruptcy Court orders.

~~The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement (as defined in~~ ~~Note 6—Long-Term Debt~~) and the indentures governing the Company’s Senior Notes (as defined below), resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding under the Credit Agreement and Senior Notes. Accordingly, the Company has classified its outstanding Senior Notes debt as liabilities subject to compromise on its condensed consolidated balance sheet as of September 30, 2020. The Credit Facility (as defined in ~~Note 6—Long-Term Debt) was not classified as liabilities subject to compromise because it is fully secured and is expected to be unimpaired. Please refer to~~ ~~Note 4—Liabilities Subject to Compromise~~ ~~for more information. Pursuant to the Bankruptcy Code and as described in~~ ~~Note 6—Long-Term Debt~~, the filing of the Chapter 11 Cases automatically stayed most actions against the Debtors, including most actions to collect indebtedness incurred prior to the Petition Date or to exercise control over the Debtors’ property.

~~Restructuring Support Agreement~~

As previously disclosed, on June 14, 2020, the Company entered into a Restructuring Support Agreement (the “RSA”) with (i) significant holders of its 7.375% senior unsecured notes due 2024 (the “2024 Senior Notes”) issued pursuant to that certain indenture, dated as of August 1, 2017, by and among Extraction, as issuer, certain guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee (such trustee, “WSFS” and such indenture, the “2024 Senior Notes Indenture”) and (ii) significant holders (such holders, together with the foregoing significant holders under the 2024 Senior Notes, the “Consenting Stakeholders”) of its 5.625% senior unsecured notes due 2026 (the “2026 Senior Notes” and, together with the 2024 Senior Notes, the “Senior Notes”) issued pursuant to that certain indenture, dated as of January 25, 2018, by and among Extraction, the subsidiary guarantors party thereto and WSFS, as trustee (the “2026 Senior Notes Indenture” and, together with the 2024 Senior Notes Indenture, the “Senior Notes Indentures”). The RSA contemplates a financial restructuring of the existing indebtedness of, and equity interests in, the Company to be effectuated through a joint Chapter 11 plan of reorganization (as amended or modified, the “Restructuring Plan”).

~~Restructuring Plan, Disclosure Statement, and Backstop Commitment Agreement~~

On July 30, 2020, the Debtors filed a proposed ~~Restructuring~~ Plan of Reorganization (as amended, modified, or supplemented from time to time, the “Plan”) and related Disclosure Statement (as amended or modified, the “Disclosure Statement”) describing the ~~Restructuring~~ Plan and the solicitation of votes to approve the same from certain of the Debtors’ creditors with respect to the Chapter 11 ~~Cases (as amended or modified, the “Disclosure Statement”).~~Cases. Subsequently on October 22,

~~Table of Contents~~

2020 and November 5, 2020, the Debtors filed first and second amendments, respectively, to the Disclosure Statement. The hearing to consider approval of the Disclosure Statement

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was held on November 6, 2020. On November 6, 2020, the Bankruptcy Court approved the adequacy of the Disclosure Statement and the Debtors commenced a solicitation process to ~~receive~~obtain votes on the ~~Restructuring~~ Plan. ~~Pursuant to the terms~~The Plan was confirmed by order of the Restructuring Plan and as described in the Disclosure Statement, the Debtors will also commence a rights offering, which has been backstopped by certain holders of the Senior Notes. On November 6, 2020, the Bankruptcy Court ~~approved~~on December 23, 2020 (the “Confirmation Order”). On January 20, 2021 (the “Emergence Date”), the ~~Backstop Commitment Agreement, which provides a commitment of $200 million. The hearing on the confirmation of the Restructuring~~ Plan ~~has been scheduled to be held on or before December 21, 2020.~~

~~The Restructuring Plan contemplates, among other things, the following:~~

•holders of claims under the Amended and Restated Credit Agreement, dated as of August 16, 2017, by and among Extraction, the subsidiary guarantors party thereto, the lenders from time to time thereto, and Wells Fargo Bank, National Association, as administrative agent (as may be amended, restated, supplemented, or otherwise modified from time to time, the “Credit Agreement”), except to the extent that a Holder of an Allowed Revolving Credit Agreement Claim and the Debtors against which such Allowed Revolving Credit Agreement Claim is asserted agree to a less favorable treatment for such Holder, in full and final satisfaction, settlement, release, and discharge of and in exchange for each Allowed Revolving Credit Agreement Claim, each Holder of such Allowed Revolving Credit Agreement Claim shall receive, either:

◦(i) if such Holder elects to participate in the Exit RBL Facility on a pro rata basis, determined on a ratable basis with respect to its percentage of the Obligations (as defined in the Revolving Credit Agreement) under the Revolving Credit Agreement, such Holder of an Allowed Revolving Credit Agreement Claim shall become an Exit RBL Facility Lenderbecame effective in accordance with ~~the~~its terms ~~of the Exit RBL Facility Documents; or~~

◦(ii) if such Holder does not elect to participate in the Exit RBL Facility as provided above (including by not making any election with respect to the Exit RBL Facility on the ballot), its Pro Rata Share of the Exit Term Loans.

•holders of claims under the Senior Notes Indentures (“Senior Notes Claims”) shall receive, in full and final satisfaction, compromise, settlement, release, and discharge of, and in exchange for such Allowed Senior Notes Claim, its Pro Rata share of (A) the Claims Equity Allocation and (B) the Senior Noteholder Subscription Rights;

•holders of trade claims shall receive, in full and final satisfaction, compromise, settlement, release, and discharge of, and in exchange for such Allowed Trade Claim, payment in full of such Allowed Trade Claim on the Effective Date or otherwise in the ordinary course of the Debtors’ business;

•holders of claims arising from non-funded debt general unsecured obligations shall receive, in full and final satisfaction, compromise, settlement, release, and discharge of, and in exchange for such Allowed General Unsecured Claim, its Pro Rata share of the Claims Equity Allocation;

•each Existing Preferred Interest in the Company shall be canceled, released, and extinguished, and will be of no further force or effect, and each Holder of an Allowed Existing Preferred Interest shall receive, in full and final satisfaction, compromise, settlement, release, and discharge of, and in exchange for such Existing Preferred Interest, its Pro Rata share of (A) 50% of the Existing Interests Equity Allocation, (B) the Existing Preferred Interest Subscription Rights, (C) 50% of the Tranche A Warrants, and (D) 50% of the Tranche B Warrants;

•each Existing Common Interest in the Company shall be canceled, released, and extinguished, and will be of no further force or effect, and each Holder of an Allowed Existing Common Interest shall receive, in full and final satisfaction, compromise, settlement, release, and discharge of, and in exchange for such Existing Common Interest its Pro Rata share of (A) 50% of the Existing Interests Equity Allocation, (B) the Existing Common Interest Subscription Rights, (C) 50% of the Tranche A Warrants, and (D) 50% of the Tranche B Warrants;

•~~holders of claims arising from the DIP Credit Facility (as defined in~~ ~~Note 6—Long-Term Debt) receiving cash or such other consideration as the DIP Lenders (as defined in~~ ~~Note 6—Long-Term Debt) agree in their sole discretion;~~

•cash payment in full of all administrative expense claims, priority tax claims, other priority claims, and other secured claims or other such treatment rendering such claims unimpaired, including reinstatement pursuant to section 1124 of the Bankruptcy Code or delivery of the collateral securing any such secured claim and payment of any interest required under section 506(b) of the Bankruptcy Code; and

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•the Restructuring Plan will provide for the establishment of a post-emergence management incentive plan to be adopted by the New Board (the “Management Incentive Plan”), which may include (a) restricted stock units, options, New Common Shares, or other rights exercisable, exchangeable, or convertible into New Common Shares representing up to 10% of the New Common Shares on a fully diluted and fully distributed basis (the “MIP Equity”) and (b) other terms and conditions customary for similar type equity plans.

Information contained in the Restructuring Plan and the Disclosure Statement is subject to change, whether as a result of amendments or supplements to the Restructuring Plan or Disclosure Statement, third-party actions, or otherwise, and should not be relied upon by any party. There is no guarantee the Restructuring Plan can be implemented and the Restructuring Plan approved.

The information presented in this section is not a solicitation to accept or reject the Restructuring Plan. Any such solicitation will be made pursuant to and in accordance with the Disclosure Statement and applicable law, including orders of the Bankruptcy Court. Capitalized terms used but not specifically defined in this section have the meanings specified for such terms in the Restructuring Plan and Disclosure Statement, as applicable.

~~Tax Attributes and Net Operating Loss Carryforwards~~

The Company has substantial tax net operating loss carryforwards and other tax attributes. Under the U.S. Internal Revenue Code of 1986, as amended (the “Code”), our ability to use these net operating losses and other tax attributes may be limited if the Company experiences an “ownership change”, as determined under Section 382 of the Code. Accordingly, on July 13, 2020, the Company obtained a final order from the Bankruptcy Court that is intended to prevent an ownership change during the pendency of the Chapter 11 Cases and therefore protect the Company's ability to use its tax attributes by imposing certain notice procedures and transfer restrictions on the trading of the Company’s existing common stock and preferred stock.

In general, the order applies to any person or entity that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of the Company’s common stock or preferred stock. Such persons are required to notify the Company and the Bankruptcy Court before effecting a transaction involving the Company's common stock or preferred stock, and the Company has the right to seek an injunction to prevent the transaction if it might adversely affect the Company's ability to use its tax attributes. The order also requires any person or entity that, directly or indirectly, beneficially owns at least 50% of the Company’s common stock or preferred stock to notify the Company and the Bankruptcy Court prior to claiming any deduction for worthlessness of the Company's common stock or preferred stock for a tax year ending before the Company’s emergence from chapter 11 protection and the Company has the right to seek an injunction to prevent the transaction if it might adversely affect the Company's ability to use its tax attributes.

Any purchase, sale or other transfer of, or any claim of a deduction for worthlessness with respect to, the Company's common stock or preferred stock in violation of the restrictions of the order is null and void ab initio as an act in violation of a Bankruptcy Court order and would therefore confer no rights on a proposed transferee or such holder, as applicable.

~~Ability to Continue as a Going Concern~~

The condensed 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 condensed consolidated financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern.

As discussed above, the filing of the Chapter 11 Cases constituted an event of default under the Company’s outstanding debt agreements, which resulted in the automatic and immediate acceleration of all of the Company’s debt outstanding under the Credit Agreement and Senior Notes. The Company projects that it will not have sufficient cash on hand or available liquidity to repay such debt. These conditions and events raise substantial doubt about the Company’s ability to continue as a going concern.

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The Company’s ability to continue as a going concern is contingent upon, among other things, its ability to, subject to the Bankruptcy Court’s approval, implement the Restructuring Plan, successfully emergeemerged from the Chapter 11 Cases and generate sufficient liquidity from the Restructuring to meet its obligations and operating needs. As a result of risks and uncertainties related to (i) the Company’s ability to obtain requisite support for the Restructuring Plan from various stakeholders, and (ii) the effects of disruption from the Chapter 11 Cases making it more difficult to maintain business, financing and operational relationships, the Company has concluded that management’s plans do not alleviate substantial doubt regarding the Company’s ability to continue as a going concern.

The condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.

~~Deconsolidation of Elevation Midstream, LLC~~

Elevation Midstream, LLC ("Elevation"), a Delaware limited liability company, is focused on the construction and operation of gathering systems and facilities to serve the development of acreage in the Company’s Hawkeye and Southwest Wattenberg areas. Midstream assets of Elevation are represented as the gathering systems and facilities line item within the condensed consolidated balance sheets for any periods ended on or prior to December 31, 2019.

During the first quarter of 2020, Elevation's then non-controlling interest owner, which owned 100% of Elevation's preferred stock, per contractual agreement, expanded Elevation's then five member board of managers by four seats and filled them with managers of their choosing (the "Board Expansion"). Because Extraction had the right to appoint only three of the managers of Elevation before and after Board Expansion, Extraction determined the Company had lost voting control of Elevation, and on March 16, 2020 deconsolidated Elevation and began accounting for the entity as an equity method investment. Though Extraction determined control of Elevation was lost under the voting interest model of consolidation, the Company also determined significant influence was not lost due to (1) Extraction owning 100% of the common stock, (2) Extraction appointing three of the nine managers of Elevation and (3) Extraction's continuing involvement in the day-to-day operation of Elevation through a management services agreement. Because Extraction also determined the Company is not the primary beneficiary, Elevation Midstream, LLC is not a variable interest entity.

Extraction elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of the investment in the condensed consolidated statements of operations for the three months ended March 31, 2020. Also during the three months ended March 31, 2020, Elevation determined certain gathering systems and facilities were impaired by $50.3 million as a result of the abandonment of certain projects. In accordance with Accounting Standards Codification ("ASC") ~~Topic 323-10-35-20: Investments—equity method and joint ventures, Extraction discontinued applying the equity method investment for Elevation as the impairment charge would have reduced the investment below zero.~~

On May 1, 2020, Elevation's board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation's members other than Extraction (the "Capital Raise"). The Capital Raise caused Extraction's ownership of Elevation to be diluted to less than 0.01%. As a result of the Capital Raise, beginning in May 2020 Extraction began accounting for Elevation under the cost method of accounting. The Company reserves all rights related to actions taken by Elevation’s board of managers.Cases.

Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements

Basis of Presentation

The unaudited condensed consolidated financial statements include the accounts of the Company, including its wholly owned subsidiaries. ~~All significant intercompany~~Intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the Securities and Exchange Commission rules and ~~regulation~~regulations for interim financial reporting. In the opinion of management, all adjustments, consisting primarily of normal recurring ~~accruals~~adjustments that are considered necessary for a fair statement of the

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unaudited condensed consolidated financial information, have been included. However, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year. Interim condensed consolidated financial statements and the year-end balance sheets do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 (“Annual Report”).

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 22—Basis of Presentation and Significant Accounting Policies to the Company’s consolidated financial statements in its Annual Report and are supplemented by the notes to the unaudited condensed consolidated financial statements in this ~~report.~~Quarterly Report. As discussed in Note 3—Fresh Start Reporting, upon emergence from bankruptcy on January 20, 2021, the Company recorded its consolidated balance sheet accounts at fair value.

~~Beginning after the Petition Date, the~~The Predecessor Company ~~has~~ applied ~~ASC~~Accounting Standards Codification (“ASC”) Topic ~~852 —~~ 852—Reorganizations(“ASC 852”) in preparing the condensed consolidated financial statements. ASC 852 did not apply to the Successor Company. ASC 852 requires the financial statements, for periods subsequent to the Chapter 11 ~~Cases'~~Cases’ filing date, to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses incurred during the bankruptcy proceedings, including ~~unamortized~~gain on settlement of debt ~~issuance costs associated with debt classified as liabilities subject to compromise,~~and fresh-start valuations, are recorded as reorganization ~~items.~~items, net. In addition, for periods after the Petition Date and through the Emergence Date, Predecessor Company pre-petition obligations that may behave been impacted by the ~~chapter~~Chapter 11 process have been classified on the condensed consolidated balance sheets as ~~liabilities subject~~“Liabilities Subject to ~~compromise.~~Compromise.” These liabilities are reported at the amounts the Predecessor Company ~~anticipates will~~anticipated would be allowed by the Bankruptcy Court as of that balance sheet date, even if they may be settled for lesser amounts. See below for more information regarding reorganization ~~items.~~items, net.

GAAP requires certain additional reporting for financial statements prepared between the Petition Date and the ~~date that the Company emerges from bankruptcy,~~Emergence Date, including:

•Reclassification of pre-petition liabilities that are unsecured, under-secured or where it cannot be determined that the liabilities are fully secured to a separate line item in the condensed consolidated balance sheets called ~~liabilities subject~~“Liabilities Subject to ~~compromise;~~Compromise”; and

•Segregation of reorganization items, net as a separate line in the condensed consolidated statements of operations outside of income from continuing operations.

~~Debtor-In-Possession~~

~~The Debtors~~Accounting policies for the balance sheet accounts listed below are ~~currently operating as debtors~~disclosed in ~~possession in accordance with~~ the ~~applicable provisions~~Company’s Annual Report. As of the ~~Bankruptcy Code. The Bankruptcy Court has approved motions filed by~~Effective Date, the ~~Debtors that were designed primarily to mitigate~~amounts for these accounts have been recorded at fair value. After the ~~impact of the Chapter 11 Cases on the Company’s operations, customers and employees. As a result,~~effective date, the Company ~~is able~~will continue to ~~conduct normal business activities and pay all associated obligations for~~follow the ~~period following~~accounting policies within its bankruptcy filing in the ordinary course of business and is authorized to pay and has paid certain pre-petition obligations, including, among other things, for employee wages and benefits and certain goods and services provided. During the Chapter 11 Cases, transactions outside the ordinary course of business require prior approval of the Bankruptcy Court.

~~Automatic Stay~~

Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 Cases automatically stayed most judicial or administrative actions against the Debtors and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code.

Annual Report.

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•Cash and Cash Equivalents

•Accounts Receivable

•Inventory, Prepaid Expenses and Other

•Oil and Gas Properties

•Other Property and Equipment

•Debt Issuance Costs

•Commodity Derivative Instruments

•Intangible Assets

•Asset Retirement Obligations

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors 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 the Debtors from performing their 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. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance.

~~Potential~~Bankruptcy Claims

The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of each of the Debtors, subject to the assumptions filed in connection therewith. These schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by the bar date of August 14, 2020. As of ~~November 2, 2020,~~August 3, 2021, the ~~Debtors'~~Debtors’ have received approximately ~~2,545~~2,600 proofs of claim, primarily representing general unsecured claims, for an amount of approximately ~~$6.7~~$5.8 billion. ~~These~~The Bankruptcy Court does not allow for claims ~~will~~that have been acknowledged as duplicates. Approximately 2,200 claims totaling approximately $4.2 billion have been withdrawn, disallowed or are pending approval to be ~~reconciled to amounts recorded~~disallowed. As of August 3, 2021, there are a total of approximately $75.1 million in ~~liabilities subject to compromise~~remaining asserted claims in the ~~condensed consolidated balance sheet.~~bankruptcy. For the remaining claims, the Company is attempting to reach settlement with the claimants or has or is expected to object to the claims. Differences in amounts recorded and claims filed by creditors ~~will be~~are currently being investigated and resolved, including through ~~the~~ filing of objections with the Bankruptcy Court, where appropriate. The Company may ask the Bankruptcy Court to disallow claims that the Company believes are duplicative, have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. In ~~addition, as a result of this process, the Company may identify additional liabilities that will need to be recorded or reclassified to liabilities subject to compromise. In~~ light of the substantial number of claims ~~filed, and expected to be~~ filed, the claims resolution process may take considerable time to complete and ~~likely will continue~~is continuing even after the Debtors ~~emerge~~emerged from bankruptcy.

~~Financial Statement Classification of Liabilities Subject to Compromise~~

The accompanying condensed consolidated balance sheets as of September 30, 2020 includes amounts classified as liabilities subject to compromise, which represent liabilities the Company anticipates will be allowed as claims in the Chapter 11 Cases. These amounts represent the Debtors’ current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the chapter 11 process and adjust amounts as necessary. Such adjustments may be material. Please refer to ~~Note 4~~—~~Liabilities Subject to Compromise~~ ~~for more information.~~

~~Reorganization Items, Net~~

The Debtors, have incurred and will continue to incur significant costs associated with the reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. The amount of these costs, which since the Petition Date, are being expensed as incurred, are expected to significantly affect the Company’s results of operations. In accordance with applicable guidance, costs associated with the bankruptcy proceedings have been recorded as reorganization items within the Company's accompanying condensed consolidated statements of operations for the three and nine months ended September 30, 2020. Please refer to ~~Note 5—Reorganization Items, Net~~ ~~for more information.~~

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~~Revenue~~ — ~~Contract Balances~~

The Company had a certain revenue contract with an initial term beginning on November 1, 2016 and continuing until October 31, 2020 after which the contract was to begin an automatic month-to-month renewal unless terminated by either party giving notice at least six months prior to the effective termination date but in no event could either party give such notice earlier than November 1, 2020. Based on the accounting treatment pursuant to ~~ASC 606 — Revenue from Contracts with Customers~~, the contract term would end on April 30, 2021 because it could be terminated by either party with no penalty effective as of such date. The contract term impacted the amount of consideration that could be included in the transaction price. The Company recognizes revenue and invoices customers once its performance obligations have been satisfied. When it becomes probable that the Company will not meet its performance obligations, the transaction price allocated to the performance obligation is constrained in the amount of the estimated unmet performance obligation and recognized as a reduction to revenue in the period in which the transaction price changes. On June 12, 2020, the Company and the counterparty to the contract mutually cancelled the contract effective June 30, 2020. As a result of the cancellation, for the three months ended September 30, 2020, 0 revenue was recorded as a reduction in the transaction price resulting from unsatisfied performance obligations in the period. For the nine months ended September 30, 2020, $12.3 million was recorded as a reduction in the transaction price resulting from unsatisfied performance obligations in the period. For the three and nine months ended September 30, 2019, the Company allocated $22.2 million to a satisfied performance obligation recognized within oil sales. As a result of the contract termination, the Company incurred an early termination fee of $13.2 million recorded in other operating expenses for the nine months ended September 30, 2020. This amount was settled during the third quarter of 2020, and there are no remaining amounts due to the counterparty.

~~Other Operating Expenses~~

Other operating expenses were $9.8 million and $75.5 million for the three and nine months ended September 30, 2020, respectively. There were no other operating expenses for the three and nine months ended September 30, 2019. The amounts in the current year are made up of the following:

•$46.8 million loss contingency from an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. Please see ~~Note 14—Commitments and Contingencies~~ ~~for further details.~~

•~~$2.9 million of accrued interest related to the aforementioned alleged breach in contract recorded in the third quarter of 2020.~~

•~~$13.2 million early termination penalty for the revenue contract terminated in June 2020. Please see the section~~ ~~Revenue~~ — ~~Contract Balance~~ ~~immediately above for further details.~~

•~~$7.5 million charge to income for expenses related to workforce reductions in February and May 2020.~~

•~~$2.4 million charge to income for expenses related to certain drilling rig standby charges during the second quarter of 2020.~~

•~~$2.4 million charge to income for interest expense on unpaid production taxes recorded in the third quarter of 2020.~~

•~~$0.3 million charge to income for other legal accruals recorded in the third quarter of 2020.~~

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~~Impairment of Oil and Gas Properties~~

For the three months ended September 30, 2020 the Company recognized 0 impairment expense on its proved oil and gas properties, but for the nine months ended September 30, 2020 the Company recognized $1.6 million related to impairment of assets in its northern field. For the three months ended September 30, 2019, the Company recognized 0 impairment expense on its proved oil and gas properties, but for the nine months ended September 30, 2019, the Company recognized $11.2 million related to impairment of assets in its northern field. The fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field. For the three and nine months ended September 30, 2020 and 2019, the Company did not have any proved property impairment in its Core DJ Basin field.

Of the Company's $9.8 million in exploration and abandonment expenses for the three months ended September 30, 2020, $9.5 million was lease abandonment expense. Of the Company's $184.9 million in exploration and abandonment expenses for the nine months ended September 30, 2020, $179.0 million was lease abandonment expense. Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties are reported in exploration and abandonment expenses in the condensed consolidated statements of operations.

~~Recent Accounting Pronouncements~~Divestitures

In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-13, Financial Instruments—Credit Losses. In May 2019, ASU No. 2016-13 was subsequently amended by ASU No. 2019-04, Codification Improvements to Topic 326, Financial Instruments—Credit Losses and ASU No. 2019-05, Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief. ASU No. 2016-13, as amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU replaced the incurred loss approach with an expected loss model for instruments measured at amortized cost and was effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. ASU No. 2016-13 will be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company adopted this ASU on January 1, 2020, and the adoption did not have a material impact on the condensed consolidated financial statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-13, which removes or modifies current fair value disclosures and adds additional disclosures. The update to the guidance is the result of the FASB's test of the principles developed in its disclosure effectiveness project, which is designed to improve the effectiveness of disclosures in the notes to the financial statements. The disclosures that have been removed or modified may be applied immediately with retrospective application. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2020, and the adoption did not have a material impact on the condensed consolidated financial statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-15, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. For public entities, the guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2020 which did not have a material impact on the condensed consolidated financial statements and related disclosures as capitalized costs for internal-use software were not material as of September 30, 2020.

Other than as disclosed above or in the Company’s Annual Report, there are no other accounting standards applicable to the Company as of September 30, 2020 and through the date of this filing that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company.

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~~Note 3—Divestitures~~

~~February 2020 Divestiture~~

~~In February 2020,~~April 2021, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately ~~$12.2~~$15.2 million, subject to customary purchase price adjustments. No gain or loss was ~~recognized~~recognized. In conjunction with the April 2021 divestiture, the Company recorded a receivable of approximately $2.7 million in the condensed consolidated balance sheet as of June 30, 2021 for ~~the February 2020 Divestiture.~~post-closing adjustments. The Company continues to explore divestitures as part of our ongoing initiative to divest non-strategic assets.

~~December 2019 Divestiture~~Segments

The Company has a single reportable segment.

Recent Accounting Pronouncements

In ~~December 2019,~~May 2021, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2021-04, Earnings Per Share (Topic 260), Debt—Modifications and Extinguishments (Subtopic 470-50), Compensation—Stock Compensation (Topic 718), and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40). This ASU clarifies accounting for modifications or exchanges of freestanding equity-classified written call options (for example, warrants) that remain equity classified after modification or exchange. The amendments in this ASU are effective for the Company ~~completed~~beginning January 1, 2022. Early adoption is permitted and

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amendments should be applied prospectively to modifications or exchanges occurring on the ~~sale~~effective date of ~~certain non-operated producing properties for aggregate sales proceeds~~the amendments. The Company is evaluating the effect of ~~approximately $10.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the December 2019 Divestiture.~~adopting this guidance.

~~August 2019 Divestiture~~

~~In August 2019,~~Other than as disclosed in the Company’s Annual Report, there are no other accounting standards applicable to the Company ~~completed~~as of June 30, 2021 and through the ~~sale~~date of certain non-operated producing properties for aggregate sales proceeds of approximately $22.0 million, subject to customary purchase price adjustments. No gain or loss was recognized for the August 2019 Divestiture.

~~March 2019 Divestiture~~

~~In March 2019,~~this filing that have been issued but not yet adopted by the Company ~~completed~~that would have a material effect on the ~~sale of its interests in approximately 5,000 net acres of leasehold~~Company’s unaudited condensed consolidated financial statements and producing properties for aggregate sales proceeds of approximately $22.4 million. The effective date for the March 2019 Divestiture was July 1, 2018 with purchase price adjustments calculated as of the closing date of $5.9 million, resulting in net proceeds of $16.5 million. No gain or loss was recognized for the March 2019 Divestiture.related disclosures.

Note ~~4—Liabilities Subject~~3—Fresh Start Reporting

Fresh Start Reporting

In connection with the Company’s emergence from bankruptcy and in accordance with ASC 852, the Company qualified for and applied fresh start reporting on the Emergence Date. The Company was required to ~~Compromise~~apply fresh start reporting due to the fact that (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company, and (ii) the reorganization value (defined below) of the Company’s assets immediately prior to confirmation of the Plan of $1.4 billion was less than the $2.9 billion of post-petition liabilities and allowed claims.

As a result of the Company qualifying for fresh start reporting, a new reporting entity was considered to have been created; as a result and in accordance with ASC 852, the Company allocated the reorganization value of the Company to its individual assets, including property, plant and equipment, based on their estimated fair values in conformity with ASC Topic 820–Fair Value Measurement (“ASC 820”) and ASC Topic 805–Business Combinations (“ASC 805”). As such, the condensed consolidated financial statements after January 20, 2021 are not comparable with the condensed consolidated financial statements as of or prior to that date.

Reorganization Value

Reorganization value represents the fair value of the Successor Company’s assets before considering certain liabilities and is intended to represent the approximate amount a willing buyer would pay for the Company’s assets immediately after reorganization. Reorganization value is derived from an estimate of enterprise value, or fair value of the Company’s interest-bearing debt and stockholders’ equity. As set forth in the Plan and related disclosure statement, the enterprise value of the Successor Company was estimated to be between $875.0 million to $1.275 billion. On the Emergence Date, the Successor Company’s estimated enterprise value was $1.052 billion before the consideration of cash and cash equivalents on hand, which falls slightly below the midpoint of this range. The enterprise value was derived from an independent valuation using an income approach to derive the fair value of the Company’s assets as of the Emergence Date. On the Emergence Date, pursuant to the terms of the Plan, the Successor Company entered into a $1.0 billion reserve-based credit agreement with an initial borrowing base of $500.0 million. Please see Note 4—Long-Term Debt for discussion of the Successor Company’s debt.

The Company’s ~~liabilities subject~~principal assets are its oil and natural gas properties. The fair value of proved reserves was estimated using a discounted cash flows approach, which was based on the anticipated future cash flows associated with those proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 11.0%. The proved reserve locations included in this analysis were limited to ~~compromise consisted~~wells included in the Company's five-year development plan. Future prices were based on forward strip price curves (adjusted for basis differentials). The fair value of the Company’s unproved reserves was estimated using a discounted cash flows approach. See further discussion below in the section titled “Fresh Start Adjustments.”

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The following table reconciles the Company’s enterprise value to the implied value of Successor equity as of January 20, 2021 (in thousands, except per share data):


	Successor
	January 20, 2021
Enterprise value	$	1,052,000
Plus: Cash and cash equivalents	71,793
Plus: General unsecured claims to be satisfied through issuance of equity after Emergence	16,127
Less: Working capital adjustment(1)	(333,938)
Less: Interest bearing liabilities	(265,000)
Less: Fair value of warrants(2)	(20,403)
Implied value of Successor equity after satisfaction of general unsecured claims after Emergence	$	520,579
Less: General unsecured claims to be satisfied through issuance of equity after Emergence	(16,127)
Implied value of Successor equity as of January 20, 2021	$	504,452




Common shares of Successor equity as of January 20, 2021	24,729,681
Implied value per common share as of January 20, 2021	$	20.41

_______________

(1) Represents current assets without cash and cash equivalents and restricted cash, current liabilities without asset retirement obligations and the current liability related to the professional fee escrow accrual in “Accounts payable and accrued liabilities,” other non-current liabilities, non-current production taxes, and the working capital deficit adjustment of approximately $23.9 million utilized by the valuation specialist to determine enterprise value for the Plan. This adjustment considers the impact of liabilities in excess of normalized working capital to the enterprise value for purposes of calculating implied Successor equity.

(2) Warrants were considered as part of equity on the condensed consolidated balance sheet but are broken out separately here for presentation and disclosure purposes.

The following table reconciles the Company’s enterprise value to its reorganization value as of January 20, 2021 (in thousands):


	Successor
	January 20, 2021
Enterprise value	$	1,052,000
Plus: Normalized working capital liabilities(1)	176,976
Plus: Asset retirement obligations, current and non-current	87,199
Plus: Cash and cash equivalents	71,793
Reorganization value	$	1,387,968

_______________

(1) Relates to normalized working capital liabilities in the Predecessor ending balance sheet.

Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. See below in the section titled “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of the Company’s significant assets and liabilities.

Condensed Consolidated Balance Sheet at the Emergence Date (in thousands)

The adjustments set forth in the following condensed consolidated balance sheet as of January 20, 2021 reflect the consummation of transactions contemplated by the Plan (the “Reorganization Adjustments”) and the fair value adjustments as a result of applying fresh start reporting (the “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the corresponding assets or liabilities, as well as significant assumptions.

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	Predecessor		Reorganization Adjustments			Fresh Start Adjustments			Successor
ASSETS
Current Assets:
Cash and cash equivalents	$	246,952	$	(175,159)	(a)	$	—		$	71,793
Restricted cash	—		38,869		(b)	—			38,869
Accounts receivable, net
Trade	12,500		—			—			12,500
Oil, natural gas and NGL sales	64,698		—			—			64,698
Inventory, prepaid expenses and other	33,524		0			3,470		(r)	36,994
Commodity derivative asset	—		—			—			—
Total Current Assets	357,674		(136,290)			3,470			224,854
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	4,746,225		—			(3,800,981)		(s)	945,244
Unproved oil and gas properties	221,247		—			(75,647)		(s)	145,600
Wells in progress	136,247		—			(136,247)		(s)	—
Less: accumulated depletion, depreciation, amortization and impairment charges	(3,475,279)		—			3,475,279		(s)	—
Net oil and gas properties	1,628,440		—			(537,596)			1,090,844
Other property and equipment, net of accumulated depreciation and impairment charges	56,455		—			350		(t)	56,805
Net Property and Equipment	1,684,895		—			(537,246)			1,147,649
Non-Current Assets:
Commodity derivative asset	134		—			—			134
Other non-current assets	9,003		6,328		(c)	—			15,331
Total Non-Current Assets	9,137		6,328			—			15,465
Total Assets	$	2,051,706	$	(129,962)		$	(533,776)		$	1,387,968
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	93,036	$	58,792	(d)	$	3,469	(r)	$	155,297
Revenue payable	68,003		59,750		(e)	—			127,753
Production taxes payable	3,284		132,255		(f)	—			135,539
Commodity derivative liability	7,897		—			—			7,897
Accrued interest payable	2,236		(2,236)		(g)	—			—
Asset retirement obligations	—		13,937		(h)	(478)		(u)	13,459
DIP Credit Facility	106,727		(106,727)		(i)	—			—
Prior Credit Facility	453,872		(453,872)		(i)	—			—
Total Current Liabilities	735,055		(298,101)			2,991			439,945
Non-Current Liabilities:
RBL Credit Facility	—		265,000		(j)	—			265,000
Production taxes payable	38,716		22,405		(f)	—			61,121
Commodity derivative liability	—		—			—			—
Other non-current liabilities	—		23,307		(k)	—			23,307
Asset retirement obligations	—		80,620		(h)	(6,880)		(u)	73,740
Deferred tax liability	—		—			—			—
Total Non-Current Liabilities	38,716		391,332			(6,880)			423,168
Liabilities Subject to Compromise	2,135,808		(2,135,808)		(l)	—			—
Total Liabilities	2,909,579		(2,042,577)			(3,889)			863,113

Commitments and Contingencies
Series A Convertible Preferred Stock	192,172		(192,172)		(m)	—			—
Stockholders' Equity (Deficit):
Predecessor common stock	1,336		(1,336)		(n)	—			—
Predecessor treasury stock	(170,138)		170,138		(o)	—			—
Predecessor additional paid-in capital	2,140,383		(2,140,383)		(n)(o)	—			—
Successor common stock	—		247		(p)	—			247
Successor warrants	—		20,403		(p)	—			20,403
Successor additional paid-in capital	0		504,205		(p)	—			504,205
Accumulated deficit	(3,021,626)		3,551,513		(q)	(529,887)		(v)	—
Total Stockholders' Equity (Deficit)	(1,050,045)		2,104,787			(529,887)			524,855
Total Liabilities and Stockholders' Equity (Deficit)	$	2,051,706	$	(129,962)		$	(533,776)		$	1,387,968

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Reorganization Adjustments

(a) The table below reflects the sources and uses of cash and cash equivalents on the Emergence Date pursuant to the terms of the Plan (in thousands):


Sources:
Total cash received from the RBL Credit Facility	September 30, 2020$	265,000
Total proceeds from backstopped rights offering	200,255
Total proceeds from the general unsecured claims rights offering	218
Total sources of cash	465,473
Uses:
Payment of DIP Credit Facility, Prior Credit Facility, and related interest	(562,834)
Funding of the professional fee escrow account	(38,869)
Payment of prepetition taxes classified as liabilities subject to compromise	(21,532)
Payment of debt issuance cost associated with the RBL Credit Facility	(6,329)
Payment of contract cure costs classified as liabilities subject to compromise	(5,374)
Payments to professionals at emergence	(5,102)
Payment of the general unsecured claim cash out election for claims classified as liabilities subject to compromise	(592)
Total uses of cash	(640,632)
Net uses of cash	$	(175,159)

(b) Represents the funding of the professional fee escrow account.

(c) Represents $6.3 million of financing costs related to the RBL Credit Facility, which were capitalized as debt issuance costs and will be amortized straight-line to interest expense through the maturity date of July 20, 2024.

(d) Represents amounts shown in “Accounts payable and accrued liabilities” as reorganization adjustments (in thousands):


Reinstatements from liabilities subject to compromise:
Accounts payable and accrued liabilities	$	29,752
Current portion of a settlement liability	17,700
General unsecured claims to be satisfied through issuance of equity after Emergence	16,127
Other general unsecured claims to be satisfied after Emergence	8,746
Other adjustments:
Success fees	20,800
Backstop Commitment Agreement premium satisfied in common shares at Emergence	(29,231)
Professional fees paid at Emergence	(5,102)
Total accounts payable and accrued liabilities reorganization adjustments	$	58,792

(e) Represents revenue payables formerly in “Liabilities Subject to Compromise” that have been reinstated at emergence and will be paid out subsequent to emergence.

(f) Represents production taxes payable formerly in “Liabilities Subject to Compromise” that have been reinstated at emergence and will be paid out subsequent to emergence.

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(g) Represents the satisfaction upon emergence of the Predecessor Company’s accrued interest payable for the Prior Credit Facility and DIP Credit Facility.

(h) Represents $13.9 million and $80.6 million of the current and non-current portions of asset retirement obligations, respectively, formerly in “Liabilities Subject to Compromise” that have been reinstated at emergence.

(i) Reflects the payment in full of the borrowings outstanding under the Prior Credit Facility and DIP Credit Facility.

(j) Reflects borrowings drawn under the RBL Credit Facility upon emergence.

(k) Represents $19.3 million of the non-current portion of a settlement liability and $4.0 million of other non-current liabilities formerly in “Liabilities Subject to Compromise” that have been reinstated at emergence and will be paid out subsequent to emergence.

(l) As part of the Plan, the Bankruptcy Court approved the settlement of certain claims reported within “Liabilities Subject to Compromise” in the Company's consolidated balance sheet at their respective allowed claim amounts. The table below indicates the reinstatement or disposition of liabilities subject to compromise (in thousands):


Liabilities subject to compromise pre-emergence		$	2,135,808
Amounts reinstated on the Emergence Date:
Production taxes payable		(154,660)
Asset retirement obligations		(94,557)
Revenue payable		(59,750)
Accounts payable and accrued liabilities		$		~~93,526~~
~~Revenue payable~~	~~63,841~~
~~Production taxes payable - current~~	~~155,894~~
~~Production taxes payable - non-current~~	~~22,405~~
~~Asset retirement obligations - current~~	~~18,306~~
~~Asset retirement obligations - non-current~~	~~71,798~~
~~Accrued interest on debt subject to compromise~~	~~31,676~~
~~2024 Senior Notes due May 15, 2024~~	~~400,000~~
~~2026 Senior Notes due February 1, 2026~~	~~700,189~~
~~Deferred liability~~	~~16,813~~
~~Deferred tax liability~~	~~2,200~~
~~Damages for rejected and settled contracts~~	~~494,398~~ (72,860)
Other non-current liabilities		~~38,400~~ (23,307)
Total liabilities reinstated		(405,134)
Consideration provided to settle liabilities subject to compromise per the Plan
Issuance of Successor equity associated with the participation in the backstopped and general unsecured rights offerings		(251,795)
Less proceeds from issuance of Successor equity associated with the backstopped and general unsecured rights offerings		200,473
Issuance of Successor equity to 2024 and 2026 Senior Notes holders, incremental to the backstopped and general unsecured rights offerings, and backstop commitment premium		(156,889)
Issuance of Successor equity to general unsecured claim holders, incremental to the backstopped and general unsecured rights offerings, and backstop commitment premium		(64,857)
Cash payment in settlement of claims and other		(27,498)
Total consideration provided to settle liabilities subject to compromise per the Plan		(300,566)
Gain on settlement of liabilities subject to compromise		$	~~2,109,446~~1,430,108

(m) Pursuant to the terms of the Plan, on the Emergence Date, all Predecessor preferred stock interests were cancelled.

(n) Pursuant to the terms of the Plan, on the Emergence Date, all Predecessor common stock interests were cancelled.

(o) Pursuant to the terms of the Plan, on the Emergence Date, all Predecessor treasury stock interests were cancelled.

(p) Reflects the issuance of Successor equity, including the issuance of 24,729,681 shares of common stock at a par value of $0.01 per share and warrants to purchase 4,358,369 shares of common stock in exchange for claims against or interests in the Debtors pursuant to the Plan. Equity issued is detailed in the table below (in thousands):

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Issuance of Successor equity associated with the participation in the backstopped and general unsecured claims rights offerings	$	251,795
Issuance of Successor equity associated with the backstop commitment premium	23,584
Issuance of Successor equity to 2024 and 2026 Senior Notes holders, incremental to the backstopped and general unsecured rights offerings, and backstop commitment premium	156,889
Issuance of Successor equity to general unsecured claims holders, incremental to the backstopped and general unsecured rights offerings, and backstop commitment premium	64,857
Fair value of warrants (Tranche A and B) to Predecessor common and preferred stockholders	20,403
Issuance of Successor equity to Predecessor common stockholders	3,664
Issuance of Successor equity to Predecessor preferred stockholders	3,663
Total Successor equity as of January 20, 2021	$	524,855

(q) The table below reflects the cumulative net impact of the effects on accumulated deficit (in thousands):


Reorganization items, net:
Gain on settlement of liabilities subject to compromise	$	(1,430,108)
Adjustment to Backstop Commitment Agreement premium	(5,365)
Acceleration of unvested stock compensation	3,468
Success fees	20,800
Impact on reorganization items, net	(1,411,205)
Cancellation of Predecessor equity	(2,140,308)
Net impact on accumulated (deficit)	$	(3,551,513)

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~~As discussed in~~ ~~Note 1—Business and Organization — Voluntary Reorganization under Chapter 11 of the Bankruptcy Cod~~e, since the Petition Date, the Company has been operating as debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with provisions of the Bankruptcy Code. On the accompanying condensed consolidated balance sheets, the line item liabilities subject to compromise reflects the expected allowed amount of the prepetition claims that are not fully secured and that have at least a possibility of not being repaid at the full claim amount. Determination of the value at which liabilities will ultimately be settled cannot be made until the Bankruptcy Court approves the Restructuring Plan. In addition, the manner by which those liabilities are settled will ultimately be determined by the aforementioned Restructuring Plan and could include settlement in cash, Company equity or a combination. Liabilities subject to compromise includes amounts related to the rejection of various executory contracts and unexpired leases. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts and unexpired leases are rejected. The Company will continue to evaluate the amount and classification of its prepetition liabilities. Any additional liabilities that are subject to compromise will be recognized accordingly, and the aggregate amount of liabilities subject to compromise may change.Fresh Start Adjustments

(r) Reflects the adjustment to fair value of the Company's line fill inventory based on market prices as of the Emergence Date.

(s) Reflects the adjustments to fair value of the Company's oil and natural gas properties, proved and unproved, as well as the elimination of wells in progress and accumulated depletion, depreciation and amortization.

~~Note 5—~~

For purposes of estimating the fair value of the Company's proved oil and gas properties, a discounted cash flows approach was used that estimated the fair value based on the anticipated future cash flows associated with the Company's proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 11.0%. The proved reserve locations included in this analysis were limited to wells included in the Company's five-year development plan. Future prices for the income approach were based on forward strip price curves (adjusted for basis differentials) as of the Emergence Date.

In estimating the fair value of the Company's unproved properties, a discounted cash flows approach was used. The approach utilized for proved properties was also consistently utilized for properties that had positive future cash flows associated with reserve locations that did not qualify as proved reserves.

(t) Reflects the fair value adjustment to recognize the Company’s land as of the Emergence Date based on assessed values provided to management by a licensed appraiser. The appraisals utilized the market approach for comparable properties, where there was market comparable data available or the appraiser’s knowledge of the market and the property, to provide an estimated market value where market comparable data was not available.

(u) Reflects the adjustment to fair value of the Company's asset retirement obligations including using a credit-adjusted risk-free rate as of the Emergence Date.

(v) Reflects the net cumulative impact of the fresh start adjustments on accumulated deficit.

Reorganization Items, Net

~~The Company’s reorganization items, net consisted of the following (in thousands):~~

For the Three Months Ending For the Nine Months Ending
September 30,
2020 September 30,
2020
Professional fees $ 23,469 $ 25,819
Professional services fees 0 2,200
Trustee fees 356 471
Damages for rejected and settled contracts 478,370 486,104
DIP Credit Facility fees 0 1,251
Write-off of debt issuance costs 272 13,541
Court approved vendor settlements (1,394) (1,394)
Total reorganization items, net $ 501,073 $ 527,992

~~We have incurred and will continue to incur significant~~Any expenses, gains and losses ~~associated with~~that were realized or incurred between the ~~reorganization, primarily adjustments for allowable claims related to executory contracts approved for rejection by~~Petition Date and the ~~Bankruptcy Court, negotiated settlements on executory contracts, the write-off~~Emergence Date and as a direct result of ~~unamortized debt issuance costs and professional fees incurred subsequent to~~ the Chapter 11 ~~filings for the restructuring process. The amount of these items, which are being incurred~~Cases were recorded in reorganization items, net ~~within our accompanying unaudited condensed~~in the Company’s consolidated statements of ~~operations, are expected to significantly affect our results~~operations. The following table summarizes the components of ~~operations. In future~~reorganization items, net for the periods ~~we may also incur adjustments for allowable claims related to our legal proceedings and executory contracts approved for rejection by the Bankruptcy Court.~~presented (in thousands):

As of September 30, 2020, $505.4 million of reorganization costs, net consisting of professional fees, trustee fees and damages for rejected contracts are accrued and unpaid and are presented in either accounts payable and accrued liabilities or liabilities subject to compromise on the condensed consolidated balance sheets. The write-off of the Senior Notes debt issuance costs are included in reorganization items, net as the Company believes the underlying debt instruments will be impacted by the Chapter 11 Cases. The write-off of the Senior Notes debt issuance costs is a non-cash reorganization item. For the three and nine months ended September 30, 2020, the Company had cash charges related to reorganization items, net of $6.7 million and $10.5 million, respectively.


	Predecessor
	For the Period from January 1 through January 20,
	2021
Gain on settlement of liabilities subject to compromise	$	1,430,108
Adjustment to Backstop Commitment Agreement premium	5,365
Acceleration of unvested stock compensation	(3,468)
Professional fees	(7,410)
Success fees	(20,800)
Fresh start valuation adjustment	(529,887)
Total reorganization items, net	$	873,908

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Note 6—4—Long-Term Debt

The Company’s long-term debt consisted of the following (in thousands):

September 30,
2020 December 31,
2019
DIP Credit Facility $ 110,000 $ —
Credit Facility due August 16, 2022 (or an earlier time as set forth in the Credit Facility) 453,746 470,000
2024 Senior Notes due May 15, 2024 400,000 400,000
2026 Senior Notes due February 1, 2026 700,189 700,189
Total principal 1,663,935 1,570,189
Unamortized debt issuance costs on Senior Notes (1)
0 (14,412)
Total debt, prior to reclassification to liabilities subject to compromise 1,663,935 1,555,777
Less amounts reclassified to liabilities subject to compromise (2)
(1,100,189) 0
Total debt not subject to compromise (3)
563,746 1,555,777
Less current portion of long-term debt (4)
(563,746) 0
Total long-term debt $ 0 $ 1,555,777


	Successor		Predecessor
	June 30, 2021		December 31, 2020
RBL Credit Facility	$	90,000	$	—
DIP Credit Facility	—		106,727
Prior Credit Facility	—		453,747
2024 Senior Notes	—		400,000
2026 Senior Notes	—		700,189
Total principal	90,000		1,660,663
Unamortized debt issuance costs(1)	0		0
Total debt, prior to reclassification to “Liabilities Subject to Compromise”	90,000		1,660,663
Less amounts reclassified to “Liabilities Subject to Compromise”(2)	0		(1,100,189)
Total debt not subject to compromise(3)	90,000		560,474
Less current portion of long-term debt	0		(560,474)
Total long-term debt	$	90,000	$	0

_______________

(1) As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company wrote off all unamortized debt issuance cost balances to reorganization items, net in the ~~condensed~~ consolidated statements of operations during the ~~nine months~~year ended ~~September 30,~~December 31, 2020.

(2) ~~Debt subject~~As of December 31, 2020, amounts reclassified to ~~compromise includes~~“Liabilities Subject to Compromise” included the principal balances of the Predecessor Company’s 2024 and 2026 Senior ~~Notes, which are unsecured claims in the Chapter 11 Cases and where the payments are stayed.~~Notes.

(3) ~~Debt~~Total debt not subject to compromise includes all borrowings outstanding under the Prior Credit Facility and DIP Credit ~~Facility which are fully secured claims in the Chapter 11 Cases and are expected to be unimpaired.~~

(4) Due to uncertainties regarding the outcome of the Chapter 11 Cases, the Company has classified the borrowings outstanding under the Credit Facility and DIP Credit Facility as current liabilities on the condensed consolidated balance sheets as of September 30, 2020.

~~Chapter 11 Cases and Effect of Automatic Stay~~Facility.

On June 14, 2020, the Company filed for relief under Chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing the Company’s Senior Notes, resulting in the automatic and immediate acceleration of all of the Company’s outstanding debt under the Credit Agreement and Senior Notes. In conjunction with the filing of the Chapter 11 Cases, the Company did not make the $14.8 million interest payment on the Company’s 2024 Senior Notes (as defined below) due on May 15, 2020. Any efforts to enforce payment obligations related to the acceleration of the Company’s debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Please refer to ~~Note 1—Business and Organization — Ability to Continue as a Going Concern~~ ~~for more information on the Chapter 11 Cases.~~

~~Debtor-in-Possession Financing~~RBL Credit Facility

On ~~June 16, 2020, in connection with~~ the ~~filing~~Emergence Date, pursuant to the terms of the ~~Chapter 11 Cases,~~Plan, the ~~Debtors~~Successor Company entered into a ~~debtor-in-possession~~$1.0 billion reserve-based credit agreement ~~on the terms set forth in a Superpriority Senior Secured Debtor-in-Possession Credit Agreement (the “DIP~~(“RBL Credit Agreement”)~~, by and among the Company, as borrower, the Company’s subsidiaries party thereto, as guarantors, the lenders party thereto (the “DIP Lenders”), and~~ with Wells Fargo Bank, National Association as DIP agent and issuing lender, pursuant to which, having been granted the approval of the Bankruptcy Court, the DIP Lenders agree to provide the Company with a superpriority senior secured debtor-in-possession credit facility (as amended, the “DIP(“RBL Credit Facility”) with ~~loans in~~an initial borrowing base of $500.0 million. The borrowing base is redetermined semiannually on or around May 1 and November 1 of each year, with one interim “wildcard” redetermination available to each of the Successor Company and its administrative agent between scheduled redeterminations during any 12-month period. On May 6, 2021, the Successor Company’s borrowing base was reaffirmed at $500.0 million. The next scheduled redetermination will be on or around November 1, 2021.

As of the date of this filing, the Successor Company has drawn $70.0 million on the RBL Credit Facility. Total funds available for borrowing under the Successor Company’s RBL Credit Facility, after giving effect to an aggregate ~~principal amount not to exceed $50.0~~of $0.5 million ~~that, among other things, will be used to finance the ongoing general corporate needs~~of undrawn letters of credit, were $429.5 million as of the ~~Debtors during the course~~date of the Chapter 11 Cases. In addition to the $50.0 million of incremental loans, the DIP Credit Facility included $75.0 million in Credit Facility loans rolled over into the DIP Credit Facility during July 2020, for a total facility size of $125.0 million.this filing.

The ~~maturity date~~RBL Credit Facility provides for a $50.0 million sub-limit of the ~~DIP Credit Agreement is the earliest of (i) December 14, 2020, or the date~~aggregate commitments that is ~~six (6) months after~~available for the ~~filing~~issuance of letters of credit. The RBL Credit Facility bears interest either at a rate equal to (i) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (ii) a base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. The RBL Credit Facility matures on July 20, 2024. The grid below shows the ~~Chapter 11 Cases; provided, that such date may be extended to March 14, 2021 with~~base rate margin and Eurodollar margin depending on the ~~prior written approval~~applicable borrowing base utilization percentage as of certain of the DIP Lenders; (ii) the consummation of a sale of all or substantially all of the assets of the Debtors; (iii) the effective date of a plan of reorganization or liquidation in the Chapter 11 Cases; (iv) the entry of an order by the Bankruptcy Court dismissing any of the Chapter 11 Cases or converting such Chapter 11 Cases to a case under chapter 7 of title 11 of the United States Bankruptcy Code; and (v) the date of ~~termination of the DIP Lenders’ commitments and the acceleration of any outstanding extensions of credit, in each case, under the DIP Credit~~this filing:

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~~Agreement and in accordance with the interim and final orders entered by the Bankruptcy Court concerning the DIP~~RBL Credit Agreement. Furthermore, the DIP Credit Facility's interest rate varies similar to the Company's Credit Agreement and was a LIBOR loan with a base interest rate of 1.00% and spread of 5.75% as of September 30, 2020.Facility Borrowing Base Utilization Grid


					Base Rate		Eurodollar		Commitment
Borrowing Base Utilization Percentage	Utilization				Margin		Margin		Fee Rate
Level 1	<25%				2.00	%	3.00	%	0.50	%
Level 2	≥	25%	<	50%	2.25	%	3.25	%	0.50	%
Level 3	≥	50%	<	75%	2.50	%	3.50	%	0.50	%
Level 4	≥	75%	<	90%	2.75	%	3.75	%	0.50	%
Level 5	≥90%				3.00	%	4.00	%	0.50	%

The ~~DIP~~RBL Credit Facility requires the Successor Company to maintain (i) a consolidated net leverage ratio of less than or equal to 3.00 to 1.00, and (ii) a consolidated current ratio of greater than or equal to 1.00 to 1.00. Per the RBL Credit Agreement, ~~contains a requirement that~~for the ~~Company provide, on a monthly basis, a rolling thirteen-week operating budget~~purpose of calculating the current ratio for fiscal quarters ending March 31, 2021 and ~~cash flow forecast (the “Approved Budget”) and not vary~~June 30, 2021, all ad valorem, severance or tax liabilities can be excluded from the Approved Budget, subject to a Permitted Variance (defined below). The Approved Budget is, subject to certain exceptions, tested on a weekly basis to measure any variance, on an aggregate basis, for all disbursements madecurrent liabilities in the ~~prior four-week period. The disbursements actually made in such prior four week period compared to~~calculation of the budgeted aggregate disbursements for such four week period reflected in the most recently delivered Approved Budget may not vary by more than 10% (or a greater amount, to the extent agreed upon by the DIP Agent) (such variance, a “Permitted Variance”). As of September 30, 2020, the Company was in compliance with the covenants under the DIP Credit Facility.current ratio.

The ~~DIP Credit Agreement contains events of default customary~~Successor Company is required to debtor-in-possession financings, including events related to the Chapter 11 Cases, the occurrence of which could result in the acceleration of the Debtors’ obligation to repay the outstanding indebtedness under the DIP Credit Agreement. The Debtors’ obligations under the DIP Credit Agreement will be secured by a security interest in, and lien on, substantially all present and after acquired property (whether tangible, intangible, real, personal or mixed) of the Debtors and will be guaranteed by all of the Company’s restricted subsidiaries.

On July 20, 2020, the Company, together with its subsidiaries party thereto, certain of the DIP Lenders and Wells Fargo Bank, National Association entered into an amendment to the DIP Credit Agreement to, among other things: (i) extend certain Milestones in the DIP Credit Agreement, (ii) modify the limitation on the amount of undrawn New Money Interim Loans and New Money Final Loans in any borrowing so that the amount permitted to be drawn in accordance with the Approved Budget gives effect to the Permitted Variance, (iii) provide for customary prohibitions against unreasonable withholding of approvals with respect to the Approved Budget and the Restructuring Plan on the part of the DIP Lenders and the DIP Agent, and (iv) reaffirm the Debtors’ liens, guaranties and representations and warranties under the DIP Credit Agreement.

On November 2, 2020, the Company, together with its subsidiaries party thereto, certain of the DIP Lenders and Wells Fargo Bank, National Association entered into a second amendment to the DIP Credit Agreement to, among other things: (i) extend certain “Milestones,” as defined in the DIP Credit Agreement, (ii) extend the “Scheduled Maturity Date,” as defined in the DIP Credit Agreement, to January 31, 2021 and (iii) provide that the Scheduled Maturity Date may be further extended, at the request of the Company, to a date that is on or before March 14, 2021 with the prior written consent of the Majority Lenders, as defined in the DIP Credit Agreement.

As of September 30, 2020, the Company's DIP Credit Facility borrowings were $35.0 million and $75.0 million had been rolled over from the Credit Facility for a total outstanding balance of $110.0 million. The DIP Credit Facility is classified as a current liability on the condensed consolidated balance sheets as of September 30, 2020 as it is fully secured and expected to be unimpaired. On July 20, 2020, the Bankruptcy Court entered the final order approving the DIP Credit Agreement and associated DIP Credit Facility (the “Final DIP Order”) and $52.5 million was rolled over from the Credit Agreement into the DIP Credit Facility. On July 27, 2020, the Company drew an additional $20.0 million on the DIP Credit Facility leaving $15.0 million of availability on the facility. However, this availability could be restricted by a minimum liquidity covenant of $10.0 million from unrestricted cash and DIP Credit Facility availability.

~~Credit Agreement~~

In August 2017, the Company entered into an amendment and restatement of its existing credit facility to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base (as amended, the "Credit Facility"). The Credit Facility matures on the earlier of (a) August 16, 2022, (b) April 15, 2021, if (and only if) (i) the Series A Preferred Stock have not been converted into common equity or redeemed prior to April 15, 2021 (the Company can redeem the Series A Preferred Stock at any time), and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16, 2022 or (c) the earlier termination in whole of the commitments under the Credit Facility. No principal payments are generally required until the Credit Facility matures or in the event that the borrowing base falls below the outstanding balance.

~~Table of Contents~~

The amount available to be borrowed under the Company’s Credit Facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of the Company’s proved oil and gas reserves, commodity prices, estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Company’s Credit Facility. Additionally, the undrawn balance may be constrained by the Company's quantitative covenants under the Credit Facility, including the current ratio and ratio of consolidated debt less cash balances to its consolidated EBITDAX, at the next required quarterly compliance date.

On April 27, 2020, the lenders under the Credit Facility provided notice to the Company that they had completed the redetermination scheduled to occur on May 1, 2020, and via this redetermination, the borrowing base had been reduced from $950.0 million to $650.0 million. Following this redetermination, the Company had outstanding borrowings of $600.5 million and had standby letters of credit of $49.5 million, which reduce the availability of the undrawn borrowing base.

The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permits the counterparties to such derivative instruments to terminate their outstanding hedges. Such termination events are not stayed under the Bankruptcy Code. During June 2020, certain of the lenders under the Credit Agreement elected to terminate their International Swaps and Derivatives Association master agreements and outstanding hedges with the Company for aggregate settlement proceeds of $96.1 million. The proceeds from these terminations were applied to the outstanding borrowings under the Credit Facility.

~~As is described in the~~ ~~Debtor-in-Possession Financing~~ section above, $22.5 million rolled from the Credit Facility to the DIP Credit Facility on June 16, 2020 and an additional $52.5 million rolled on July 20, 2020 upon court approval of the Final DIP Order. As of September 30, 2020, the Credit Facility had a drawn balance of $453.7 million classified as a current liability on the condensed consolidated balance sheet. During the third quarter, due to the cancellation of a certain revenue contract discussed in ~~Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements — Revenue — Contract Balances,~~ ~~$24.3 million was drawn on a $40.0 million letter of credit secured by the Company's Credit Facility.As of the date of this filing, and excluding any undrawn amounts under letters of credit, the available amount to be borrowed under the Credit Facility was 0.~~

Principal amounts borrowed on the Credit Facility will be payable on the maturity date. The Company can repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. Prior to the filing of the Chapter 11 Cases, amounts repaid under the Credit Facility could be re-borrowed from time to time, subject to the terms of the facility.

Interest on the Credit Facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the pricing grid below. Additionally, the Credit Facility provides forpay a commitment fee of ~~0.375% to~~ 0.50%, depending on borrowing base usage. Due to the bankruptcy filing on June 14, 2020, a default penalty of an additional 2.00% went into effect and increased the Credit Agreement interest rates above those interest rates shown in the grid below. The grid below shows the Base Rate Margin and Eurodollar Margin depending per annum on the ~~applicable Borrowing Base Utilization Percentage (as defined in the Credit Agreement) as~~actual daily unused portion of the ~~date of this filing:~~

~~Borrowing Base Utilization Grid~~

Eurodollar Base Rate Commitment
Borrowing Base Utilization Percentage Utilization Margin Margin Fee Rate
Level 1 <25% 1.50 % 0.50 % 0.38 %
Level 2 ≥ 25% < 50% 1.75 % 0.75 % 0.38 %
Level 3 ≥ 50% < 75% 2.00 % 1.00 % 0.50 %
Level 4 ≥ 75% < 90% 2.25 % 1.25 % 0.50 %
Level 5 ≥90% 2.50 % 1.50 % 0.50 %

The Credit Agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants;

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(ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the Credit Agreement limits the Company entering into hedges in excess of 85% of its anticipated production volumes.

~~The Credit Agreement also contains financial covenants requiring the Company to comply on the last day of each quarter with a~~ current ~~ratio of its restricted subsidiaries’ current assets (includes availability~~aggregate commitments under the revolving Credit Facility and unrestricted cash and excludes derivative assets) to its restricted subsidiaries’ current liabilities (excludes obligations under the revolving Credit Facility, senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of its restricted subsidiaries’ debt less cash balances to its restricted subsidiaries EBITDAX (EBITDAX is defined as net income adjusted for interest expense, income tax expense/benefit, DD&A, exploration and abandonment expenses as well as certain non-recurring cash and non-cash charges and income (such as stock-based compensation expense, unrealized gains/losses on commodity derivatives and impairment of long-lived assets and goodwill), subject to pro forma adjustments for non-ordinary course acquisitions and divestitures) for the four fiscal quarter periods most recently ended, of not greater than 4.0 to 1.0 as of the last day of such fiscal quarter.

The acceleration of the obligations under the Credit Agreement as of June 14, 2020 resulted in a cross-default and acceleration of the maturity of the Company’s other outstanding long-term debt. The Credit Facility is classified as a current liability on the condensed consolidated balance sheets as of September 30, 2020 as it is fully secured and expected to be unimpaired.

Any borrowings under the Credit Facility are collateralized by substantially all of the assets of the Company and certain of its subsidiaries, including oil and gas properties, personal property and the equity interests of those subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under theRBL Credit Facility. The ~~Company’s obligations under these hedging contracts are secured by the collateral securing the Credit Facility. Elevation~~Successor Company is ~~an unrestricted subsidiary, which is no longer consolidated or controlled by the Company,~~also required to pay customary letter of credit and ~~the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries.~~

~~2024 Senior Notes~~

In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the "2024 Senior Notes" and the offering, the "2024 Senior Notes Offering"). The 2024 Senior Notes bear an annual interest rate of 7.375%. The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year which commenced on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deductingfronting fees.

The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under aRBL Credit Facility (the "2024 Senior Notes Guarantors"). The 2024 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that do not guarantee the 2024 Senior Notes.

~~The 2024 Senior Notes~~Agreement also ~~contain~~contains customary affirmative and negative covenants, ~~that,~~including, among other things, ~~limit~~as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, restrictions on the ~~Company's~~incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants.

Additionally, the RBL Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Successor Company does not comply with the financial and other covenants in the RBL Credit Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Credit Agreement and any outstanding unfunded commitments may be terminated.

Prior Credit Facility, DIP Credit Facility, 2024 Senior Notes Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its 2024 Senior Notes Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and ~~gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes also contains customary events of~~

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default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2024 Senior Notes.

~~The filing of the Chapter 11 Cases resulted in an event of default under and acceleration of the maturity of the Company’s 2024 Senior Notes.~~

2026 Senior Notes

~~In January 2018,~~Information pertaining to these debt facilities can be found in the ~~Company issued at par $750.0 million principal amount of 5.625% Senior Notes due February 1, 2026 (the "2026 Senior Notes" and together with the~~Company’s Annual Report. The Company’s obligations under its Prior Credit Facility, DIP Credit Facility, 2024 Senior Notes ~~the "Senior Notes"~~ and ~~the offering of the~~ 2026 Senior Notes were settled at the "2026 Senior Notes Offering"). The 2026 Senior Notes bear an annual interest rate of 5.625%. The interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year commencing on August 1, 2018. The Company received net proceeds of approximately $737.9 million after deducting fees.

The Company's 2026 Senior Notes are the Company's senior unsecured obligations and rank equally in right of payment with all of the Company's other senior indebtedness and senior to any of the Company's subordinated indebtedness. The Company's 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantee the Company's indebtedness under a Credit Facility (the "2026 Senior Notes Guarantors"). The 2026 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of certain of the Company's future restricted subsidiaries that do not guarantee the 2026 Senior Notes.

The 2026 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the 2026 Senior Notes Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company's or any of its 2026 Senior Notes Guarantors' equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2026 Senior Notes.

~~The filing of the Chapter 11 Cases resulted in an event of default under and acceleration of the maturity of the Company’s 2026 Senior Notes.~~Effective Date.

Debt Issuance Costs

~~Debt~~Successor Company debt issuance costs include origination, legal and other fees incurred in connection with the Successor Company’s RBL Credit ~~Facility and Senior Notes.~~Facility. As of ~~September~~June 30, ~~2020,~~2021, the Successor Company had debt issuance costs, net of accumulated amortization, of ~~$0.5~~$5.5 million, ~~related to its Credit Facility~~ which has been reflected on the Successor Company's condensed consolidated balance sheets within the line item ~~other~~“Other non-current assets.” For the period from January 1, 2021 to January 20, 2021, the Predecessor Company recorded amortization expense related to debt issuance costs of $0.1 million. For the three months ended June 30, 2021 and for the period from January 21, 2021 to June 30, 2021, the Successor Company recorded amortization expense related to debt issuance costs of $0.5 million and $0.9 million, respectively. For the three and six months ended June 30, 2020, the Predecessor Company recorded amortization expense related to debt issuance costs of $1.9 million and $3.2 million, respectively.

Predecessor Company debt issuance costs include origination, legal and other fees incurred in connection with the Predecessor Company’s Prior Credit Facility, DIP Credit Facility, 2024 Senior Notes and 2026 Senior Notes. As a result of the bankruptcy, the Company ~~wrote-off $13.5~~wrote off $13.3 million in unamortized debt issuance costs on the 2024 and 2026 Senior Notes to reorganization items, net in the condensed consolidated statements of ~~operations. For~~operations for the three and six months ~~ended September~~ending June 30, 2020 and 2019, the Company recorded amortization expense related to the debt issuance costs of $0.2 million and $1.0 million, respectively. For the nine months ended September 30, 2020 and 2019, the Company recorded amortization expense related to the debt issuance costs of $3.3 million and $3.8 million, respectively.2020.

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Interest Incurred on Long-Term Debt

For the ~~three and nine months ended September 30, 2020,~~period from January 1, 2021 to January 20, 2021, the Predecessor Company incurred interest expense on long-term debt of ~~$8.1~~$1.5 million and ~~$50.6 million, respectively, as compared to $23.8~~capitalized interest expense on long-term debt of $0.1 million. For the three months ended June 30, 2021, the Successor Company incurred interest expense on long-term debt of $1.8 million and ~~$66.9~~capitalized interest expense on long-term debt of $0.1 million. For the period from January 21, 2021 to June 30, 2021, the Successor Company incurred interest expense on long-term debt of $4.4 million ~~respectively, for~~and capitalized interest expense on long-term debt of $0.1 million. For the three and ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020, the Predecessor Company incurred interest expense on long-term debt of $20.2 million and $42.5 million, respectively. Absent the automatic stay, interest expense for the three and ~~nine~~six months ended ~~September~~June 30, 2020 would have been ~~$24.6~~$23.2 million and ~~$69.2~~$44.5 million, respectively. For the three and ~~nine~~six months ended ~~September~~June 30, 2020, the Predecessor Company capitalized interest expense on ~~long term~~long-term debt of ~~$0.9~~$1.9 million and ~~$4.9~~$4.0 million, respectively, as compared to $1.6 million and $5.4 million, respectively, for the three and nine months ended September 30, 2019, which has been reflected in the Company’s condensed consolidated financial statements.

~~Senior Note Repurchase Program~~

On January 4, 2019, the Board of Directors authorized a program to repurchase up to $100.0 million of the Company’s Senior Notes (the “Senior Notes Repurchase Program”). The Company’s Senior Notes Repurchase Program is subject to restrictions under the Credit Facility and does not obligate it to acquire any specific nominal amount of Senior Notes. For the three and nine months ended September 30, 2020, the Company did not repurchase any Senior Notes. As a result of the Chapter 11 Cases, the authorization to repurchase Senior Notes is no longer applicable. For the three months ended September 30, 2019, the Company did not repurchase 2026 Senior Notes. For the nine months ended September 30, 2019, the Company repurchased a nominal value of $49.8 million for $39.3 million in connection with the Senior Notes Repurchase Program. Interest expense for the nine months ended September 30, 2019 contained a $10.5 million gain on debt repurchase related to the Company's Senior Notes Repurchase Program. For the three months ended September 30, 2019, this gain was 0.respectively.

Note 7—5—Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. The Company has historically relied on commodity derivative contracts to mitigate its exposure to lower commodity prices.

The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While

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the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

To reduce the impact of fluctuations in oil and natural gas prices on the Company's revenues, the Company has periodically entered into commodity derivative contracts with respect to certain of its oil and natural gas production through various transactions that limit the downside of future prices received. The Company plans to continue its practice of entering into such transactions to reduce the impact of commodity price volatility on its cash flow from operations. Future transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage the Company's exposure to oil and natural gas price fluctuations.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with 2 counterparties, both of which are lenders under the Credit Agreement and the DIP Credit Facility. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. There is 0 credit risk related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period.

~~Effect of Chapter 11 Cases~~

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The Company’s open commodity derivative contracts by quarter as of ~~September~~June 30, ~~2020~~2021 are summarized below:


		12/31/2020		3/31/2021		6/30/2021			9/30/2021		12/31/2021		3/31/2022		6/30/2022		9/30/2022		12/31/2022		3/31/2023
NYMEX WTI Crude Swaps:	NYMEX WTI Crude Swaps:							NYMEX WTI Crude Swaps:
Notional volume (Bbl)	Notional volume (Bbl)	1,875,000		750,000		450,000		Notional volume (Bbl)	1,153,000		1,041,000		828,000		—		—		—		—
Weighted average fixed price ($/Bbl)	Weighted average fixed price ($/Bbl)	$	47.59	$	60.07	$	60.07	Weighted average fixed price ($/Bbl)	$	49.64	$	50.01	$	50.05	$	—	$	—	$	—	$	—
NYMEX WTI Crude Purchased Puts:	NYMEX WTI Crude Purchased Puts:							NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)	Notional volume (Bbl)	0		150,000		150,000		Notional volume (Bbl)	—		—		—		345,839		320,247		297,903		94,820
Weighted average purchased put price ($/Bbl)	Weighted average purchased put price ($/Bbl)	$	0	$	55.04	$	55.04	Weighted average purchased put price ($/Bbl)	$	—	$	—	$	—	$	40.00	$	40.00	$	40.00	$	40.00
NYMEX WTI Crude Sold Calls:	NYMEX WTI Crude Sold Calls:							NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)	Notional volume (Bbl)	0		150,000		150,000		Notional volume (Bbl)	—		—		—		345,839		320,247		297,903		94,820
Weighted average sold call price ($/Bbl)	Weighted average sold call price ($/Bbl)	$	0	$	65.00	$	65.00	Weighted average sold call price ($/Bbl)	$	—	$	—	$	—	$	72.70	$	72.70	$	72.70	$	72.70
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)		0		900,000		600,000
Weighted average sold put price ($/Bbl)		$	0	$	43.92	$	43.88
NYMEX HH Natural Gas Swaps:	NYMEX HH Natural Gas Swaps:							NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)	Notional volume (MMBtu)	9,000,000		—		—		Notional volume (MMBtu)	8,482,141		7,904,240		6,468,277		—		—		—		—
Weighted average fixed price ($/MMBtu)	Weighted average fixed price ($/MMBtu)	$	2.53	$	—	$	—	Weighted average fixed price ($/MMBtu)	$	2.93	$	2.93	$	3.00	$	—	$	—	$	—	$	—
CIG Basis Swaps
NYMEX HH Natural Gas Purchased Puts:								NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)	Notional volume (MMBtu)	3,000,000		—		—		Notional volume (MMBtu)	—		—		—		2,764,135		2,614,602		2,477,469		797,160
Weighted average fixed basis price ($/MMBtu)		$	(0.40)	$	—	$	—
Weighted average purchased put price ($/MMBtu)								Weighted average purchased put price ($/MMBtu)	$	—	$	—	$	—	$	2.00	$	2.00	$	2.00	$	2.00
NYMEX HH Natural Gas Sold Calls:								NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)								Notional volume (MMBtu)	—		—		—		2,764,135		2,614,602		2,477,469		797,160
Weighted average sold call price ($/MMBtu)								Weighted average sold call price ($/MMBtu)	$	—	$	—	$	—	$	3.25	$	3.25	$	3.25	$	3.25

The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the condensed consolidated balance sheets (in thousands):

As of September 30, 2020
Location on Balance Sheet Gross Amounts of Recognized Assets and Liabilities
Gross Amounts Offsets in the Balance Sheet(1)
Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Gross Amounts not Offset in the Balance Sheet(2)
Net Amounts(3)
Current assets $ 40,595 $ (7,970) $ 32,625 $ 0 $ 32,625
Non-current assets 0 0 0 0 0
Current liabilities (8,646) 7,970 (676) 0 (676)
Non-current liabilities 0 0 0 0 0
As of December 31, 2019
Location on Balance Sheet Gross Amounts of Recognized Assets and Liabilities
Gross Amounts Offsets in the Balance Sheet(1)
Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Gross Amounts not Offset in the Balance Sheet(2)
Net Amounts(3)
Current assets $ 48,605 $ (31,051) $ 17,554 $ 0 $ 30,783
Non-current assets 38,034 (24,805) 13,229 0 0
Current liabilities (33,049) 31,051 (1,998) 0 (2,106)
Non-current liabilities (24,913) 24,805 (108) 0 0

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Location on Balance Sheet	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offsets in the Balance Sheet(1)		Net Amounts of Assets and Liabilities Presented in the Balance Sheet		Gross Amounts not Offset in the Balance Sheet(2)		Net Amounts(3)
	Successor as of June 30, 2021
Current assets	$	375	$	(375)	$	0	$	0	$	0
Non-current assets	1,207		(1,207)		0		0		0
Current liabilities	(79,290)		375		(78,915)		0		(82,217)
Non-current liabilities	(4,509)		1,207		(3,302)		0		0


	Predecessor as of December 31, 2020
Current assets	$	8,372	$	(1,401)	$	6,971	$	0	$	6,971
Non-current assets	0		0		0		0		0
Current liabilities	(3,548)		1,401		(2,147)		0		(2,147)
Non-current liabilities	0		0		0		0		0

_______________

(1)Agreements are in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

(2)Netting for balance sheet presentation is performed by current and non-current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the condensed consolidated balance sheets. There are no amounts of related financial collateral received or pledged.

(3)Net amounts are not split by current and non-current. All counterparties in a net asset position are shown in the current asset line, and all counterparties in a net liability position are shown in the current liability line item.

Commodity derivatives gain (loss) are included in the Other income (expense) section of the condensed consolidated statements of operations. The table below sets forth the commodity derivatives gain (loss) for the ~~three and nine months ended September 30, 2020 and 2019~~periods presented (in thousands). ~~Commodity derivatives gain (loss) are included under the other income (expense) line item in the condensed consolidated statements of operations.~~

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2020 2019 2020 2019
Commodity derivatives gain (loss) $ (9,673) $ 87,956 $ 184,041 $ 39,383


	Successor		Predecessor
	For the Three Months Ended June 30,		For the Three Months Ended June 30,
	2021		2020
Commodity derivative loss	$	(75,839)	$	(69,301)


	Successor		Predecessor
	For the Period from January 21 through June 30,		For the Period from January 1 through January 20,		For the Six Months Ended June 30,
	2021		2021		2020
Commodity derivative gain (loss)	$	(104,325)	$	(12,586)	$	193,714

Note 8—6—Asset Retirement Obligations

~~The Company follows accounting for asset retirement obligations in accordance with ASC 410~~ —~~Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made.~~ The Company’s asset retirement obligations ~~primarily~~(“ARO”) represent the ~~estimated~~ present value of estimated future costs associated with the ~~amounts expected to be incurred to plug, abandon~~plugging and ~~remediate producing~~abandonment of oil and ~~shut-in~~gas wells, ~~at the end~~removal of ~~their productive lives~~equipment and facilities from leased acreage, and land restoration in accordance with applicable local, state and federal ~~laws,~~laws. The current and ~~applicable lease terms. The Company determines the estimated fair value~~non-current portions as of ~~its asset retirement obligations by calculating the present value of estimated cash flows related~~December 31, 2020 (Predecessor) were $14.3 million and $80.5 million, respectively, and have been included in “Liabilities Subject to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method. Asset retirement obligations are currently presentedCompromise” in ~~the line item liabilities subject to compromise on~~ the condensed consolidated balance ~~sheets.~~

sheets as of that balance sheet date. The following table ~~summarizes the activities~~provides a reconciliation of the Company’s ~~asset retirement obligations~~ARO for the ~~period indicated~~periods presented (in thousands):

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	~~For the Nine Months Ended September 30, 2020~~
~~Balance beginning of period~~Asset retirement obligations at December 31, 2020 (Predecessor)			$	~~95,908~~
~~Liabilities incurred or acquired~~		~~332~~94,769
Liabilities settled			~~(18,975)~~(545)
Accretion expense			333
Asset retirement obligations at January 20, 2021 (Predecessor)			94,557
Fresh start adjustment(1)			(7,358)
Asset retirement obligations at January 20, 2021 (Predecessor)			87,199


Asset retirement obligations at January 21, 2021 (Successor)			87,199
Liabilities incurred or acquired			138
Liabilities settled			(2,541)
Revisions in estimated cash flows			~~7,861~~651
Accretion expense			~~4,978~~3,267
~~Balance end of period~~Asset retirement obligations at June 30, 2021 (Successor)			$	~~90,104~~88,714

_______________

(1) Refer to Note 3—Fresh Start Reporting for more information on fresh start adjustments.

Note 9—7—Fair Value Measurements

~~ASC 820,~~ ~~Fair Value Measurement and Disclosure~~, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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•~~Level 1: Quoted prices are available in active markets for identical assets or liabilities;~~

•~~Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;~~

•~~Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.~~

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between levels during any periods presented below.

The following table (in thousands) presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis, ~~as of September 30, 2020 and December 31, 2019~~ by level within the fair value ~~hierarchy (in thousands):~~hierarchy:


		Fair Value Measurement at September 30, 2020									Successor								Predecessor
		Level 1		Level 2		Level 3		Total			Fair Value Measurement at June 30, 2021								Fair Value Measurement at December 31, 2020
Financial Assets:
											Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivative assets	Commodity derivative assets	$	0	$	32,625	$	0	$	32,625	Commodity derivative assets	$	0	$	0	$	0	$	0	$	0	$	6,971	$	0	$	6,971
Financial Liabilities:
Commodity derivative liabilities	Commodity derivative liabilities	$	0	$	676	$	0	$	676	Commodity derivative liabilities	0		82,217		0		82,217		0		2,147		0		2,147

Fair Value Measurement at December 31, 2019
Level 1 Level 2 Level 3 Total
Financial Assets:
Commodity derivative assets $ 0 $ 30,783 $ 0 $ 30,783
Financial Liabilities:
Commodity derivative liabilities $ 0 $ 2,106 $ 0 $ 2,106

The following ~~methods and assumptions were used to estimate~~table (in thousands) presents the fair value of the ~~assets and liabilities in the tables above:~~

~~Commodity Derivative Instruments~~

The Company determines its estimate of the fair value of derivative instruments using a market based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty, and the Company's own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options and, call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

~~Fair Value of Financial Instruments~~

~~The Company's~~ financial instruments ~~consist primarily of cash~~ and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. As of September 30, 2020, the Senior Notes were reclassified to liabilities subject to compromise. The carrying ~~values of cash and cash equivalents,~~

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accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amounts of the Company’s Credit Facility and DIP Credit Facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair values of the 2024 Senior Notes and 2026 Senior Notes were derived from available market data. As such, the Company has classified the 2024 Senior Notes and 2026 Senior Notes as Level 2. Please refer to ~~Note 6—Long-Term Debt~~ ~~for further information. The Company’s policy is to recognize transfers between levels at the end of the period.~~value. This ~~disclosure (in thousands)~~table does not impact the Company's financial position, results of operations or cash flows.

At September 30, 2020 At December 31, 2019
Carrying Amount Fair Value Carrying Amount Fair Value
Credit Facility $ 453,746 $ 453,746 $ 470,000 $ 470,000
DIP Credit Facility $ 110,000 $ 110,000 $ — $ —
2024 Senior Notes(1)
$ 400,000 $ 102,500 $ 394,824 $ 250,000
2026 Senior Notes(2)
$ 700,189 $ 178,548 $ 690,953 $ 420,113

~~(1)The carrying amount of the 2024 Senior Notes includes 0 unamortized debt issuance costs as of September 30, 2020 and $5.2 million as of December 31, 2019.~~

~~(2)The carrying amount of the 2026 Senior Notes includes 0 unamortized debt issuance costs as of September 30, 2020 and $9.2 million as of December 31, 2019.~~


	Successor				Predecessor
	At June 30, 2021				At December 31, 2020
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
RBL Credit Facility	$	90,000	$	90,000	$	0	$	0
Prior Credit Facility	0		0		453,747		453,747
DIP Credit Facility	0		0		106,727		106,727
2024 Senior Notes	0		0		400,000		70,732
2026 Senior Notes	0		0		700,189		123,408

Non-Recurring Fair Value Measurements

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair value on a recurring basis, but are subject to fair value adjustments when facts and circumstances arise that indicate a need for remeasurement.

The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate ~~and at least annually,~~ a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on the net discounted future cash flows of producing property. The future cash flows are based on management’s estimates for the future. ~~Unobservable~~The unobservable inputs ~~include~~ listed below are Level 3 inputs within the fair value hierarchy and include:

•estimates of oil and gas production, as the case may be, from the Company’s reserve ~~reports,~~ reports;

•commodity prices based on the sales contract terms and forward price ~~curves,~~ curves;

•operating and development ~~costs~~costs; and,

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•a discount rate based on a market-based weighted average cost of ~~capital (all of which are Level 3 inputs within~~capital.

For both the ~~fair value hierarchy). For the nine months ended September~~periods from January 1, 2021 to January 20, 2021 and January 21, 2021 to June 30, ~~2020 and 2019,~~2021, the Company recognized ~~$1.6~~no impairment expense on their proved oil and gas properties. For the three and six months ended June 30, 2020, the Predecessor Company recognized $0.8 million and ~~$11.2~~$1.6 million, respectively, in impairment expense on its proved oil and gas properties related to impairment of assets in its northern ~~field. For~~field as the ~~three months ended September 30, 2020 and 2019,~~fair value did not exceed the ~~Company recognized 0 impairment expense on~~Predecessor Company's carrying amount associated with its proved oil and gas properties ~~related to impairment of assets~~ in its northern field.

See Note 3—Fresh Start Reporting for discussion of the revaluation of the Company’s oil and gas properties upon emergence from bankruptcy.

Note ~~10—~~8—Income Taxes

The Company computes an estimated annual effective tax rate (“AETR”) each quarter based on the current and forecasted operating results. The income tax expense or benefit associated with the interim period is computed using the most recent estimated AETR applied to the year-to-date ordinary income or loss, plus the tax effect of any significant or infrequently occurring items recorded during the interim period. The computation of the estimated AETR at each interim period requires certain estimates and significant judgements including, but not limited to, the expected operating income (loss) for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent differences and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, and additional information becomes known or as the tax environment changes.

The effective combined U.S. federal and state income tax rate for the ~~nine~~following periods were as follows:

•For the period from January 1, 2021 to January 20, 2021: 0

•For the three months ended ~~September~~June 30, ~~2020 and 2019 was (0.27)~~2021: 16.29%

•For the period from January 21, 2021 to June 30, 2021: 19.90%

•For the three months ended June 30, 2020: 0

•For the six months ended June 30, 2020: (0.80)% ~~and (5.7)%, respectively.~~

The effective rate ~~for the nine months ended September 30, 2020 and 2019~~ differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to

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pre-tax income due to (i) the effect of a full valuation allowance in effect at ~~September~~June 30, ~~2020~~2021, and (ii) the effects of state taxes, permanent taxable differences, and income attributable to non-controlling interest for the ~~nine~~six months ended ~~September~~June 30, ~~2019. Before accounting for a naked credit deferred tax liability, net~~2020. Net tax expense for the ~~three months ended September 30, 2020~~period January 1, 2021 to January 20, 2021 was reduced to zero due to the valuation allowance. Current tax expense for the period January 21, 2021 to June 30, 2021 was $28.1 million primarily as a result of net operating loss (“NOL”) carryovers limited under Section 382 of the Internal Revenue Service Code of 1986, as amended (“IRC”) due to the change in control as referenced in Note 3—Fresh Start Reporting.

As described in Note 1—Business and Organization—Voluntary Reorganization under Chapter 11 of the Bankruptcy Code in the Company’s filed Form 10-Q from the first quarter of 2021, in accordance with the Plan, the Company’s 2024 and 2026 Senior Notes were canceled and exchanged for New Common Stock. 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 ~~naked credit deferred~~Internal Revenue Code (“IRC”) provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax ~~liability results~~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 emergence from Chapter 11 bankruptcy proceedings, the CODI may reduce some or all of the amount of prior tax attributes, which can include net operating losses, capital losses, alternative minimum tax credits and tax basis in assets. The actual reduction in tax ~~expense of $2.2 million for the nine months ended September 30, 2020.~~attributes does not occur until January 1, 2022.

The Company ~~considers whether some portion, or all,~~has evaluated the impact of the ~~deferred~~reorganization, including the change in control, resulting from its emergence from bankruptcy. From an income tax ~~assets (“DTAs”)~~perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses. On the date of emergence, the estimated NOL was approximately

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$1.3 billion. The Company believes that the Successor Company will be able to fully absorb the cancellation of debt income realized ~~based on a more likely than not standard of judgment.~~by the Predecessor Company in connection with the reorganization with its adjusted NOL carryovers. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At December 31, 2019, the Company had a valuation allowance totaling $246.1 million against its DTAs resulting from prior year cumulative financial losses, oil and gas impairments, and significant net operating losses for U.S. federal and state income tax. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. As of September 30, 2020, there was no change in the Company’s assessmentamount of the ~~realizability of its DTAs, except for a naked credit deferred tax liability.~~

On July 13, 2020 the Bankruptcy Court entered a final order approving certain procedures (including notice requirements) that certain shareholders and potential shareholders must comply with regarding transfers of, or declarations of worthlessness with respect to, the Company’s common stock and preferred stock, as well as certain obligations with respect to notifying the Company with respect to current share ownership, each of which are intended to preserve the Company’s ability to use its net operating losses to offset possible future U.S. taxable income by reducing the likelihood of an ownership changeremaining NOL carryovers will be limited under Section 382 of the ~~Code during~~IRC due to the ~~pendency~~change in control as referenced in Note 3—Fresh Start Reporting. As the tax basis of the ~~Chapter 11 Cases.~~Company's assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the fresh-start accounting process, the Successor Company is in a net deferred tax asset position. Per authoritative guidance, historical results along with expected market conditions known on the date of measurement, it is more likely than not that the Company will not realize future income tax benefits from the additional tax basis and its remaining NOL carryovers. This is periodically reassessed and could change. Accordingly, the Company has provided for a full valuation allowance of the underlying deferred tax assets.

Note ~~11—~~9—Stock-Based Compensation

~~Extraction Long Term~~2021 Long-Term Incentive Plan

On January 20, 2021, as part of the emergence from bankruptcy, the Board adopted the Extraction 2021 Long-Term Incentive Plan (the “2021 LTIP”) with a share reserve equal to 3,038,657 shares of New Common Stock. The 2021 LTIP provides for the grant of restricted stock units, restricted stock awards, stock options, stock appreciation rights, performance awards and cash awards to the Company’s employees and non-employee Board members. At emergence, the Successor Company granted awards under the 2021 LTIP to its directors, officers and employees, including restricted stock units, performance stock units and deferred stock units.

2016 Long-Term Incentive Plan

In October 2016, the Predecessor Company’s ~~board of directors~~Board adopted the Extraction ~~Oil & Gas, Inc.~~ 2016 ~~Long Term~~Long-Term Incentive Plan (the “2016 ~~Plan” or “LTIP”~~LTIP”), pursuant to which employees, consultants, and directors of the Predecessor Company and its affiliates performing services for the Predecessor Company ~~are~~were eligible to receive awards. The 2016 ~~Plan provides~~LTIP provided for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards, and performance awards intended to align the interests of participants with those of stockholders. In May 2019, the ~~Company's~~Predecessor Company’s stockholders approved the amendment and restatement of the ~~Company's~~ 2016 ~~Long Term Incentive Plan.~~LTIP. The amended and restated 2016 ~~Long Term Incentive Plan provides~~LTIP provided a total reserve of 32.2 million shares of ~~common stock~~the Predecessor Common Stock for issuance pursuant to awards under the 2016 LTIP. Extraction ~~has~~ granted awards under the 2016 LTIP to certain directors, officers and employees, including stock options, restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards. Effective January 20, 2021, as part of the emergence from bankruptcy, the 2016 LTIP was terminated and no longer in effect and all outstanding awards were cancelled.

Successor Company Restricted Stock Units (“RSUs”)

~~Restricted stock units granted~~RSUs issued under the 2021 LTIP ~~(“RSUs”)~~ generally vest over either a one or three-year service period, with either 100% vesting in year one or ~~25%, 25%~~one-third, one-third and ~~50%~~one-third of the units vesting in ~~year~~ years one,, two and three, respectively. Grant date fair value was determined based on the value of ~~Extraction’s common stock~~the Successor Company’s New Common Stock pursuant to the terms of the 2021 LTIP. The Successor Company assumed a forfeiture rate of 0zero as part of the grant date estimate of compensation cost.

The Successor Company recorded ~~$1.0~~$1.7 million and ~~$3.4~~$3.1 million of stock-based compensation costs related to Successor Company RSUs for the three ~~and nine~~ months ended ~~September~~June 30, ~~2020, respectively, as compared to $6.6 million~~2021 and ~~$20.6 million~~ for the ~~three and nine months ended September~~period from January 21, 2021 through June 30, ~~2019,~~2021, respectively. These costs were included in the condensed consolidated statements of operations within the ~~general~~“General and administrative ~~expenses~~expense” line item. As of ~~September~~June 30, ~~2020,~~2021, there was ~~$4.1~~$4.9 million of total unrecognized compensation cost related to the unvested Successor Company RSUs granted to certain directors, officers and employees that is expected to be recognized over a weighted average period of ~~1.2 years.~~

1.0 year. The following table summarizes the Successor Company’s RSU activity ~~from January 1, 2020 through September 30, 2020~~for the period shown and provides information for the Successor Company’s RSUs outstanding at the dates indicated.

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		Number of Shares	Weighted Average Grant Date Fair Value			Number of Shares	Weighted Average Grant Date Fair Value
Non-vested RSUs at January 1, 2020		2,635,765	$	8.32
Non-vested Successor Company RSUs at January 21, 2021					Non-vested Successor Company RSUs at January 21, 2021	0	$	0
Granted	Granted	1,409,765	$	0.75	Granted	394,795	20.46
Forfeited	Forfeited	(1,845,164)	$	2.99	Forfeited	(6,799)	20.41
Vested	Vested	(995,805)	$	9.03	Vested	0	0
Non-vested RSUs at September 30, 2020		1,204,561	$	7.05
Non-vested Successor Company RSUs at June 30, 2021					Non-vested Successor Company RSUs at June 30, 2021	387,996	$	20.46

~~Performance Stock Awards~~Predecessor Company RSUs

RSUs issued under the 2016 LTIP generally vested over either a one or three-year service period, with either 100% vesting in year one or 25%, 25% and 50% of the units vesting in years one, two and three, respectively. Grant date fair value was determined based on the value of the Predecessor Common Stock pursuant to the terms of the 2016 LTIP. The Predecessor Company assumed a forfeiture rate of 0 as part of the grant date estimate of compensation cost.

The Predecessor Company recorded $0.2 million of stock-based compensation costs related to Predecessor Company RSUs for the period from January 1, 2021 through January 20, 2021, as compared to $1.7 million and $2.5 million for the three and six months ended June 30, 2020, respectively. These costs were included in the condensed consolidated statements of operations within the “General and administrative expense” line item. The following table summarizes the Predecessor Company’s RSU activity for the period shown and provides information for the Predecessor Company’s RSUs outstanding at the dates indicated.


	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested Predecessor Company RSUs at January 1, 2021	1,185,351	$	6.99
Vested	(4,500)	8.70
Cancelled at emergence from bankruptcy	(1,180,851)	6.98
Non-vested Predecessor Company RSUs at January 20, 2021	0	$	0

Successor Company Performance Unit Awards (“PSUs”)

Upon emergence from bankruptcy on January 20, 2021, the Successor Company granted ~~performance stock awards ("PSAs")~~PSUs to certain executives under the ~~LTIP in October 2017, March 2018, April 2019 and March 2020.~~2021 LTIP. The number of shares of ~~the Company's common stock~~New Common Stock that may be issued to settle these various ~~PSAs~~PSUs ranges from zero to two times the number of ~~PSAs~~PSUs awarded. ~~PSA's that settle in cash are presented as liability awards.~~ Generally, the shares issued for ~~PSAs~~PSUs are determined based on the satisfaction of a time-based vesting schedule and ~~a weighting of one or more of the following: (i)~~ absolute total stockholder return ~~("ATSR"), (ii) relative total stockholder return ("RTSR"), as compared to the Company's peer group and (iii) cash return on capital invested ("CROCI") or return on invested capital ("ROIC"~~(“ATSR”) measured over a three-year period, and vest in their entirety at the end of the three-year measurement period. Any ~~PSAs~~PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated with the RTSR is based on a comparison of the Company's total shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR ~~and RTSR~~ vesting ~~criteria~~criterion are linked to the Successor Company's share price, ~~they each are~~it is considered a market ~~condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that is associated with the CROCI and ROIC are considered a performance~~ condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the ~~PSAs~~Successor Company’s PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Successor Company's PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, and because future stock prices are stochastic, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company's expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company's peers.

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The Successor Company recorded $0.5 million and $0.9 million of stock-based compensation costs related to Successor Company PSUs for the three months ended June 30, 2021 and for the period from January 21, 2021 through June 30, 2021, respectively. These costs were included in the condensed consolidated statements of operations within the “General and administrative expense” line item. As of June 30, 2021, there was $5.5 million of total unrecognized compensation cost related to the unvested Successor Company PSUs granted to certain executives that is expected to be recognized over a weighted average period of 2.6 years. The Successor Company’s PSUs will be settled by issuing New Common Stock. The following table summarizes the Successor Company’s PSU activity for the period shown and provides information for the Successor Company’s PSUs outstanding at the dates indicated.


	Number of Shares(1)	Weighted Average Grant Date Fair Value
Non-vested Successor Company PSUs at January 21, 2021	0	$	0
Granted	230,850	28.11
Forfeited	0	0
Vested	0	0
Non-vested Successor Company PSUs at June 30, 2021	230,850	$	28.11

_______________

(1) The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final number of shares of New Common Stock issued may vary depending on the performance multiplier, which ranges from zero to two for the Successor Company’s 2021 PSU grants, depending on the level of satisfaction of the vesting condition.

Predecessor Company Performance Stock Awards (“PSAs”)

The Predecessor Company granted PSAs to certain executives under the 2016 LTIP in October 2017, March 2018, April 2019 and March 2020. The number of shares of Predecessor Common Stock that may be issued to settle these various PSAs ranges from zero to two times the number of PSAs awarded. PSAs that settle in cash were presented as liability awards. Generally, the shares issued for PSAs were determined based on the satisfaction of a time-based vesting schedule and a weighting of one or more of the following: (i) ATSR, (ii) relative total stockholder return (“RTSR”), as compared to the Predecessor Company's peer group and (iii) cash return on capital invested (“CROCI”) or return on invested capital (“ROIC”) measured over a three-year period and vest in their entirety at the end of the three-year measurement period. Any PSAs that have not vested at the end of the applicable measurement period were forfeited. The vesting criterion that was associated with the RTSR was based on a comparison of the Predecessor Company's total shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria were linked to the Predecessor Company's share price, they each were considered a market condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that was associated with the CROCI and ROIC were considered a performance condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the Predecessor Company’s PSAs were measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Predecessor Company's PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peer will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, and because future stock prices are stochastic, ~~or probabilistic with some direction in nature,~~ the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSAs. Significant assumptions used in this simulation include the Company's expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company's peers.

The Predecessor Company recorded ~~$0.9 million and $1.0~~$0.1 million of stock-based compensation costs related to Predecessor Company PSAs for the period from January 1, 2021 through January 20, 2021, as compared to $0.8 million and $0.1 million for the three and ~~nine~~six months ended ~~September~~June 30, 2020, ~~respectively, as compared to $0.7 million and $6.8 million of stock-based compensation costs related to PSAs for the three and nine months ended September 30, 2019,~~ respectively. These costs were included in the condensed consolidated statements of operations within the ~~general~~“General and administrative ~~expenses~~expense” line item. As of ~~September~~June 30, ~~2020,~~2021, there was ~~$1.8 million of total~~no unrecognized compensation cost related to the unvested Predecessor Company PSAs granted to certain ~~executives that is expected to be recognized over a weighted average period of 0.5 years.~~

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executives as they were all cancelled at emergence. The following table summarizes the Predecessor Company’s PSA activity ~~from January 1, 2020 through September 30, 2020~~for the period shown and provides information for the Predecessor Company’s PSAs outstanding at the dates indicated.


	Number of Shares(1)	Weighted Average Grant Date Fair Value
Non-vested Predecessor Company PSAs at January 1, 2021	1,196,279	$	5.32
Cancelled at emergence from bankruptcy	(1,196,279)	5.32
Non-vested Predecessor Company PSAs at January 20, 2021	0	$	0

Number of Shares (1)
Weighted Average Grant Date
Fair Value
Non-vested PSAs at January 1, 2020 2,863,190 $ 7.72
Granted 5,952,700 $ 0.29
Forfeited(2)
(5,881,200) $ (0.29)
Vested 0 $ 0
Non-vested PSAs at September 30, 2020 2,934,690 $ 8.18
_______________

(1)The number of awards ~~assumes~~assumed that the associated maximum vesting condition is met at the target amount. The final number of shares of the ~~Company's common stock~~Predecessor Common Stock issued ~~may vary~~would have varied depending on the performance multiplier, which ~~ranges~~ranged from zero to one for the 2017 and 2018 grants and ~~ranges~~ranged from zero to two for the 2019 and 2020 grants, ~~depending~~which would have depended on the level of satisfaction of the vesting condition.

~~(2)~~The Company approved retention agreements on June 12, 2020 with certain executives and senior managers. These retention agreements, are subject to repayment upon a resignation without “good reason” or termination of employment for “cause” before specified dates and events. As a condition to participating in the revised compensation program, the equity compensation awards granted in 2020 were cancelled.

Successor Company Deferred Stock ~~Options~~Units (“DSUs”)

~~Expense~~Upon emergence from bankruptcy on January 20, 2021, a new Board was appointed and each Board member (except the ~~stock options is recognized on~~CEO) was granted 16,800 Successor Company DSUs, which vest in quarterly installments over a ~~straight-line basis over the service~~one-year period of the award less awards forfeited. The fair value of the stock options was measured at the grant date using the Black-Scholes valuation model. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary offollowing the grant date. ~~To fulfill options exercised,~~The Successor Company DSUs will be settled in shares of New Common Stock upon the ~~Company will issue new shares.~~

~~The Company recorded 0 stock-based compensation costs related to stock options for~~Board member’s departure from the ~~three and nine months ended September 30, 2020, as compared to $4.0 million and $11.5 million for the three and nine months ended September 30, 2019, respectively. These costs were~~Company; thus, these DSUs may not be included in the ~~condensed consolidated statements of operations within the general~~Successor Company’s issued and ~~administrative expenses line item. As of September 30, 2020, there are 0 remaining unrecognized compensation costs related to the stock options granted to certain executives.~~

~~There was no stock option activity from January 1, 2020 through September 30, 2020. However, as of September 30, 2020, there was approximately 5.2 million~~ outstanding ~~and exercisable stock options with a weighted-average exercise price of $18.50.~~

~~Incentive Restricted Stock Units~~

~~Officers of the Company contributed 2.7 million~~ shares, of common stock to Extraction Employee Incentive, LLC (“Employee Incentive”), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock units (“Incentive RSUs”) to certain employees. Incentive RSUs vested over a three year service period, with 25%, 25% and 50% of the units vesting in year ~~one~~, ~~two~~ and three, respectively. On July 17, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested immediately and the remaining Incentive RSUs vest 25%, 25% and 25% each six months thereafter, over the remaining 18-month service period.potentially for several years. Grant date fair value was determined based on the value of the ~~Company's common stock on~~Successor Company’s New Common Stock pursuant to the ~~date~~terms of ~~issuance.~~the 2021 LTIP. The Company assumed a forfeiture rate of 0 as part of the grant date estimate of compensation cost.

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The Successor Company recorded ~~0 stock-based compensation costs related to Incentive RSUs for the three~~$0.5 million and ~~nine months ended September 30, 2020. The Company recorded 0 stock-based compensation costs related to Incentive RSUs for the three months ended September 30, 2019. The Company recorded $0.8~~$0.9 million of stock-based compensation costs related to ~~Incentive RSUs~~Successor Company DSUs for the ~~nine~~three months ended ~~September~~June 30, ~~2019.~~2021 and for the period from January 21, 2021 through June 30, 2021, respectively. These costs were included in the condensed consolidated statements of operations within the ~~general~~“General and administrative ~~expenses~~expense” line item. As of ~~September~~June 30, ~~2020,~~2021, there ~~are no remaining~~was $1.1 million of total unrecognized compensation ~~costs~~cost related to the ~~Incentive RSUs~~unvested Successor Company DSUs granted to certain ~~employees.~~directors that is expected to be recognized over a weighted average period of 0.6 years. The following table summarizes the Successor Company’s DSU activity for the period shown and provides information for the Successor Company’s DSUs outstanding at the dates indicated.


	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested Successor Company Deferred Stock Units at January 21, 2021	0	$	0
Granted	100,800	20.41
Forfeited	0	0
Vested	(25,200)	20.41
Non-vested Successor Company Deferred Stock Units June 30, 2021	75,600	$	20.41

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Note ~~12—~~10—Equity

Common Stock

On the Emergence Date, the Successor Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, the authority to issue a total of 950,000,000 shares of all classes of capital stock of which 900,000,000 shares are common stock, par value $0.01 per share (the “New Common Stock”) and 50,000,000 shares are preferred stock, par value $0.01 per share. Upon emergence from the Chapter 11 Cases, all existing shares of the Predecessor Common Stock and the Predecessor Preferred Stock were cancelled, and the Successor Company issued 25,703,212 shares of New Common Stock during the first quarter of 2021. During the second quarter of 2021, the Company issued 133,705 shares of New Common Stock to settle general unsecured claims. As of June 30, 2021, the Company expects to issue an additional 136,943 shares of New Common Stock to settle general unsecured claims. See Note 1—Business and Organization —Voluntary Reorganization under Chapter 11 of the Bankruptcy Code in the Company’s filed Form 10-Q from the first quarter of 2021 and Note 3—Fresh Start Reporting for more information.

Series A Preferred Stock

~~The~~In connection with emergence from the Chapter 11 Cases on January 20, 2021, and pursuant to the Plan, each share of the Predecessor Preferred Stock was canceled, released and extinguished, and is of no further force or effect.

Warrants

On the Emergence Date and pursuant to the Plan, the Successor Company entered into warrant agreements with American Stock Transfer & Trust Company, LLC, as warrant agent, which provided for (i) the Successor Company’s issuance of up to an aggregate of 2,905,567 Tranche A Warrants to purchase the New Common Stock (the “Tranche A Warrants”) to certain former holders of ~~our Series A Preferred~~the Predecessor Common Stock and (ii) the Successor Company’s issuance of up to an aggregate of 1,452,802 Tranche B warrants to purchase New Common Stock (the ~~"Series~~“Tranche B Warrants” and, together with the Tranche A ~~Preferred Holders"~~Warrants, the “New Warrants”) to certain former holders of the Predecessor Common Stock.

The Tranche A Warrants are ~~entitled to receive a cash dividend~~exercisable from the date of ~~5.875% per year, payable quarterly in arrears,~~issuance until the fourth anniversary of the Emergence Date, at which time all unexercised Tranche A Warrants will expire, and the rights of the holders of such warrants to purchase New Common Stock will terminate. The Tranche A Warrants are initially exercisable for one share of New Common Stock per Tranche A Warrant at an initial exercise price of $107.64 per Tranche A Warrant (the “Tranche A Exercise Price”).

The Tranche B Warrants are exercisable from the date of issuance until the fifth anniversary of the Emergence Date, at which time all unexercised Tranche B Warrants will expire, and the rights of the holders of such warrants to purchase New Common Stock will terminate. The Tranche B Warrants are initially exercisable for one share of New Common Stock per Tranche B Warrant at an initial exercise price of $122.32 per Tranche B Warrant (the “Tranche B Exercise Price” and together with the Tranche A Exercise Price, the “Exercise Prices”).

Pursuant to the warrant agreements, no holder of a New Warrant, by virtue of holding or having a beneficial interest in a New Warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of the Successor Company’s directors or any other matter, or exercise any rights whatsoever as a stockholder of the Successor Company ~~has the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately~~unless, until and only to the extent such ~~quarterly dividends are partially paid in cash). The Company has paid the quarterly dividends in kind from the fourth quarter~~holders become holders of ~~2019 until the filing~~record of shares of New Common Stock issued upon settlement of the Chapter 11 Cases. Because certain provisions within the RSA and the DIP Credit Agreement restrict the Company's ability to declare a dividend, the Company has not made any dividend payments on the Series A Preferred Stock since the commencement of the Chapter 11 Cases. The Series A Preferred Stock is convertible into shares of our common stock at the election of the Series A Preferred Holders at a conversion ratio per share of Series A Preferred Stock of 61.9195. Until the three-year anniversary of the closing of the IPO, the Company could elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of our common stock had traded at or above a certain premium to our initial offering price, such premium to decrease with time. On October 15, 2019, the three year anniversary had passed for the Series A Preferred Stock to convert into our common stock. Prior to the commencement of the Chapter 11 Cases, the Company could have redeemed the Series A Preferred Stock for the liquidation preference, which was $198.7 million on June 14, 2020. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock matures on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference to the extent there are legally available funds to do so. For more information, see the Company’s Annual Report.New Warrants.

~~Elevation~~The number of shares of New Common ~~Units~~Stock for which a New Warrant is exercisable, and the Exercise Prices, are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of New Common Stock or a reclassification in respect of New Common Stock.

On May 1, 2020, Elevation's board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation's members other than Extraction through the Capital Raise. The Capital Raise caused Extraction's ownership of Elevation to be diluted to less than 0.01%. As a resultUpon completion of the ~~Capital Raise, beginning~~BCEI Merger, the current warrant structure described above could result in ~~May 2020 Extraction began accounting for Elevation under the cost method of accounting. The Company reserves all rights related to actions taken by Elevation’s board of managers.~~

~~Elevation Preferred Units~~

~~In July 2018 and July 2019, respectively, Elevation sold 150,000 and 100,000 of Elevation Preferred Units at~~ a price of $990 per unit to a third party (the "Purchaser"). The aggregate liquidation preference when the units were sold was $150.0 million and $100.0 million, respectively. These Preferred Units represent the noncontrolling interest presented on the condensed consolidated balance sheets, condensed consolidated statements of operations and condensed consolidated statements of changes in stockholders' equity and noncontrolling interest for periods ended on or prior to December 31, 2019. As part of the July 2018 transaction, the Company committed to Elevation that it would drill at least 425 qualifying wells in the acreage dedicated to Elevation by December 31, 2023, subject to reductions if Elevation does not invest the full amount of capital as initially anticipated. Pursuant to the Fourth Amendment to the Elevation Gathering Agreements between Elevation and Extraction, this drilling commitment would be eliminated, if and only if all Elevation Preferred Units have been redeemed in full or are otherwise no longer outstanding. Please see ~~Note 14—Commitments and Contingencies — Elevation Gathering Agreements~~ ~~for further details~~.

~~Upon deconsolidation of Elevation Midstream, LLC as discussed in~~ ~~Note 1—Business and Organization -Deconsolidation of Elevation Midstream, LLC, the $270.5 million Elevation preferred unit balance in the noncontrolling interest line item of the condensed consolidated balance sheets as of March 31, 2020 was removed. The amount~~modification.

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comprises the line item effects of deconsolidation of Elevation Midstream, LLC on the condensed consolidated statements of changes in stockholders' equity and noncontrolling interest as of March 31, 2020.

During the twenty-eight months following the July 3, 2018 Preferred Unit closing date, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $250.0 million commitment. For the three months ended September 30, 2020, due to the deconsolidation of Elevation during the first quarter of 2020, the Company's condensed consolidated statements excluded all commitment fees paid-in-kind from the Preferred Unit commitment fees and dividends paid-in-kind line item in the condensed consolidated statements of changes in stockholders' equity and noncontrolling interest. For the three months ended September 30, 2019, Elevation recognized $0.7 million of commitment fees paid-in-kind. For the nine months ended September 30, 2020 and 2019, respectively, Elevation recognized $0.6 million and $2.4 million of commitment fees paid-in-kind.

The Elevation Preferred Units entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. The Dividend is currently payable solely in cash. For the three months ended September 30, 2020, due to the deconsolidation of Elevation during the first quarter of 2020, the Company's condensed consolidated statements excluded all dividends paid-in-kind from the Preferred Unit commitment fees and dividends paid-in-kind line item in the condensed consolidated statements of changes in stockholders' equity and noncontrolling interest. For the three months ended September 30, 2019, Elevation recognized $5.2 million of dividends paid-in-kind. For the nine months ended September 30, 2020 and 2019, respectively, Elevation recognized $5.5 million and $11.5 million of dividends paid-in-kind.

Note ~~13—~~11—Earnings (Loss) Per Share

Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings of the Company.

The Company uses the “if-converted” method to determine potential dilutive effects of the Company’s outstanding Series A Preferred Stock and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards and stock options. The basic weighted average shares outstanding calculation is based on the actual days in which the shares were ~~outstanding for the three and nine months ended September 30, 2020 and 2019.~~

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outstanding. The components of basic and diluted ~~EPS~~earnings (loss) per share (“EPS”) were as follows (in thousands, except per share data):


											Successor		Predecessor
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,					For the Three Months Ended June 30,		For the Three Months Ended June 30,
		2020		2019		2020		2019			2021		2020
Basic and Diluted Income (Loss) Per Share	Basic and Diluted Income (Loss) Per Share									Basic and Diluted Income (Loss) Per Share
Net income (loss)	Net income (loss)	$	(540,607)	$	33,924	$	(823,504)	$	(16,664)	Net income (loss)	$	24,544	$	(291,934)
Less: Noncontrolling interest		0		(5,776)		(6,160)		(13,849)

Less: Adjustment to reflect Series A Preferred Stock dividends	Less: Adjustment to reflect Series A Preferred Stock dividends	0		(2,721)		(8,749)		(8,164)		Less: Adjustment to reflect Series A Preferred Stock dividends	0		(4,001)
Less: Adjustment to reflect accretion of Series A Preferred Stock discount	Less: Adjustment to reflect accretion of Series A Preferred Stock discount	(1,865)		(1,682)		(5,452)		(4,915)		Less: Adjustment to reflect accretion of Series A Preferred Stock discount	0		(1,817)
Adjusted net income (loss) available to common shareholders, basic and diluted	Adjusted net income (loss) available to common shareholders, basic and diluted	$	(542,472)	$	23,745	$	(843,865)	$	(43,592)	Adjusted net income (loss) available to common shareholders, basic and diluted	$	24,544	$	(297,752)
Denominator:
Weighted average common shares outstanding, basic and diluted (1) (2)		138,348		137,789		138,080		155,847
Denominator										Denominator
Weighted average common shares outstanding, basic(1)(2)										Weighted average common shares outstanding, basic(1)(2)	25,777		138,163
Weighted average common shares outstanding, diluted										Weighted average common shares outstanding, diluted	26,429		138,163
Income (Loss) Per Common Share	Income (Loss) Per Common Share									Income (Loss) Per Common Share
Basic and diluted		$	(3.92)	$	0.17	$	(6.11)	$	(0.28)
Basic										Basic	$	0.95	$	(2.16)
Diluted										Diluted	$	0.93	$	(2.16)

_______________

(1)For the three ~~and nine~~ months ended ~~September~~June 30, 2021, 651,924 dilutive shares, including restricted stock units, performance stock units and deferred stock units outstanding, were included in the calculation above.

(2) For the three months ended June 30, 2020, ~~6,448,989~~6,532,472 potentially dilutive shares, including restricted stock awards and stock options outstanding, were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 11,472,445 common shares associated with the assumed conversion of ~~Series A~~Predecessor Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.

~~(2)~~

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	Successor		Predecessor
	For the Period from January 21 through June 30,		For the Period from January 1 through January 20,		For the Six Months Ended June 30,
	2021		2021		2020
Basic and Diluted Income (Loss) Per Share
Net income (loss)	$	113,098	$	870,970	$	(282,897)
Less: Noncontrolling interest	0		0		(6,160)
Less: Adjustment to reflect Series A Preferred Stock dividends	0		0		(8,749)
Less: Adjustment to reflect accretion of Series A Preferred Stock discount	0		(418)		(3,587)
Adjusted net income (loss) available to common shareholders, basic and diluted	$	113,098	$	870,552	$	(301,393)
Denominator
Weighted average common shares outstanding, basic(1)(2)(3)	25,655		136,589		137,945
Weighted average common shares outstanding, diluted	26,262		136,589		137,945
Income (Loss) Per Common Share
Basic	$	4.41	$	6.37	$	(2.18)
Diluted	$	4.31	$	6.37	$	(2.18)

_______________

(1) For the ~~three~~period from January 21, 2021 through June 30, 2021, 607,273 dilutive shares, including restricted stock units, performance stock units and ~~nine months ended September 30, 2019, 8,956,812~~deferred stock units outstanding, were included in the calculation above.

(2) For the period from January 1, 2021 to January 20, 2021, 7,138,153 potentially dilutive shares, including restricted stock awards and stock options outstanding, were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 11,472,445 common shares associated with the assumed conversion of ~~Series A~~Predecessor Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.

(3) For the six months ended June 30, 2020, 6,532,472 potentially dilutive shares, including restricted stock awards and stock options outstanding, were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 11,472,445 common shares associated with the assumed conversion of Predecessor Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.

Note ~~14—~~12—Commitments and Contingencies

~~Chapter 11 Cases~~

On June 14, 2020, the Company filed the Chapter 11 Cases seeking relief under the Bankruptcy Code. The Company continues to operate its business and manage its properties in the ordinary course of business pursuant to the applicable provisions of the Bankruptcy Code. In addition, commencement of the Chapter 11 Cases automatically stayed all of the proceedings and actions against the Company (other than regulatory enforcement matters), including those noted below. Please refer to ~~Note 1—Business and Organization~~ ~~for more information on the Chapter 11 Cases.~~

General

As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost, or the Company may be required to pay damages if certain performance conditions are not met.

Drilling Rigs

As of June 30, 2021, the Company was subject to no drilling rig commitments.

Leases

The Company has entered into operating leases for certain ~~office facilities,~~ compressors and office equipment. In connection with the Chapter 11 Cases, the Company filed a motion to reject its drilling rig contracts effective June 14, 2020. For one of the contracts, the rejection resulted in the removal of the lease liabilityfacilities and ~~net right-of-use asset in the amount of $6.7 million from the condensed consolidated balance sheets.~~equipment. Maturities of operating lease liabilities associated with right-of-use assets and including imputed interest were as follows (in thousands):


	Successor
	As of June 30, 2021
2021 - remaining	$	4,537
2022	3,592
2023	701
2024	0
Thereafter	0
Total lease payments	8,830
Less imputed interest(1)	(402)
Present value of lease liabilities	$	8,428

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As of September 30,
2020 As of December 31,
2019
2020 - remaining $ 836 2020 $ 19,040
2021 3,045 2021 5,247
2022 2,670 2022 2,211
2023 2,450 2023 2,246
2024 2,301 2024 2,301
Thereafter 8,273 Thereafter 8,273
Total lease payments 19,575 Total lease payments 39,318
Less imputed interest (1)
(2,347)
Less imputed interest (1)
(4,735)
Present value of lease liabilities (2)
$ 17,228
Present value of lease liabilities (2)
$ 34,583
_______________

(1) Calculated using the estimated interest rate for each lease.

(2) Of the total present value of lease liabilities as of September 30, 2020 and December 31, 2019, $3.2 million and $17.4 million, respectively, were recorded in accounts payable and accrued liabilities and $14.0 million and $17.2 million, respectively, were recorded in other non-current liabilities on the condensed consolidated balance sheets.

~~Drilling Rigs~~

~~As of September 30, 2020, the Company was not subject to commitments on any drilling rigs. As part of Chapter 11, the Company filed a motion to reject its drilling rig contract.~~As such, the Company recorded $6.7 million in liabilities subject to compromise on the condensed consolidated balance sheets as of September 30, 2020 and in reorganization items, net on the condensed consolidated statements of operations.

Delivery Commitments

As part of the Chapter 11 Cases, the Company is currently in the process of renegotiating certain contracts terms which include minimum volume commitments. If mutual terms cannot be reached, the Company under Chapter 11 may file a motion to reject the contract.

On November 2, 2020, the Bankruptcy Court ruled in favor of the Company rejecting several midstream contracts. As a result of these rejected contracts, the Company accrued $405.2 million within liabilities subject to compromise on the condensed consolidated balance sheets as of September 30, 2020 and in reorganization items, net on the condensed consolidated statements of operations for the three and nine months ended September 30, 2020.

The Company was subject to a firm transportation agreement that commenced in November 2016 and had a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. Until June 2020, these were obligations of the Company’s oil marketer, which reverted back to the Company when the oil marketing contract terminated in June 2020. In May 2017, the Company amended its agreement with its oil marketer that required it to sell all of its crude oil from an area of mutual interest in exchange for a make-whole provision that allowed the Company to satisfy any minimum volume commitment deficiencies incurred by its oil marketer with future barrels of crude oil in excess of their minimum volume commitment during the contract term. In May 2019, the Company extended the term of this agreement through October 31, 2020 subject to an evergreen provision thereafter where either party can provide a six month notice of termination beginning November 1, 2020. Due to the contract termination date, the amount of consideration recognized in revenue is reduced. Please see ~~Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements — Revenue — Contract Balances~~. On June 12, 2020, the Company and the transportation contract counterparty mutually terminated its contract with the Company's oil marketer effective June 30, 2020. The Company had posted a letter of credit for this agreement in the amount of $40.0 million and, as of September 30, 2020, the counterparty had drawn $24.3 million on the letter of credit.

After termination of the aforementioned contract with the oil marketer, the Company had a long-term crude oil delivery commitment agreement that commenced on July 1, 2020. As of September 30, 2020, the Company's long-term

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crude oil delivery commitment had a monthly minimum delivery commitment of 61,800 Bbl/d through October 2023 and then would reduce to 58,000 Bbl/d through October 2026. The Company was required to pay a shortfall fee for any volume deficiencies under these commitments. On November 2, 2020, the Bankruptcy Court ruled in favor of the Company rejecting this contract with an effective date as of June 14, 2020, and, therefore, the Company has no remaining minimum delivery commitments under this transportation contract. The counterparty to this contract has indicated that it plans on appealing the ruling approving of the rejection of the contract.

~~The Company had 2 long-term crude oil gathering commitments with two unconsolidated subsidiaries in which the Company has a de minimis minority ownership interest. Please see~~ ~~Note 1—Business and Organization~~ for information related to the deconsolidation of Elevation Midstream, LLC. The first agreement commenced in November 2016 and had a term of ten years with a minimum volume commitment of an average of 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The Company may have been required to pay a shortfall fee for any volume deficiencies under this commitment. The second agreement commenced in October 2019 and had a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. On November 2, 2020, the Bankruptcy Court ruled in favor of the Company rejecting both of these crude oil gathering contracts with an effective date as of June 14, 2020, and, therefore, the Company has no remaining minimum delivery commitments. The counterparties to these contracts have indicated that they plan on appealing the ruling approving of the rejection of these contracts.

~~In February 2019, the~~Predecessor Company entered into ~~two~~a long-term gas gathering and processing ~~agreements~~agreement (the “Gathering Agreement”) with a third-party midstream ~~providers. One of the agreements additionally includes a long-term NGL sales commitment for take-in-kind NGLs from other processing agreements.~~provider in February 2019. The ~~first agreement~~Gathering Agreement commenced in November 2019 and has a term of twenty years with a minimum volume commitment of 251 Bcf to be delivered within the first seven years. The annual commitments over seven years are to be delivered on an average 85,000 Mcf/d in year one, 125,000 Mcf/d in year two, 140,000 Mcf/d in year three, 118,000 Mcf/d in year four, 98,000 Mcf/d in year five, 70,000 Mcf/d in year six and 52,000 Mcf/d in year seven. The aggregate remaining amount of estimated payments under this agreement is approximately $281.5 million. The second agreement commenced on January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 ~~Bcf in years one through ten.~~Bcf. The ~~second agreement~~Gathering Agreement also includes a commitment to sell take-in-kind NGLs from other processing agreements of 4,000 Bbl/d in the first year ~~one~~of the Gathering Agreement and 7,500 Bbl/d in years two through seven of the Gathering Agreement with the ability to roll forward up to a 10% shortfall in a given month to the subsequent month. On December 23, 2020, the Predecessor Company and the counterparty entered into a settlement and amended the Gathering Agreement (the “Settlement and Amendment”). No changes were made to the Company’s annual minimum volume commitment as a result of the settlement and amendment.

~~The summary of these minimum volume commitments as of September 30, 2020, was as follows:~~

Oil (MBbl) Gas (MMcf) Total (MBOE)
2020 - remaining 2,466 10,260 4,176
2021 9,797 46,540 17,554
2022 8,944 49,758 17,237
2023 9,490 41,850 16,465
2024 9,516 34,160 15,209
Thereafter 29,860 40,260 36,570
Total 70,073 222,828 107,211

In ~~collaboration~~December 2016 and August 2017, the Predecessor Company agreed with several ~~other~~third-party producers and a midstream provider ~~on December 15, 2016 and August 7, 2017, the Company agreed~~ to ~~participate in expansions of~~expand natural gas gathering and processing capacity in the DJ ~~Basin. The plan includes~~Basin, including through the addition of 2 new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in August 2018 and the second plant commenced operations in July 2019. The Company’s share of these commitments ~~will require~~requires an incremental 51.5 and 20.6 MMcf per day, respectively, over a baseline volume of 65 MMcf per day ~~to be delivered after the plants' in-service dates~~ for a period of seven years ~~thereafter.~~following the in-service dates of the plants. The Company may be required to pay a shortfall fee for any incremental volume ~~deficiency~~deficiencies under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other third-party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold.

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In July 2019, the Company entered into 3 long-term contracts to supply 125,000 dekatherms of residue gas per day for five years to a transportation company. The aggregate remaining amount of estimated commitment assuming no production is $27.5 million. The Company has posted a letter of credit for this agreement in the amount of $8.7 million.

The Company is considering rejecting certain midstream contracts with minimum volume commitments as part of the Chapter 11 Cases. The aggregate amount of estimated remaining payments under agreements that have not been rejected is $309.0 million.

~~Elevation Gathering Agreements~~

In July 2018, the Company entered into three long-term gathering agreements (the "Elevation Gathering Agreements") for gas, crude oil and produced water with Elevation. Under the agreements, the Company agreed to drill 100 wells in Broomfield and 325 wells in Hawkeye by December 31, 2023 if both facilities are to be built, subject to adjustments if less capital is spent. Elevation has alleged that if the Company fails to complete the wells by the applicable commitment deadline, then it would be in breach of the agreement and Elevation could attempt to assert damages against Extraction and its affiliates. During the first quarter of 2020, Elevation postponed indefinitely further development of gathering systems and facilities that were to be constructed to service the Company's acreage in Hawkeye and another project in the Southwest Wattenberg area. Due to the decision to not complete the Hawkeye facilities and based on the amount of capital invested, Elevation has asserted that the drilling commitment now consists of 297 wells in the Broomfield area of operations with a deadline of December 31, 2022.

In April 2019, the Elevation Gathering Agreements were amended to provide for, among other amendments, the inclusion of additional gathering facilities that would produce into Elevation’s Badger facility. Pursuant to this amendment, Elevation has asserted that the additional gathering facilities were required to be completed by April 1, 2020 or, within 30 days of such date, Elevation could assert that Extraction must make a payment to Elevation in the amount of 135% of all costs incurred by Elevation as of such date for the development and construction of such additional gathering facilities. As of September 30, 2020, the costs incurred by Elevation for these additional gathering facilities totaled $34.9 million. The Company did not cause the completion of these additional gathering facilities by April 1, 2020, and Elevation has alleged that Extraction is in breach of the Elevation Gathering Agreements. On April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. While the Company disputes that these amounts are due to Elevation, under ~~ASC Topic 450 - Contingencies~~, the Company recorded the amount in liabilities subject to compromise on the condensed consolidated balance sheet as of September 30, 2020 and in other operating expenses on the condensed consolidated statements of operations.

In December 2019, the Elevation Gathering Agreements were further amended to provide Elevation additional connection fees that are consistent with market terms (the "Connect Fees"). In the fourth quarter of 2019, the Company incurred and paid $19.5 million for Connect Fees pursuant to the Elevation Gathering Agreements, and in the first quarter of 2020 the Company incurred and paid $23.5 million. The Company does not expect to incur additional Connect Fees for the year ending December 31, 2020.

In March 2020, the Elevation Gathering Agreements were further amended to reset all gathering rates and eliminate existing minimum drilling commitment. This amendment will not become effective until after all Elevation Preferred Units have been redeemed in full or are otherwise no longer outstanding.

In November 2020, the Company and Elevation reached an agreement in principle regarding amendments to the gathering agreements and the settlement of outstanding claims. The Company anticipates finalizing the settlement in the fourth quarter of 2020, pending Bankruptcy Court approval. As part of the settlement, the Company will pay Elevation $38.4 million in cash over 24 months following the Company’s emergence from chapter 11 and both parties agreed Elevation will be allowed to submit an unsecured claim $80.0 million with the Bankruptcy Court. The agreement would also release certain areas from future dedication, provide a reduction in gathering fees, a reduction in the number of wells subject to the drilling commitment, and an extended term in order to satisfy the drilling commitment. The Company had previously accrued $46.8 million as discussed above and $2.9 million of accrued interest. Therefore, during the third quarter of 2020, the Company accrued $68.7 million within liabilities subject to compromise on the condensed

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~~consolidated balance sheets as of September 30, 2020 and in reorganization items, net on the condensed consolidated statements of operations for the three and nine months ended September 30, 2020.~~

Litigation and Legal Items

~~The~~From time to time, the Company is involved in various legal proceedings arising in the ordinary course of its business and reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the Company’s best interests. The Company has provided the necessary estimated accruals in the condensed consolidated balance sheets where deemed appropriate for litigation and ~~legal related~~legal-related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, the Company currently believes that the ultimate results of such proceedings will not have a material adverse effect on our business, financial position, results of operations or liquidity.

Environmental. Due to the nature of the oil and natural gas ~~and oil~~ industry, the Company is exposed to environmental ~~risks.~~liabilities in the ordinary course of its business. The Company has various policies and procedures in place to minimize and mitigate the risks from environmental contamination or with respect to environmental compliance issues. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as ~~discussed~~disclosed herein, the Company is not aware of any material environmental claims existing as of ~~September~~June 30, ~~2020 which~~2021 that have not been provided for or would otherwise have a material impact on ~~our~~the Company’s financial ~~statements; however,~~statements. However, there can be no assurance that current regulatory requirements will not change or that unknown

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potential past non-compliance with environmental laws, compliance matters or other environmental liabilities will not be discovered on our properties. ~~Accrued environmental liabilities are recorded in accounts payable and accrued liabilities on the condensed consolidated balance sheets.~~ The liability ultimately incurred with respect to a matter may exceed the related accrual.

COGCC Notices of Alleged Violations (“NOAVs”).. The Company ~~has~~previously received NOAVs from the Colorado Oil and Gas Conservation Commission (the ~~"COGCC"~~“COGCC”) for alleged compliance ~~violations~~violations. On July 27, 2021, the COGCC approved a global settlement agreement with the Company that resolves these NOAVs. The settlement agreement requires the Company to make a cash payment to the COGCC of $0.1 million and also contains an obligation that the Company ~~has responded to. At this time, the COGCC has not alleged any specific penalty amounts in these matters. The Company does not believe~~complete pubic projects that ~~any penalties that could result from these NOAVs~~ will ~~have a material effect on our business, financial condition, results of operations or liquidity, but they may exceed $100,000.~~

~~Midstream Connections.~~ ~~The Company had dedicated the production from some acreage to a certain midstream service provider. However,~~cost the Company was unable to connect well pads to the provider due to the inability to secure right of way access for building the connection pipeline. Because the acreage’s production was dedicated to the midstream provider, they have invoiced the Company for oil and gas handled by other midstream providers. The Company disputes these invoices based on force majeure and may have other contractual or legal defenses. The Company’s maximum exposure as of September 30, 2020 was $19.5approximately $0.5 million. ~~As of September 30, 2020, no contingent liability has been recorded as it is not probable a loss has been incurred, and the amount of the loss cannot be reasonably estimated.~~

~~Elevation Gathering.~~ ~~As discussed above under~~ ~~Elevation Gathering Agreements~~, on April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. While the Company disputes that these amounts are due to Elevation, under ~~ASC Topic 450 - Contingencies~~, the Company recorded the amount in liabilities subject to compromise on the condensed consolidated balance sheet as of September 30, 2020 and in other operating expenses on the condensed consolidated statements of operations.

~~Note 15—Related Party Transactions~~

~~Elevation Midstream, LLC~~

~~As discussed in~~ ~~Note 14—Commitments and Contingencies~~, on April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. While the Company disputes that these amounts are due to Elevation, under ~~ASC Topic 450 - Contingencies, the Company recorded the amount in liabilities subject to compromise on the condensed consolidated balance sheet as of September 30, 2020 and in other~~

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~~operating expenses on the condensed consolidated statements of operations. The Company also accrued $2.9 million of interest related to the aforementioned alleged breach in contract.~~

~~Note 16—Segment Information~~

Beginning in the fourth quarter of 2018, the Company had 2 operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction of and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Elevation Midstream, LLC comprised the gathering and facilities segment. During the three and nine months ending September 30 2019, the Company’s gathering and facilities segment was in the construction phase and no revenue generating activities had commenced. Through March 16, 2020, the results of Elevation were included in the condensed consolidated financial statements of Extraction. Effective March 17, 2020, the results of Elevation Midstream, LLC are no longer consolidated in Extraction's results; however, the Company’s prior quarter segment disclosures included the gathering and facilities segment because it was consolidated through March 16, 2020. Please see ~~Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC~~ ~~for further information related to the deconsolidation of Elevation Midstream, LLC. After March 31, 2020, the Company had a single reportable segment.~~

The following table presents a reconciliation of Adjusted EBITDAX by segment to the GAAP financial measure of income (loss) before income taxes for the three and nine months ended September 30, 2020 and 2019 (in thousands).

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2020 2019 2020 2019
Reconciliation of Adjusted EBITDAX to Income (Loss) Before Income Taxes
Exploration and production segment EBITDAX $ 98,308 $ 138,491 $ 334,986 $ 406,539
Gathering and facilities segment EBITDAX 0 (622) 1,256 (1,168)
Subtotal of Reportable Segments $ 98,308 $ 137,869 $ 336,242 $ 405,371
Less:
Depletion, depreciation, amortization and accretion $ (85,306) $ (114,996) $ (243,977) $ (352,134)
Impairment of long lived assets 0 0 (1,736) (11,233)
Other operating expenses (9,766) 0 (75,549) 0
Exploration and abandonment expenses (9,762) (13,245) (184,903) (32,725)
Gain on sale of property and equipment 0 1,011 0 1,329
Gain (loss) on commodity derivatives (9,673) 87,956 184,041 39,383
Settlements on commodity derivative instruments (14,045) (16,101) (180,770) 8,432
Premiums paid for derivatives that settled during the period 0 812 0 19,910
Stock-based compensation expense (1,902) (11,358) (4,462) (39,306)
Amortization of debt issuance costs (155) (974) (3,345) (3,799)
Gain on repurchase of 2026 Senior Notes 0 0 0 10,486
Interest expense (7,233) (22,250) (45,714) (61,478)
Loss on deconsolidation of Elevation Midstream, LLC 0 0 (73,139) 0
Reorganization items, net (501,073) — (527,992) —
Income (Loss) Before Income Taxes $ (540,607) $ 48,724 $ (821,304) $ (15,764)

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~~Financial information of the Company's reportable segments was as follows for the three months ended September 30, 2020 and 2019 (in thousands).~~

For the Three Months Ended September 30, 2020
Exploration and Production Gathering and Facilities Elimination of Intersegment Transactions Consolidated Total
Revenues:
Revenues from third parties $ 158,226 $ 0 $ 0 $ 158,226
Revenues from Extraction 0 0 0 —
Total Revenues $ 158,226 $ 0 $ 0 $ 158,226
Operating Expenses and Other Income (Expense):
Direct operating expenses $ (64,263) $ 0 $ 0 $ (64,263)
Depletion, depreciation, amortization and accretion (85,306) 0 0 (85,306)
Interest income 8 0 0 8
Interest expense (7,388) 0 0 (7,388)
Earnings in unconsolidated subsidiaries 0 0 0 0
Subtotal Operating Expenses and Other Income (Expense): $ (156,949) $ 0 $ 0 $ (156,949)
Segment Assets $ 2,370,571 $ 0 $ 0 $ 2,370,571
Capital Expenditures (1,320) 0 0 (1,320)
Investment in Equity Method Investees 0 0 0 0
Segment EBITDAX 98,308 0 0 98,308

For the Three Months Ended September 30, 2019
Exploration and Production Gathering and Facilities Elimination of Intersegment Transactions Consolidated Total
Revenues:
Revenues from third parties $ 176,942 $ 0 $ 0 $ 176,942
Revenues from Extraction 0 0 0 —
Total Revenues $ 176,942 $ 0 $ 0 $ 176,942
Operating Expenses and Other Income (Expense):
Direct operating expenses $ 0 $ 0 $ 0 $ 0
Depletion, depreciation, amortization and accretion (114,971) (25) 0 (114,996)
Interest income 114 355 0 469
Interest expense (23,224) 0 0 (23,224)
Earnings in unconsolidated subsidiaries 0 640 0 640
Subtotal Operating Expenses and Other Income (Expense): $ (138,081) $ 970 $ 0 $ (137,111)
Segment Assets $ 4,046,862 $ 395,224 $ (619) $ 4,441,467
Capital Expenditures 134,998 65,098 0 200,096
Investment in Equity Method Investees 0 35,992 0 35,992
Segment EBITDAX 138,491 (622) 0 137,869

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For the Nine Months Ended September 30, 2020
Exploration and Production Gathering and Facilities Elimination of Intersegment Transactions Consolidated Total
Revenues:
Revenues from third parties $ 385,068 $ 1,473 $ — $ 386,541
Revenues from Extraction 0 4,513 (4,513) —
Total Revenues $ 385,068 $ 5,986 $ (4,513) $ 386,541
Operating Expenses and Other Income (Expense):
Direct operating expenses $ (189,155) $ (3,935) $ 4,294 $ (188,796)
Depletion, depreciation, amortization and accretion (242,878) (1,099) 0 (243,977)
Interest income 78 29 0 107
Interest expense (49,059) 0 0 (49,059)
Earnings in unconsolidated subsidiaries 0 480 0 480
Subtotal Operating Expenses and Other Income (Expense): $ (481,014) $ (4,525) $ 4,294 $ (481,245)
Segment Assets $ 2,370,571 $ 0 $ 0 $ 2,370,571
Capital Expenditures 168,382 (6,311) 0 162,071
Investment in Equity Method Investees 0 0 0 0
Segment EBITDAX 334,986 1,256 0 336,242

For the Nine Months Ended September 30, 2019
Exploration and Production Gathering and Facilities Elimination of Intersegment Transactions Consolidated Total
Revenues:
Revenues from third parties $ 620,916 $ 0 $ 0 $ 620,916
Revenues from Extraction 0 0 0 —
Total Revenues $ 620,916 $ 0 $ 0 $ 620,916
Operating Expenses and Other Income (Expense):
Direct operating expenses $ 0 $ 0 $ 0 $ 0
Depletion, depreciation, amortization and accretion (352,062) (72) 0 (352,134)
Interest income 372 1,286 0 1,658
Interest expense (54,791) 0 0 (54,791)
Earnings in unconsolidated subsidiaries 0 1,179 0 1,179
Subtotal Operating Expenses and Other Income (Expense): $ (406,481) $ 2,393 $ 0 $ (404,088)
Segment Assets $ 4,046,862 $ 395,224 $ (619) $ 4,441,467
Capital Expenditures 516,510 192,568 0 709,078
Investment in Equity Method Investees 0 35,992 0 35,992
Segment EBITDAX 406,539 (1,168) 0 405,371

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report ~~on Form 10-Q (“Quarterly Report”)~~ contains ~~"forward-looking~~“forward-looking statements."” All statements, other than statements of historical facts, included or incorporated by reference herein concerning, among other things, the BCEI Merger and Crestone Peak Merger, any statements regarding the expected timetable for completing the BCEI Merger and Crestone Peak Merger, the results, effects, benefits and synergies of the BCEI Merger and Crestone Peak Merger, future opportunities for the combined company, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as ~~''may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," ''will," "continue," ''potential," "should," "could,"~~“'may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

•~~potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations;~~

•~~objections to the confirmation of our Restructuring Plan or other pleadings we file that could protract the Chapter 11 Cases;~~

•our ability to ~~continue as a going concern;~~

•execute on our ~~ability to comply with the restrictions and other covenants imposed by our DIP Credit Agreement and other financial arrangements;~~business strategy following emergence from bankruptcy;

•the ~~Bankruptcy Court’s rulings in the Chapter 11 Cases,~~COVID-19 pandemic, including its effects on commodity prices, downstream capacity, employee health and ~~the outcome of the Chapter 11 Cases generally;~~

•~~the length of time that we will operate under Chapter 11 protection~~safety, business continuity and ~~the continued availability of operating capital during the pendency of the proceedings;~~regulatory matters;

•federal and state regulations and laws;

•capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

•risks and restrictions related to our debt agreements;

•impact of political and regulatory developments in Colorado, particularly with respect to additional permit scrutiny;

•our ability to use derivative instruments to manage commodity price risk;

•realized oil, natural gas and NGL ~~prices;~~prices as well as the volatility and widening of differentials;

•a decline in oil, natural gas and NGL production, and the impact of general economic conditions on the demand for oil, natural gas and NGL and the availability of ~~capital to oil and natural gas producers;~~capital;

•asset impairments from commodity price declines;

•~~the outbreak of communicable diseases such as coronavirus;~~

•the willingness of the Organization of Petroleum Exporting Countries (“OPEC”) ~~and certain other oil and natural gas producing countries~~ to set and maintain production levels;

•unsuccessful drilling and completion activities and the possibility of resulting write-downs;

•geographical concentration of our operations;

•constraints in the DJ Basin of Colorado with respect to gathering, transportation and processing facilities and marketing;

•~~lack of U.S. domestic storage;~~

•our ability to meet our proposed drilling schedule and to successfully drill wells that produce oil or natural gas in commercially viable quantities;

•seasonal weather conditions.

•shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;

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•adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

•incorrect estimates associated with properties we acquire relating to estimated proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of such acquired properties;

•drilling operations associated with the employment of horizontal drilling techniques, and adverse weather and environmental conditions;

•limited control over non-operated properties;

•title defects to our properties and inability to retain our leases;

•our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;

•our ability to retain key members of our senior management and key technical employees;

•cost of pending or future litigation;

•risks relating to managing our growth, particularly in connection with the BCEI Merger and Crestone Peak Merger and integration of other significant acquisitions;

•impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

•~~risks associated with a material weakness in our internal control over financial reporting;~~

•changes in tax laws;

•effects of competition; and

•~~seasonal weather conditions.~~the outbreak of communicable diseases such as coronavirus.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGL that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers and management. In addition, the

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results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGL that are ultimately recovered.

In addition to the other information and risk factors set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” included in Item 1A of this Quarterly Report, ~~on Form 10-Q and our~~in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2019 (our “Annual~~2020

(“Annual Report”), and in ~~our~~the Company’s other filings with the Securities and Exchange Commission, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this Quarterly Report. Except as required by law, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. MD&A should be read in conjunction with the ~~Condensed Consolidated Financial Statements~~condensed consolidated financial statements and related ~~Notes~~notes included in ~~Part I,~~ Item 1 of this Quarterly Report. The following information updates the discussion of the Company’s financial condition provided in ~~our~~its Annual Report and analyzes the changes in the results of operations between the three and ~~nine~~combined six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019.~~the three and six months ended June 30, 2020.

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EXECUTIVE SUMMARY

We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves ~~as well as the construction and support of midstream assets to gather crude oil, natural gas and water production~~ in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin of Colorado. We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development drilling opportunities on high resource-potential leasehold on contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin.

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Financial Results

Our results of operations as reported in our condensed consolidated financial statements for the periods January 21, 2021 through June 30, 2021 (“Successor”), January 1, 2021 through January 20, 2021 (“Predecessor”), three months ended June 30, 2021 (“Successor”), and the three and six months ended June 30, 2020 (“Predecessor”) are in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Although GAAP requires that we report on our results for the Successor and Predecessor periods separately, management views our operating results for the combined six months ended June 30, 2021 by combining the results of the Predecessor and Successor periods because management believes such presentation provides the most meaningful comparison of our results to prior periods. We are not able to compare the 20 days from January 1, 2021 through January 20, 2021 operating results to any of the previous periods reported in the condensed consolidated financial statements and do not believe reviewing this period in isolation would be useful in identifying any trends in or reaching any conclusions regarding our overall operating performance. We believe the key performance indicators such as operating revenues and expenses for the Successor period combined with the Predecessor period provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no changes in policies between the periods and any material impacts as a result of fresh start reporting were included within the discussion of these changes. These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, but are presented because we believe they provide the most meaningful comparison of our results to prior periods.

For the three and ~~nine~~combined six months ended ~~September~~June 30, ~~2020,~~2021, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, ~~decreased~~increased to ~~$172.3~~$204.4 million and ~~$471.2~~$486.2 million, respectively, as compared to ~~$192.3~~$94.5 million and ~~$592.6~~$299.0 million, respectively, in the same prior year period due to ~~a decrease~~an increase of ~~$4.50~~$17.95 and ~~$7.87,~~$18.64, respectively, in realized price per BOE, including settled derivatives, partially offset by ~~an increase~~a decrease in sales volumes of approximately ~~620~~1,347 MBoe and ~~2,742~~3,480 MBoe, respectively.

For the three and ~~nine~~combined six months ended ~~September~~June 30, ~~2020,~~2021, we had a net ~~loss~~income of ~~$540.6~~$24.5 million and ~~$823.5~~$984.1 million, respectively, as compared to ~~net income of $33.9 million and~~ a net loss of ~~$16.7~~$291.9 million and $282.9 million, respectively, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. The change to net income for the three months ended June 30, 2021 from a net loss for the three months ended ~~September~~June 30, 2020 ~~from net income for the three months ended September 30, 2019~~ was primarily driven by ~~a decrease~~an increase in sales revenues of ~~$18.7~~$160.5 million, ~~a decrease in commodity derivative gains of $97.7 million and an increase in reorganization items, net of $501.1 million partially offset by~~ a decrease in operating expenses of ~~$13.6~~$122.2 million, a decrease in ~~interest expense~~reorganization items, net of ~~$15.8~~$26.9 million and a decrease of $18.1 million in interest expense, partially offset by an increase in income tax expenses of ~~$14.8~~$4.8 million. The ~~increase in~~change to net income for the combined six months ended June 30, 2021 from a net loss for the ~~nine~~six months ended ~~September~~June 30, 2020 ~~as compared to the nine months ended September 30, 2019~~ was primarily driven by ~~a decrease~~an increase in sales revenues of ~~$234.4~~$287.8 million, ~~an increase~~a decrease in ~~the loss from deconsolidation~~operating expenses of ~~$73.1~~$307.4 million, an increase in reorganization items, net of ~~$528.0~~$900.8 million, a decrease in the loss on deconsolidation of Elevation of $73.1 million and a decrease of $34.9 million in interest expense, partially offset by a decrease in commodity derivative gains of $310.6 million and an increase in ~~operating~~income tax expenses of ~~$117.7 million partially offset an increase in commodity derivative gains of $144.6~~$25.9 million.

Adjusted EBITDAX was ~~$98.3~~$150.1 million and ~~$336.2~~$357.3 million, respectively, for the three and ~~nine~~combined six months ended ~~September~~June 30, ~~2020~~2021 as compared to ~~$137.9~~$114.0 million and ~~$405.4~~$237.9 million, respectively, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, reflecting a ~~28.7%~~32% increase and ~~a 17.1% decrease,~~50% increase, respectively. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please refer to “—Adjusted EBITDAX.”

Operational Results

During the three and combined six months ended ~~September~~June 30, ~~2020,~~2021, we ~~suspended~~focused on improving free cash flow and implemented operational efficiencies to reduce drilling and ~~completions operations to reduce capital expenditures and did not incur significant drilling,~~ completion ~~or leasehold expenditures.~~costs. During the ~~nine~~three months ended ~~September~~June 30, ~~2020,~~2021, we incurred approximately ~~$154.6~~$47.3 million in drilling 379 gross ~~(26.5~~(6.4 net) wells with an average lateral length of ~~2.3~~2.1 miles and completing 4124 gross ~~(31.7~~(14.9 net) wells with an average lateral length of ~~2.4~~2.2 miles. In addition, we incurred approximately $3.4 million of leasehold and surface acreage additions. We turned 22 gross (16.3 net) wells to sales during the three months ended June 30, 2021.

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During the combined six months ended June 30, 2021, we incurred approximately $78.8 million in drilling 20 gross (12.5 net) wells with an average lateral length of 2.2 miles and completing 39 gross (26.7 net) wells with an average lateral length of 2.2 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately ~~$13.8~~$4.6 million of leasehold and surface acreage additions. We turned 22 gross (16.3 net) wells to sales ~~49 gross (36.6 net) wells with an average lateral length of approximately 2.4 miles.~~during the combined six months ended June 30, 2021.

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Recent Developments

Emergence from Chapter 11 ~~Cases~~Bankruptcy

~~On June 14, 2020, we commenced voluntary cases under chapter 11 of the Bankruptcy Code. Also~~As previously disclosed, on June 14, 2020 ~~we entered into a restructuring support agreement with certain holders~~(the “Petition Date”), Extraction and its wholly owned subsidiaries (collectively, the “Debtors”), filed voluntary petitions for relief under chapter 11 (“Chapter 11”) of ~~our Senior Notes to support a restructuring in accordance with~~title 11 of the ~~terms set forth therein. We expect to continue operations~~United States Code (the “Bankruptcy Code”) in the ~~normal course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the~~United States Bankruptcy Court for ~~certain “first day” motions, including motions to obtain customary relief intended to assure our ability to continue our ordinary course operations after~~ the ~~filing date. For more information on the~~District of Delaware (the “Bankruptcy Court”). The Debtors’ Chapter 11 ~~Cases and related matters, please see~~cases (the “Chapter 11 Cases”) were jointly administered under the caption In ~~Note 1—Business and Organization~~re Extraction Oil & Gas., et al. ~~in Part I, Item 1. Financial Information of this Quarterly Report.~~Case No. 20-11548 (CSS).

~~Elevation Gathering Agreements~~

In November 2020, the Company and Elevation reached an agreement in principle regarding amendments to the gathering agreements and the settlement of outstanding claims. The Company anticipates finalizing the settlement in the fourth quarter of 2020, pending Bankruptcy Court approval. As part of the settlement, the Company will pay Elevation $38.4 million in cash over 24 months following the Company’s emergence from chapter 11 and both parties agreed Elevation will be allowed to submit an unsecured claim of $80.0 million with the Bankruptcy Court. The agreement would also release certain areas from future dedication, provide a reduction in gathering fees, a reduction in the number of wells subject to the drilling commitment, and an extended term in order to satisfy the drilling commitment. We accrued $46.8 million discussed at ~~Note 14—Commitment and Contingencies~~ in Part I, Item 1. Financial Information of this Quarterly Report and $2.9 million of accrued interest. Therefore, during the third quarter of 2020, we accrued $68.7 million within liabilities subject to compromise on the condensed consolidated balance sheets as of September 30, 2020 and in reorganization items, net on the condensed consolidated statements of operations for the three and nine months ended September 30, 2020.

~~Rejection of Midstream Contracts~~

On July 30, 2020, the Debtors filed a proposed Plan of Reorganization (as amended, modified, or supplemented from time to time, the “Plan”) and related Disclosure Statement (as amended or modified, the “Disclosure Statement”) describing the Plan and the solicitation of votes to approve the same from certain of the Debtors’ creditors with respect to the Chapter 11 Cases. Subsequently on October 22, 2020 and November 2,5, 2020, the Debtors filed first and second amendments, respectively, to the Disclosure Statement. The hearing to consider approval of the Disclosure Statement was held on November 6, 2020. On November 6, 2020, the Bankruptcy Court ~~ruled in favor~~approved the adequacy of ~~Extraction rejecting certain transportation~~the Disclosure Statement and ~~gathering contracts with an effective date as of June 14, 2020 and August 11, 2020. As~~the Debtors commenced a ~~result of these rejections, we accrued $405.2 million within liabilities subject~~solicitation process to ~~compromise~~obtain votes on the ~~condensed consolidated balance sheets as~~Plan. The Plan was confirmed by order of ~~September 30,~~the Bankruptcy Court on December 23, 2020 (the “Confirmation Order”). On January 20, 2021 (the “Emergence Date”), the Plan became effective in accordance with its terms and ~~in reorganization items, net on~~ the ~~condensed consolidated statements of operations for~~Company emerged from the ~~three and nine months ended September 30, 2020.~~Chapter 11 Cases.

NASDAQ Delisting and Relisting

Our common stock was traded on the NASDAQ Global Select Market (the “NASDAQ”) under the symbol “XOG” ~~until~~prior to June 25, 2020. On March 30, 2020, we received a letter from the NASDAQ notifying us that we were not in compliance with the NASDAQ's rules that require the minimum bid price of our stock to be at least $1.00 per share over a consecutive 30-trading-day period. On June 16, 2020, we received a letter from ~~the~~ NASDAQ notifying us that ~~as a result of the chapter 11 Cases and~~ in accordance with NASDAQ rules, our securities would be delisted at the opening of business on June 25, 2020. On June 25, 2020, our common stock ~~commenced~~began trading on the Pink Open Market under the symbol “XOGAQ”. In connection with our emergence from the Chapter 11 Cases, our common stock was relisted on the NASDAQ on January 21, 2021 and began trading under the symbol “XOG.”

~~COVID-19 Outbreak~~Bonanza Creek Energy, Inc. Merger and ~~Global Industry Downturn~~Crestone Peak Merger

~~The recent worldwide outbreak in several countries, including the United States, of a highly transmissible and pathogenic coronavirus~~As previously disclosed, on May 9, 2021, Bonanza Creek Energy, Inc. (“~~COVID-19”~~Bonanza Creek”) and ~~the uncertainty regarding the impact~~Extraction signed a merger agreement (the “BCEI Merger Agreement”) for an all-stock merger of ~~COVID-19~~equals (the “BCEI Merger”). On June 6, 2021, Extraction entered into a merger agreement, by and ~~various governmental actions taken to mitigate the impact~~among Bonanza Creek, Raptor Condor Merger Sub 1, Inc., a Delaware corporation and a wholly owned subsidiary of ~~COVID-19 have resulted in an unprecedented decline in demand~~BCEI, Raptor Condor Merger Sub 2, LLC, a Delaware limited liability company and a wholly owned subsidiary of BCEI, Crestone Peak Resources LP, a Delaware limited partnership, CPPIB Crestone Peak Resources America Inc., a Delaware corporation (“Crestone Peak”), Crestone Peak Resources Management LP, a Delaware limited partnership (the “Crestone Peak Merger Agreement”). The Crestone Peak Merger Agreement, among other things, provides for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. Decreased demand from muchBonanza Creek’s acquisition of Crestone Peak (the “Crestone Peak Merger”). The closing of the ~~United States being~~Crestone Peak Merger is expressly conditioned on ~~lockdown~~the closing of the BCEI Merger. Upon completion of the BCEI Merger and Crestone Peak Merger, the combined company will be named Civitas Resources, Inc. (“Civitas”). Following the BCEI Merger and Crestone Peak Merger, Bonanza Creek President and Chief Executive Officer, Eric Greager, will serve as President and CEO of Civitas. Other senior leadership positions will be filled by current executives of Bonanza Creek and Extraction. As designated in the BCEI Merger agreement, of the six named officers, three will be from Bonanza Creek and three from Extraction. Extraction Chairman of the Board of Directors (“Board”), Ben Dell, will serve as Chairman of Civitas, and Bonanza Creek and Extraction will each nominate four directors, and CPP Investments will nominate one director to ~~prevent~~Civitas’ diverse, nine-member Board. We anticipate the ~~spread~~BCEI Merger will be completed during the latter half of ~~COVID-19 caused domestic storage capacity to begin to fill up~~2021.

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during March and April causing further price declines and ultimately causing oil prices to plummet. We expect the excess supply of oil and natural gas in the United States to continue for a sustained period.

The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to such operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected) and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Center for Disease Control. In addition, most of our non-operational employees are now working remotely. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak, nor have we had any confirmed cases of COVID-19 on any of our work sites.

Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we have recently reduced our operations in order to preserve capital. Specifically, as part of the Chapter 11 Cases, we have rejected our drilling rig contracts and certain equipment and compression agreements as discussed in ~~Note 14—Commitments and Contingencies~~ ~~in Part I, Item 1. Financial Information of this Quarterly Report.~~

~~Please also see Part II, Item 1A in our Annual Report and in this Quarterly Report for further information related to these matters.~~

~~Deconsolidation of Elevation Midstream, LLC~~

~~Please see~~ ~~Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC~~ ~~in Part I, Item 1. Financial Information of this Quarterly Report for information related to the deconsolidation of Elevation Midstream, LLC.~~

~~February 2020~~ Divestiture

In ~~February 2020,~~April 2021, we completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately ~~$12.2~~$15.2 million, subject to customary purchase price adjustments. No gain or loss was ~~recognized for~~recognized. In conjunction with the ~~February 2020 Divestiture. We continue to explore divestitures as part~~April 2021 divestiture,we recorded a receivable of ~~our ongoing initiative to divest non-strategic assets.~~

~~Elevation Common Units~~

On May 1, 2020, Elevation's board of managers issued 1,530,000,000 common units at a price of $0.01 per unit to certain of Elevation's members other than Extraction through the Capital Raise. The Capital Raise caused our ownership of Elevation to be diluted to less than 0.01%. As a result of the Capital Raise, beginning in May 2020 Extraction began accounting Elevation under the cost method of accounting. We reserve all rights related to actions taken by Elevation’s board of managers.

~~Midstream Projects~~

Primarily due to the significant decrease in oil and gas prices during March 2020, Elevation postponed indefinitely further development of gathering systems and facilities that were to be constructed to service our acreage in Hawkeye and another projectapproximately $2.7 million in the ~~Southwest Wattenberg area.~~

~~Table~~condensed consolidated balance sheet as of ~~Contents~~

~~Senate Bill 19-181 "Protect Public Welfare Oil and Gas Operations"~~

In April 2019, Senate Bill 19-181 ("SB181") became law, increasing the regulatory authority of local governments in Colorado over the surface impacts of oil and gas development in a necessary and reasonable manner, and in October 2020, Colorado's Air Quality Control Commission ("AQCC") adopted new rules targeting air emissions from upstream oil and gas operation. Among other things, SB181 (i) repeals a prior law restricting local government land use authority over oil and gas mineral extraction areas to areas designated by the COGCC, (ii) directs the AQCC to review its leak detection and repair rules and to adopt rules to minimize emissions of certain air pollutants, (iii) clarifies that local governments have authority to regulate the siting of oil and gas locations in a necessary and reasonable manner, including the ability to inspect oil and gas facilities, impose finesJune 30, 2021 for leaks, spills, and emissions, and impose fees on operators or owners to cover regulation and enforcement costs, (iv) allows local governments or oil and gas operators to request a technical review board to evaluate the effect of the local government’s preliminary or final determination on the operator’s application, (v) repeals an exemption for oil and gas production from counties’ authority to regulate noise, (vi) alters forced pooling requirements by increasing the threshold to compel non-consenting individuals into statutory pooling agreements and (vii) prioritizes the protection of public health, safety, and welfare, the environment, and wildlife resources in the regulation of oil and gas development. Although industry trade associations opposed SB181, Extraction has demonstrated an ability to continue to successfully operate our business. However, the enactment of SB181 and the development and implementation of related rules and regulations, which is under way, could lead to delays and additional costs to our business. Also, certain interest groups in Colorado opposed to oil and natural gas development generally have in previous years advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state.

Resulting from Colorado’s adoption of SB181 during 2019, the COGCC is currently in the process of promulgating rules associated with that legislation that, if passed, would, among other things, impose mandatory 2,000 foot setbacks for all schools and childcare centers, as well as new siting criteria for any oil and gas locations that are within 2,000 feet from residential building units. The rules additionally require local government permitting approval that could add additional timing and complexity burdens and curtail the pace of our new oil and gas development. A formal vote related to these proposed rules is expected to take place in late November 2020, and if passed, the new rules are expected to take effect on January 1, 2021.

Though these new siting zones add a number of new criteria for permitting, at this time, the promulgation of these rules has not resulted in any significant changes to our development plans. Extraction has all necessary state and local approvals for 116 permits to drill wells over the next several years. However, if additional regulatory measures are adopted, we could experience delays and/or curtailment in the permitting or pursuit of exploration, development or production activities. Such compliance requirements may lead to delays and additional costs to our operations and reduce the area available for future development of our operations. The discretion with which these new rules are interpreted and enforced by the new COGCC could additionally have a material adverse effect on our business, financial condition, and results of operations.post-closing adjustments.

~~Going Concern~~

~~Please see~~ ~~Note 1—Business and Organization — Ability to Continue as a Going Concern~~ ~~in Part I, Item 1. Financial Information and “Risk Factors” in Part II, Item 1A of this Quarterly Report, as well as “—Liquidity and Capital Resources” below.~~

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How We Evaluate Our Operations

We use ~~a variety of~~various financial and operational metrics to assess the performance of our ~~oil and gas~~ operations, including:

•Sources of revenue;

•Sales volumes;

•Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts;

•Lease operating ~~expenses (“LOE”);~~expenses;

•Capital expenditures;

•Adjusted EBITDAX (a ~~Non-GAAP~~non-GAAP measure); ~~and~~

•Free cash flow (a ~~Non-GAAP~~non-GAAP measure).; and

•Combined Predecessor period January 1, 2021 to January 20, 2021 and Successor period January 21, 2021 to June 30, 2021 (a non-GAAP measure) for comparison purposes in MD&A.

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the three months ended ~~September~~June 30, 2021, our revenues were derived 62% from oil sales, 18% from natural gas sales and 20% from NGL sales. For the three months ended June 30, 2020, our revenues were derived 58% from oil sales, 25% from natural gas sales and 17% from NGL sales. For the combined six months ended June 30, 2021, our revenues were derived 52% from oil sales, 32% from natural gas sales and 16% from NGL sales. For the six months ended June 30, 2020, our revenues were derived 71% from oil sales, ~~15%~~17% from natural gas sales and 14% from NGL sales. For the three months ended September 30, 2019, our revenues were derived 85% from oil sales, 10% from natural gas sales and 5% from NGL sales. For the nine months ended September 30, 2020, our revenues were derived 71% from oil sales, 16% from natural gas sales and 13% from NGL sales. For the nine months ended September 30, 2019, our revenues were derived 81% from oil sales, 12% ~~from natural gas sales and 7%~~ from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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Sales Volumes

The following table presents historical sales volumes for the periods indicated:

For the Three Months Ended For the Nine Months Ended
September 30, September 30,
2020 2019 2020 2019
Oil (MBbl) 2,818 3,597 9,741 10,830
Natural gas (MMcf) 18,277 14,418 54,823 43,433
NGL (MBbl) 2,146 1,390 6,031 4,097
Total (MBoe) 8,010 7,390 24,909 22,167
Average net sales (BOE/d) 87,068 80,327 90,909 81,198


	Successor	Predecessor
	For the Three Months Ended June 30,	For the Three Months Ended June 30,
	2021	2020
Oil (MBbl)	2,349	3,419
Natural gas (MMcf)	15,834	17,543
NGL (MBbl)	1,987	1,979
Total (MBoe)	6,975	8,322
Average net sales (BOE/d)	76,645	91,451


	Successor	Predecessor	Non-GAAP	Predecessor
	For the Period from January 21 through June 30,	For the Period from January 1 through January 20,	Combined Six Months Ended June 30,	For the Six Months Ended June 30,
	2021	2021	2021	2020
Oil (MBbl)	4,141	546	4,687	6,923
Natural gas (MMcf)	27,198	3,412	30,610	36,546
NGL (MBbl)	3,254	376	3,630	3,885
Total (MBoe)	11,927	1,492	13,419	16,899
Average net sales (BOE/d)	74,081	74,600	74,137	92,852

As reservoir pressures decline, production from a given well or formation decreases. Growth or maintenance in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please refer to “Risks Related to the Oil, Natural Gas and NGL Industry and Our Business” in Item ~~1A.~~1A of ~~our~~the Company’s Annual Report for a further description of the risks that affect us.

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Realized Prices on the Sale of Oil, Natural Gas and NGL

Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL and our ability to market our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period from January 1, ~~2014~~2019 to ~~September~~June 30, ~~2020,~~2021, NYMEX West Texas Intermediate (“WTI”) oil prices ranged from a high of ~~$107.26~~$74.05 per Bbl to a low of negative $37.63 per Bbl. ~~Average daily prices for~~ NYMEX Henry Hub gas prices ranged from a high of ~~$6.15~~$3.65 per MMBtu to a low of $1.48 per MMBtu during the same period. ~~Declines~~Fluctuations in ~~and continued depression of,~~ the price of oil and natural gas occurring during ~~2015,~~ 2019, 2020 and ~~2020~~2021 are due to a combination of factors including increased U.S. supply, global economic concerns stemming from COVID-19, ~~and~~ the price war between Russia and ~~Saudi Arabia.~~OPEC+, and the 2021 Texas Power crisis. These price ~~variations~~fluctuations can have a material impact on our financial results and capital expenditures.

Oil pricing is predominantly driven by ~~the physical market,~~fluctuations in supply and demand, including as a result of production and storage capacity, financial markets, and ~~national and international politics.~~geopolitical factors. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials.

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Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to dry natural gas with a low Btu content ~~dry natural gas~~ because it yields a greater quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The price we receive for our natural gas produced in the DJ Basin is based on CIG prices, adjusted for certain deductions.

Our price for NGL produced in the DJ Basin is based on a combination of prices from Mont Belvieu in Texas and the Conway hub in Kansas ~~and Mont Belvieu in Texas~~ where this production is marketed.

The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and ~~NGL~~NGLs normally ~~sells~~sell at a discount to the NYMEX WTI and NYMEX Henry Hub price, as applicable.

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		For the Three Months Ended						For the Nine Months Ended
		September 30,						September 30,							For the Three Months Ended June 30,						For the Six Months Ended June 30,
		2020			2019			2020			2019				2021			2020			2021			2020
Oil	Oil													Oil
NYMEX WTI High ($/Bbl)	NYMEX WTI High ($/Bbl)	$	43.39		$	62.90		$	63.27		$	66.30		NYMEX WTI High ($/Bbl)	$	74.05		$	40.46		$	74.05		$	63.27
NYMEX WTI Low ($/Bbl)	NYMEX WTI Low ($/Bbl)	$	36.76		$	51.09		$	(37.63)		$	46.54		NYMEX WTI Low ($/Bbl)	$	58.65		$	(37.63)		$	47.62		$	(37.63)
NYMEX WTI Average ($/Bbl)	NYMEX WTI Average ($/Bbl)	$	40.92		$	56.44		$	38.21		$	57.10		NYMEX WTI Average ($/Bbl)	$	66.10		$	28.00		$	62.21		$	36.82
Average Realized Price ($/Bbl)(1)	Average Realized Price ($/Bbl)(1)	$	39.41		$	41.99		$	27.88		$	46.31		Average Realized Price ($/Bbl)(1)	$	59.22		$	10.61		$	56.92		$	23.18
Average Realized Price, with derivative settlements ($/Bbl)(1)	Average Realized Price, with derivative settlements ($/Bbl)(1)	$	44.01		$	45.58		$	35.45		$	43.77		Average Realized Price, with derivative settlements ($/Bbl)(1)	$	50.60		$	18.11		$	50.27		$	31.97
Average Realized Price as a % of Average NYMEX WTI	Average Realized Price as a % of Average NYMEX WTI	96.3		%	74.4		%	73.0		%	81.1		%	Average Realized Price as a % of Average NYMEX WTI	89.6		%	37.9		%	91.5		%	63.0		%
Differential ($/Bbl) to Average NYMEX WTI(2)		$	(1.51)		$	(8.28)		$	(9.17)		$	(8.74)
Differential ($/Bbl) to Average NYMEX WTI(2)(3)														Differential ($/Bbl) to Average NYMEX WTI(2)(3)	$	(6.88)		$	(16.26)		$	(5.29)		$	(11.85)
Natural Gas	Natural Gas													Natural Gas
NYMEX Henry Hub High ($/MMBtu)	NYMEX Henry Hub High ($/MMBtu)	$	2.66		$	2.68		$	2.66		$	3.59		NYMEX Henry Hub High ($/MMBtu)	$	3.65		$	2.13		$	3.65		$	2.20
NYMEX Henry Hub Low ($/MMBtu)	NYMEX Henry Hub Low ($/MMBtu)	$	1.64		$	2.07		$	1.48		$	2.07		NYMEX Henry Hub Low ($/MMBtu)	$	2.46		$	1.48		$	2.45		$	1.48
NYMEX Henry Hub Average ($/MMBtu)	NYMEX Henry Hub Average ($/MMBtu)	$	2.12		$	2.33		$	1.92		$	2.56		NYMEX Henry Hub Average ($/MMBtu)	$	2.97		$	1.75		$	2.85		$	1.81
NYMEX Henry Hub Average converted to a $/Mcf basis(3)		$	2.33		$	2.56		$	2.11		$	2.82
Average Realized Price ($/Mcf)		$	1.34		$	1.17		$	1.14		$	1.71
Average Realized Price, with derivative settlements ($/Mcf)		$	1.40		$	1.33		$	1.34		$	1.69
Average Realized Price as a % of Average NYMEX Henry Hub(3)		57.5		%	45.7		%	54.0		%	60.6		%
Differential ($/Mcf) to Average NYMEX Henry Hub(3)		$	(0.99)		$	(1.39)		$	(0.97)		$	(1.11)
NYMEX Henry Hub Average converted to a $/Mcf basis(4)														NYMEX Henry Hub Average converted to a $/Mcf basis(4)	$	3.27		$	1.93		$	3.14		$	1.99
Average Realized Price ($/Mcf)(5)														Average Realized Price ($/Mcf)(5)	$	2.49		$	0.91		$	5.38		$	1.05
Average Realized Price, with derivative settlements ($/Mcf)(5)														Average Realized Price, with derivative settlements ($/Mcf)(5)	$	2.56		$	1.24		$	5.42		$	1.32
Average Realized Price as a % of Average NYMEX Henry Hub(4)(5)														Average Realized Price as a % of Average NYMEX Henry Hub(4)(5)	76.1		%	47.2		%	171.3		%	52.8		%
Differential ($/Mcf) to Average NYMEX Henry Hub(4)(5)														Differential ($/Mcf) to Average NYMEX Henry Hub(4)(5)	$	(0.78)		$	(1.02)		$	2.24		$	(0.94)
NGL	NGL													NGL
Average Realized Price ($/Bbl)		$	10.60		$	6.55		$	8.42		$	10.97
Average Realized Price as a % of Average NYMEX WTI		25.9		%	11.6		%	22.0		%	19.2		%
Average Realized Price ($/Bbl)(5)														Average Realized Price ($/Bbl)(5)	$	22.67		$	5.47		$	23.33		$	7.21
Average Realized Price as a % of Average NYMEX WTI(5)														Average Realized Price as a % of Average NYMEX WTI(5)	34.3		%	19.5		%	37.5		%	19.6		%
BOE	BOE													BOE
Average Realized Price per BOE(1)	Average Realized Price per BOE(1)	$	19.75		$	23.94		$	15.46		$	28.01		Average Realized Price per BOE(1)	$	32.06		$	7.59		$	38.46		$	13.42
Average Realized Price per BOE with derivative settlements	Average Realized Price per BOE with derivative settlements	$	21.51		$	26.01		$	18.86		$	26.73		Average Realized Price per BOE with derivative settlements	$	29.30		$	11.35		$	36.24		$	17.60

_______________

(1)Includes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the ~~nine~~three and six months ended ~~September~~June 30, 2020, ~~and for the three and nine months ended September 30, 2019,~~ pursuant to ASC Topic 606—Revenue ~~Recognition.~~Recognition (“ASC 606”).

(2)Excludes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the ~~nine~~three and six months ended ~~September~~June 30, 2020, ~~and for the three and nine months ended September 30, 2019,~~ pursuant to ASC ~~606, Revenue Recognition.~~606.

(3) During the first quarter of 2021, our renegotiated crude oil midstream contract was effective as of March 1, 2021, which resulted in a change in the accounting treatment under ASC 606. As a result, the crude oil differential for the combined six months ended June 30, 2021 is not reflective of our differential going forward.

(4) Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf using a conversion factor of 1.1 to 1.

(5) During the first quarter of 2021, a large portion of our gas and NGL contracts were subject to daily prices versus a monthly average price. As a result, our realized prices for the combined six months ended June 30, 2021 benefited from several days of severe cold during February 2021.

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Derivative Arrangements

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time, we enter into derivative arrangements for our oil and natural gas production. By removing a significant portion of price volatility associated with our oil and natural gas production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts. See “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

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We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We have relied on a variety of hedging strategies and instruments to hedge our future price risk. We have utilized swaps, put options and call options, which in some instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production. We expect to continue to use a variety of hedging strategies and instruments for the foreseeable future. The RBL Credit Agreement requires us to maintain commodity hedges covering a minimum of 65% of our anticipated oil and gas production from PDP reserves for the succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the next succeeding twelve months.

The hedge prices will depend on the commodity price environment at the time at which those hedge transactions are ~~entered into.~~entered. In the current commodity price environment, our ability to enter into derivative arrangements at favorable prices may be ~~limited, and, we are not obligated to hedge a specific portion of our oil or natural gas production.~~limited.

For a description of our derivative instruments that we utilize and a summary of our commodity derivative contracts as of ~~September~~June 30, ~~2020,~~2021, please see Note 7—5—Commodity Derivative Instruments in ~~Part I,~~ Item ~~1. Financial Information~~1 of this Quarterly Report.

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The following table summarizes our historical derivative positions and the settlement amounts for each of the periods ~~indicated.~~indicated:

For the Nine Months Ended
September 30,
2020 2019
NYMEX WTI Crude Swaps:
Notional volume (Bbl) 2,441,000 5,580,000
Weighted average fixed price ($/Bbl) $ 50.36 $ 52.55
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl) 4,950,000 15,800,000
Weighted average purchased put price ($/Bbl) $ 54.48 $ 46.59
NYMEX WTI Crude Purchased Calls:
Notional volume (Bbl) 1,100,000 14,000,000
Weighted average purchased call price ($/Bbl) $ 68.04 $ 64.99
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl) 5,650,000 17,750,000
Weighted average sold call price ($/Bbl) $ 63.37 $ 63.69
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl) 5,300,000 15,300,000
Weighted average sold put price ($/Bbl) $ 44.39 $ 44.33
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu) 22,000,000 23,400,000
Weighted average fixed price ($/MMBtu) $ 2.72 $ 2.83
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu) 600,000 3,600,000
Weighted average purchased put price ($/MMBtu) $ 2.90 $ 3.04
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu) 600,000 3,600,000
Weighted average sold call price ($/MMBtu) $ 3.48 $ 3.46
NYMEX HH Natural Gas Sold Puts:
Notional volume (MMBtu) — 3,000,000
Weighted average sold put price ($/MMBtu) $ — $ 2.50
CIG Basis Gas Swaps:
Notional volume (MMBtu) 24,600,000 31,100,000
Weighted average fixed basis price ($/MMBtu) $ (0.60) $ (0.73)
Total Amounts Received/(Paid) from Settlement (in thousands) $ 180,770 $ (8,432)
Cash used in changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives $ (7,713) $ (10,095)
Derivative unwinds reducing the Credit Facility balance $ (96,065) $ —
Settlements on Commodity Derivatives per Condensed Consolidated Statements of Cash Flows $ 76,992 $ (18,527)


	Successor		Predecessor		Predecessor
	For the Period from January 21 through June 30,		For the Period from January 1 through January 20,		For the Six Months Ended June 30,
	2021		2021		2020
NYMEX WTI Crude Swaps:
Notional volume (Bbl)	2,788,200		—		525,000
Weighted average fixed price ($/Bbl)	$	50.34	$	—	$	60.05
NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)	—		—		4,950,000
Weighted average purchased put price ($/Bbl)	$	—	$	—	$	54.48
NYMEX WTI Crude Purchased Calls:
Notional volume (Bbl)	—		—		1,100,000
Weighted average purchased call price ($/Bbl)	$	—	$	—	$	68.04
NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)	—		—		5,650,000
Weighted average sold call price ($/Bbl)	$	—	$	—	$	63.37
NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)	—		—		5,300,000
Weighted average sold put price ($/Bbl)	$	—	$	—	$	44.39
NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)	12,437,315		—		17,400,000
Weighted average fixed price ($/MMBtu)	$	2.94	$	—	$	2.75
NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)	—		—		600,000
Weighted average purchased put price ($/MMBtu)	$	—	$	—	$	2.90
NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)	—		—		600,000
Weighted average sold call price ($/MMBtu)	$	—	$	—	$	3.48
CIG Basis Gas Swaps:
Notional volume (MMBtu)	—		—		22,800,000
Weighted average fixed basis price ($/MMBtu)	$	—	$	—	$	(0.61)
Total Amounts Received/(Paid) from Settlement (in thousands)	$	(29,871)	$	—	$	166,725
Cash provided by (used in) changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives	8,703		542		(5,213)
Derivative unwinds reducing the Prior Credit Facility balance	—		—		(96,065)
Settlements on Commodity Derivatives per Condensed Consolidated Statements of Cash Flows	$	(21,168)	$	542	$	65,447

Lease Operating Expenses

All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constitutes part of the current operating expenses of a working interest. Such costs include labor, superintendence,

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supplies, repairs, maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

Capital Expenditures

For the ~~nine~~combined six months ended ~~September~~June 30, ~~2020,~~2021, we incurred approximately ~~$154.6~~$78.8 million in drilling and completion capital expenditures. For the ~~nine~~combined six months ended ~~September~~June 30, ~~2020,~~2021, we drilled 3720 gross ~~(26.5~~(12.5 net) wells with an average lateral length of approximately ~~2.3~~2.2 miles and completed 4139 gross ~~(31.7~~(26.7 net) wells with an average lateral

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length of approximately 2.2 miles. We turned to sales 22 gross (16.3 net) wells with an average lateral length of approximately ~~2.4 miles. We turned to sales 49 gross (36.6 net) wells with an average lateral length of approximately 2.4 miles.~~2.2 miles during the combined six months ended June 30, 2021. In addition, we incurred approximately ~~$13.8~~$4.6 million of leasehold and surface acreage ~~additions.~~additions during the combined six months ended June 30, 2021.

On July 8, 2021, the board of directors approved an increase in our 2021 capital expenditures budget. The 2021 total revised capital budget was approved to be $159 million, which includes $146 million for drilling and completion activity and $13 million for plugging and abandoning and other activity. Previously, our 2021 capital budget was $142 million, which included $130 million for drilling and completions activity and $12 million for plugging and abandoning and other activity.

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Adjusted EBITDAX

Adjusted EBITDAX is not a measure of net income (loss) as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items ~~including depletion, depreciation, amortization and accretion (DD&A), impairment~~shown in the table below, which presents a reconciliation of long lived assets, non-recurring charges in other operating expenses, exploration and abandonment expenses, gain on sale of property and equipment, (gain) loss on commodity derivatives, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the period, stock-based compensation expense, amortization of debt issuance costs, gain on repurchase of senior notes, interest expense, income tax expense (benefit), loss on deconsolidation of Elevation Midstream, LLC and reorganization items, net. Adjusted EBITDAX ~~is also used~~ to ~~evaluate~~ the ~~performance~~GAAP financial measure of ~~reportable segments. Please see~~ ~~Note 16—Segment Information~~ ~~in Part I, Item 1. Financial Information~~net income (loss) for each of ~~this Quarterly Report for more information regarding~~ the ~~EBITDAX~~periods indicated (in thousands).


	Successor		Predecessor
	For the Three Months Ended June 30,		For the Three Months Ended June 30,
	2021		2020
Reconciliation of Net Income (Loss) to Adjusted EBITDAX:
Net income (loss)	$	24,544	$	(291,934)
Add back:
Depletion, depreciation, amortization and accretion	50,090		82,620
Impairment of long-lived assets	170		960
Other operating expenses	5,380		13,209
Exploration and abandonment expenses	3,586		62,661
Loss on commodity derivatives	75,839		69,301
Settlements on commodity derivative instruments	(19,237)		127,429
Stock-based compensation expense	2,771		2,560
Amortization of debt issuance costs	457		1,948
Interest expense	1,713		18,366
Income tax expense	4,775		—
Reorganization items, net	—		26,919
Adjusted EBITDAX	$	150,088	$	114,039

Table of ~~reportable segments.~~Contents


	Successor		Predecessor		Non-GAAP		Predecessor
	For the Period from January 21 through June 30,		For the Period from January 1 through January 20,		Combined Six Months Ended June 30,		For the Six Months Ended June 30,
	2021		2021		2021		2020
Reconciliation of Net Income (Loss) to Adjusted EBITDAX:
Net income (loss)	$	113,098	$	870,970	$	984,068	$	(282,897)
Add back:
Depletion, depreciation, amortization and accretion	88,665		16,133		104,798		158,670
Impairment of long-lived assets	170		—		170		1,736
Other operating expenses	9,262		1,107		10,369		65,784
Exploration and abandonment expenses	4,345		316		4,661		175,141
(Gain) loss on commodity derivatives	104,325		12,586		116,911		(193,714)
Settlements on commodity derivative instruments	(29,871)		—		(29,871)		166,725
Stock-based compensation expense	4,945		302		5,247		2,560
Amortization of debt issuance costs	909		113		1,022		3,190
Interest expense	4,294		1,421		5,715		38,482
Income tax expense	28,100		—		28,100		2,200
Loss on deconsolidation of Elevation Midstream, LLC	—		—		—		73,139
Reorganization items, net	—		(873,908)		(873,908)		26,919
Adjusted EBITDAX	$	328,242	$	29,040	$	357,282	$	237,935

Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed in the table above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this ~~measure~~ measure:

(i) is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors;

(ii) helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

(iii) is used by our management team for various purposes, including as a measure of operating performance, in presentations to our ~~board of directors,~~Board, as a basis for strategic planning and forecasting.

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~~The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated (in thousands).~~

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2020 2019 2020 2019
Reconciliation of Net Income (Loss) to Adjusted EBITDAX:
Net income (loss) $ (540,607) $ 33,924 $ (823,504) $ (16,664)
Add back:
Depletion, depreciation, amortization and accretion 85,306 114,996 243,977 352,134
Impairment of long lived assets — — 1,736 11,233
Other operating expenses 9,766 — 75,549 —
Exploration and abandonment expenses 9,762 13,245 184,903 32,725
Gain on sale of property and equipment — (1,011) — (1,329)
(Gain) loss on commodity derivatives 9,673 (87,956) (184,041) (39,383)
Settlements on commodity derivative instruments 14,045 16,101 180,770 (8,432)
Premiums paid for derivatives that settled during the period — (812) — (19,910)
Stock-based compensation expense 1,902 11,358 4,462 39,306
Amortization of debt issuance costs 155 974 3,345 3,799
Gain on repurchase of 2026 Senior Notes — — — (10,486)
Interest expense 7,233 22,250 45,714 61,478
Income tax expense — 14,800 2,200 900
Loss on deconsolidation of Elevation Midstream, LLC — — 73,139 —
Reorganization items, net 501,073 — 527,992 —
Adjusted EBITDAX $ 98,308 $ 137,869 $ 336,242 $ 405,371

Free Cash Flow

Our Free Cash Flow is not a measure of and should not be considered an alternative to, or more meaningful than, net income (loss) as determined by GAAP. We define Free Cash Flow as Discretionary Cash Flow (non-GAAP) less Adjusted Cash Flow used in Investing (non-GAAP) adjusted for Other Non-Recurring Adjustments (non-GAAP). Discretionary Cash Flow is defined as net cash provided by operating activities (GAAP) ~~less~~before changes in working capital accounts (current assets and liabilities). Adjusted Cash Flow used in Investing is defined as cash flow used in investing activities (GAAP) adjusted for changes in accounts payable and accrued liabilities related to capital expenditures.

Free Cash Flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Free Cash Flow can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe Free Cash Flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities ~~construct and support midstream assets,~~ and to return capital to stockholders.

The following tables present a reconciliation of Discretionary Cash Flow and Free Cash Flow to the GAAP financial measure of net cash provided by operating activities for each of the periods indicated.


	Successor		Predecessor
	For the Three Months Ended		For the Three Months Ended
	June 30, 2021		June 30, 2020
Cash Flow from Operating Activities
Net cash used in operating activities	$	(7,339)	$	(63,145)
Changes in current assets and liabilities	148,709		52,983
Discretionary Cash Flow	141,370		(10,162)
Cash Flow from Investing Activities
Net cash used in investing activities	(18,474)		(51,710)
Change in accounts payable and accrued liabilities related to capital expenditures	(15,544)		34,851
Adjusted Cash Flow used in Investing	(34,018)		(16,859)
Free Cash Flow	$	107,352	$	(27,021)


	Successor		Predecessor		Non-GAAP
	For the Period from January 21 through June 30,		For the Period from January 1 through January 20,		Combined Six Months Ended June 30,
	2021		2021		2021
Cash Flow from Operating Activities
Net cash provided by operating activities	$	141,769	$	15,346	$	157,115
Changes in current assets and liabilities	155,481		(17,089)		138,392
Discretionary Cash Flow	297,250		(1,743)		295,507
Cash Flow from Investing Activities
Net cash used in investing activities	(41,173)		(9,120)		(50,293)
Change in accounts payable and accrued liabilities related to capital expenditures	(16,416)		(1,442)		(17,858)
Adjusted Cash Flow used in Investing	(57,589)		(10,562)		(68,151)
Free Cash Flow	$	239,661	$	(12,305)	$	227,356

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															Predecessor
															Upstream		Midstream		Consolidated
		Upstream		Midstream		Consolidated		Upstream		Midstream		Consolidated			For the Six Months Ended
		For the Three Months Ended September 30, 2020						For the Nine Months Ended September 30, 2020							June 30, 2020
Cash Flow from Operating Activities	Cash Flow from Operating Activities													Cash Flow from Operating Activities
Net cash provided by operating activities	Net cash provided by operating activities	$	65,099	$	—	$	65,099	$	146,173	$	2,880	$	149,053	Net cash provided by operating activities	$	81,074	$	2,880	$	83,954
Changes in current assets and liabilities	Changes in current assets and liabilities	$	(485,970)	$	—	$	(485,970)	$	(534,034)	$	(1,907)	$	(535,941)	Changes in current assets and liabilities	(48,064)		(1,907)		(49,971)
Discretionary Cash Flow	Discretionary Cash Flow	$	(420,871)	$	—	$	(420,871)	$	(387,861)	$	973	$	(386,888)	Discretionary Cash Flow	33,010		973		33,983

Cash Flow from Investing Activities	Cash Flow from Investing Activities													Cash Flow from Investing Activities
Net cash used in investing activities	Net cash used in investing activities	$	(25,236)	$	—	$	(25,236)	$	(210,809)	$	(5,840)	$	(216,649)	Net cash used in investing activities	(185,573)		(5,840)		(191,413)
Change in accounts payable and accrued liabilities related to capital expenditures	Change in accounts payable and accrued liabilities related to capital expenditures	$	25,853	$	—	$	25,853	$	50,227	$	2,210	$	52,437	Change in accounts payable and accrued liabilities related to capital expenditures	24,374		2,210		26,584
Adjusted Cash Flow provided by (used in) Investing		$	617	$	—	$	617	$	(160,582)	$	(3,630)	$	(164,212)

Adjusted Cash Flow used in Investing														Adjusted Cash Flow used in Investing	(161,199)		(3,630)		(164,829)
Other Non-Recurring Adjustments(1)	Other Non-Recurring Adjustments(1)	$	433	$	—	$	433	$	1,603	$	—	$	1,603	Other Non-Recurring Adjustments(1)	1,170		—		1,170

Free Cash Flow	Free Cash Flow	$	(419,821)	$	—	$	(419,821)	$	(546,840)	$	(2,657)	$	(549,497)	Free Cash Flow	$	(127,019)	$	(2,657)	$	(129,676)

Upstream Midstream Consolidated Upstream Midstream Consolidated
For the Three Months Ended
September 30, 2019 For the Nine Months Ended
September 30, 2019
Cash Flow from Operating Activities
Net cash provided by (used in) operating activities $ 138,230 $ (113) $ 138,117 $ 355,052 $ 1,509 $ 356,561
Changes in current assets and liabilities $ (11,023) $ (586) $ (11,609) $ 20,418 $ (1,355) $ 19,063
Discretionary Cash Flow $ 127,207 $ (699) $ 126,508 $ 375,470 $ 154 $ 375,624
Cash Flow from Investing Activities
Net cash used in investing activities $ (196,543) $ (61,081) $ (257,624) $ (521,697) $ (185,171) $ (706,868)
Change in accounts payable and accrued liabilities related to capital expenditures $ 76,455 $ (11,106) $ 65,349 $ 6,746 $ (22,972) $ (16,226)
Adjusted Cash Flow used in Investing $ (120,088) $ (72,187) $ (192,275) $ (514,951) $ (208,143) $ (723,094)
Other Non-Recurring Adjustments(1)
$ 4,539 $ — $ 4,539 $ 9,849 $ — $ 9,849
Free Cash Flow $ 11,658 $ (72,886) $ (61,228) $ (129,632) $ (207,989) $ (337,621)

_______________

(1) Amount incurred for the construction of our field office that is included in other property and equipment in our condensed consolidated statements of cash flows.

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Items Affecting the Comparability of Our Financial Results

Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, for the reasons described below:

•Upon emerging from bankruptcy on January 20, 2021, we recorded our consolidated balance sheet accounts at fair value. See Note 3—Fresh Start Reporting in Item 1 of this Quarterly Report. Now, the Successor period January 21, 2021 to June 30, 2021 is not comparable to the Predecessor period from January 1, 2021 to January 20, 2021 and in relation to the first six months of 2020. We illustrate this lack of comparability by using a black line in tables to separate Predecessor Company amounts from Successor Company amounts. We overcome this lack of comparability by combining the Predecessor and Successor periods so they can be viewed in relation to the first six months of 2020.

•During the Chapter 11 Cases, ~~we expect~~ our financial results ~~to continue to be~~were volatile as restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly ~~impact~~impacted our financial results. For the ~~three and nine~~combined six months ended ~~September~~June 30, ~~2020,~~2021, prior to emergence, we ~~incurred $501.1~~realized an $873.9 million ~~and $528.0 million of~~ reorganization items, net ~~respectively, as compared to none in 2019.~~gain. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. Despite the Company’s emergence from the Chapter 11 Cases, claim assessments will continue for the foreseeable future.

•For the ~~nine~~combined six months ended ~~September~~June 30, 2021 compared to the six months ended June 30, 2020, ~~and 2019, respectively,~~ exploration and abandonment expenses ~~increased~~decreased primarily due to the abandonment of ~~$179.0~~$169.6 million in unproved properties during the six months ended June 30, 2020. Abandoned properties for the combined six months ended June 30, 2021 were $2.4 million. During the first quarter of 2021 we emerged from bankruptcy where we revalued our oil and ~~$26.2 million~~gas properties. See Note 3—Fresh Start Reporting in Item 1 of ~~unproved properties.~~this Quarterly Report for information related to our asset and liability values upon emergence.

•Elevation Midstream, LLC was deconsolidated as of March 16, 2020 and accounted for as an equity method investment. We elected the fair value option to remeasure the Elevation Midstream, LLC equity method investment and determined it had no fair value. We recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the condensed consolidated statements of operations for the ~~nine~~six months ended ~~September 30, 2020. Please see~~ ~~Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC~~ ~~in Part I, Item 1. Financial Information of this Quarterly Report for information related to the deconsolidation of Elevation Midstream, LLC.~~

•On April 2, 2020, Elevation demanded payment of $46.8 million due to an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020. While we dispute that these amounts are due to Elevation, under ASC ~~Topic 450 - Contingencies, we recorded the amount in other operating expenses on the condensed consolidated statements of operations for the nine months ended September~~June 30, 2020.

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Historical Results of Operations and Operating Expenses

Oil, Natural Gas and NGL Sales Revenues, Operating Expenses and Other Income (Expense).

For components of our revenues, operating expenses, other income (expense) and net income (loss), please see our condensed consolidated statements of operations in ~~Part I,~~ Item ~~1. Financial Information~~1 of this Quarterly Report.

The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:


		For the Three Months Ended						For the Nine Months Ended										Successor					Predecessor
		September 30,						September 30,										For the Three Months Ended June 30,					For the Three Months Ended June 30,
		2020			2019			2020			2019							2021					2020
Sales (MBoe)(1):	Sales (MBoe)(1):	8,010			7,390			24,909			22,167			Sales (MBoe)(1):				6,975					8,322
Oil sales (MBbl)	Oil sales (MBbl)	2,818			3,597			9,741			10,830			Oil sales (MBbl)				2,349					3,419
Natural gas sales (MMcf)	Natural gas sales (MMcf)	18,277			14,418			54,823			43,433			Natural gas sales (MMcf)				15,834					17,543
NGL sales (MBbl)	NGL sales (MBbl)	2,146			1,390			6,031			4,097			NGL sales (MBbl)				1,987					1,979
Sales (BOE/d)(1):	Sales (BOE/d)(1):	87,068			80,327			90,909			81,198			Sales (BOE/d)(1):				76,645					91,451
Oil sales (Bbl/d)	Oil sales (Bbl/d)	30,632			39,098			35,551			39,670			Oil sales (Bbl/d)				25,814					37,571
Natural gas sales (Mcf/d)	Natural gas sales (Mcf/d)	198,662			156,717			200,083			159,095			Natural gas sales (Mcf/d)				173,997					192,780
NGL sales (Bbl/d)	NGL sales (Bbl/d)	23,326			15,109			22,011			15,007			NGL sales (Bbl/d)				21,829					21,747
Average sales prices(2):	Average sales prices(2):													Average sales prices(2):
Oil sales (per Bbl)(3)	Oil sales (per Bbl)(3)	$	39.41		$	41.99		$	27.88		$	46.31		Oil sales (per Bbl)(3)				$	59.22				$	10.61
Oil sales with derivative settlements (per Bbl)(3)	Oil sales with derivative settlements (per Bbl)(3)	44.01			45.58			35.45			43.77			Oil sales with derivative settlements (per Bbl)(3)				50.60					18.11
Natural gas sales (per Mcf)(4)	Natural gas sales (per Mcf)(4)	1.34			1.17			1.14			1.71			Natural gas sales (per Mcf)(4)	2.49					0.91
Natural gas sales with derivative settlements (per Mcf)		1.40			1.33			1.34			1.69
Natural gas sales with derivative settlements (Mcf)(4)														Natural gas sales with derivative settlements (Mcf)(4)				2.56					1.24
NGL sales (per Bbl)(4)	NGL sales (per Bbl)(4)	10.60			6.55			8.42			10.97			NGL sales (per Bbl)(4)	22.67					5.47
Average price (per BOE)(3)		19.75			23.94			15.46			28.01
Average price with derivative settlements (per BOE)(3)		21.51			26.01			18.86			26.73
Average price (per BOE)(4)(3)														Average price (per BOE)(4)(3)				32.06					7.59
Average price with derivative settlements (per BOE)(4)(3)														Average price with derivative settlements (per BOE)(4)(3)				29.30					11.35
Expense per BOE:	Expense per BOE:													Expense per BOE:
Lease operating expenses	Lease operating expenses	$	1.55		$	3.11		$	2.64		$	3.09		Lease operating expenses				$	1.97				$	2.76
Transportation and gathering	Transportation and gathering	6.26			0.94			3.98			1.31			Transportation and gathering				3.09					3.16
Production taxes	Production taxes	0.21			1.31			0.80			2.09			Production taxes				1.56					0.56
Exploration and abandonment expenses	Exploration and abandonment expenses	1.22			1.79			7.42			1.48			Exploration and abandonment expenses				0.51					7.53
Depletion, depreciation, amortization and accretion	Depletion, depreciation, amortization and accretion	10.65			15.56			9.79			15.89			Depletion, depreciation, amortization and accretion				7.18					9.93
General and administrative expenses	General and administrative expenses	1.45			3.71			1.90			3.87			General and administrative expenses				1.57					3.02
Cash general and administrative expenses(5)	Cash general and administrative expenses(5)	1.21			2.17			1.73			2.10			Cash general and administrative expenses(5)	1.17					2.71
Stock-based compensation	Stock-based compensation	0.24			1.54			0.17			1.77			Stock-based compensation				0.40					0.31
Total operating expenses per BOE~~(4)~~(6)	Total operating expenses per BOE~~(4)~~(6)	$	21.34		$	26.42		$	26.53		$	27.73		Total operating expenses per BOE~~(4)~~(6)	$	15.88				$	26.96

Production taxes as a percentage of revenue(7)	Production taxes as a percentage of revenue(7)	1.1		%	5.5		%	5.1		%	7.5		%	Production taxes as a percentage of revenue(7)	4.9		%			7.4		%

_______________

(1)One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains and losses on settlements for commodity derivatives ~~and amortization of premiums paid or received~~ on ~~options~~swaps that settled during the period.

(3)Includes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the ~~nine~~Predecessor three months ended ~~September~~June 30, 2020, ~~and for the three and nine months ended September 30, 2019,~~ pursuant to ASC ~~606, Revenue Recognition.~~606.

(4) During the first quarter of 2021, a large portion of our gas and NGL contracts were subject to daily prices versus a monthly average price. As a result, our realized prices benefited from several days of severe cold during February 2021.

(5) Cash general and administrative expenses for the Predecessor three months ended June 30, 2020 includes expense of $0.3 million related to the terms of a separation agreement with one former executive officer. Excluding this one-time expense results in cash general and administrative expense per BOE of $2.68 for the Predecessor three months ended June 30, 2020.

(6) Excludes ~~midstream operating expenses,~~ impairment of ~~long lived~~long-lived assets ~~gain on sale of property and equipment~~ and other operating expenses.

(7) Production taxes as percentage of revenue during the Successor three months ended June 30, 2021 is lower than the rate that can be expected going forward due to a true up of ad valorem taxes pursuant to a reduction in estimated rates.

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	Successor			Predecessor			Non-GAAP			Predecessor
	For the Period from January 21 through June 30,			For the Period from January 1 through January 20,			For the Combined Six Months Ended June 30,			For the Six Months Ended June 30,
	2021			2021			2021			2020
Sales (MBoe)(1):	11,927			1,492			13,419			16,899
Oil sales (MBbl)	4,141			546			4,687			6,923
Natural gas sales (MMcf)	27,198			3,412			30,610			36,546
NGL sales (MBbl)	3,254			376			3,630			3,885
Sales (BOE/d)(1):	74,081			74,600			74,137			92,852
Oil sales (Bbl/d)	25,719			27,312			25,895			38,038
Natural gas sales (Mcf/d)	168,933			170,588			169,113			200,802
NGL sales (Bbl/d)	20,209			18,820			20,049			21,346
Average sales prices(2):
Oil sales (per Bbl)(3)	$	57.88		$	49.68		$	56.92		$	23.18
Oil sales with derivative settlements (per Bbl)(3)	50.35			49.68			50.27			31.97
Natural gas sales (per Mcf)(4)	5.77			2.29			5.38			1.05
Natural gas sales with derivative settlements (Mcf)(4)	5.81			2.29			5.42			1.32
NGL sales (per Bbl)(4)	23.55			21.52			23.33			7.21
Average price (per BOE)(4)(3)	39.66			28.85			38.46			13.42
Average price with derivative settlements (per BOE)(4)(3)	37.16			28.85			36.24			17.60
Expense per BOE:
Lease operating expenses	$	2.05		$	1.71		$	2.01		$	3.16
Transportation and gathering	3.75			4.19			3.80			2.91
Production taxes	2.71			2.21			2.66			1.07
Exploration and abandonment expenses	0.36			0.21			0.35			10.36
Depletion, depreciation, amortization and accretion	7.43			10.81			7.81			9.39
General and administrative expenses	1.55			1.48			1.54			2.12
Cash general and administrative expenses(5)	1.14			1.28			1.15			1.97
Stock-based compensation	0.41			0.20			0.39			0.15
Total operating expenses per BOE(6)	$	17.85		$	20.61		$	18.17		$	29.01

Production taxes as a percentage of revenue	6.8		%	7.7		%	6.9		%	7.9		%

_______________

(1) One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2) Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains and losses on settlements for commodity derivatives on swaps that settled during the period.

(3) Includes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the Predecessor six months ended June 30, 2020, pursuant to ASC 606.

(5) Cash general and administrative expenses for the Predecessor six months ended June 30, 2020 includes expense of $2.5 million related to the terms of a separation agreement with two former executive officers. Excluding this one-time expense results in cash general and administrative expense per BOE of $1.82 for the Predecessor six months ended June 30, 2020.

(6) Excludes impairment of long-lived assets and other operating expenses.

Three Months Ended ~~September~~June 30, ~~2020~~2021 Compared to Three Months Ended ~~September~~June 30, ~~2019~~2020

Oil sales revenues. Crude oil sales revenues ~~decreased~~increased by ~~$39.9~~$102.8 million to ~~$111.1~~$139.1 million for the three months ended ~~September~~June 30, ~~2020~~2021 as compared to crude oil sales of ~~$151.0~~$36.3 million for the three months ended ~~September~~June 30, ~~2019. A~~2020. An increase in crude oil prices contributed a $114.2 million positive impact, and a decrease in sales volumes between these periods contributed a ~~$32.7~~$11.4 million negative ~~impact, and a decrease in~~impact. For the three months ended June 30, 2020, crude oil ~~prices contributed a $7.2~~revenue decreased by approximately $3.9 million ~~negative impact.~~due to the impact of the increase in the forecasted deferral balance on one of our revenue contracts. Pursuant to ASC 606, the contract term impacts the amount of consideration that could be included in the transaction price, which reduced oil sales revenue.

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For the three months ended ~~September~~June 30, ~~2020,~~2021, our crude oil sales averaged ~~30.6~~25.8 MBbl/d. Our crude oil sales volume decreased by ~~779~~1,070 to ~~2,818~~2,349 MBbl for the three months ended ~~September~~June 30, ~~2020~~2021 compared to ~~3,597~~3,419 MBbl for the three months ended ~~September~~June 30, ~~2019.~~2020. The volume decrease is primarily due to the natural decline of our existing properties, ~~and 0.4 MBbl of oil that was produced but not sold due to line fill requirements under our long-term crude oil delivery commitment agreement,~~only partially offset by an increase in production from the completion of 5140 gross wells from ~~October~~July 1, ~~2019~~2020 to ~~September~~June 30, ~~2020.~~2021, since during the second half of 2020 and in early 2021 prior to emergence from bankruptcy, our drilling program had been suspended.

The average price we realized on the sale of crude oil was ~~$39.41~~$59.22 per Bbl for the three months ended ~~September~~June 30, ~~2020~~2021 compared to ~~$41.99~~$10.61 per Bbl for the three months ended ~~September~~June 30, ~~2019.~~2020. For the three months ended ~~September~~June 30, ~~2019,~~2020, crude oil revenue decreased ~~$22.2~~$3.9 million due to the contract term impacting the amount of consideration that can be included in the transaction price, which reduced oil sales revenue pursuant to ASC 606. For the three months ended ~~September~~June 30, ~~2020,~~2021, no such decrease in crude oil revenue was recorded.

Natural gas sales revenues. Natural gas sales revenues increased by ~~$7.6~~$23.5 million to ~~$24.4~~$39.5 million for the three months ended ~~September~~June 30, ~~2020~~2021 as compared to natural gas sales revenues of ~~$16.8~~$16.0 million for the three months ended ~~September~~June 30, ~~2019.~~2020. An increase in natural gas prices contributed a $25.1 million positive impact, while a decrease in sales volumes between these periods contributed a ~~$4.5~~$1.6 million ~~positive impact, while an increase in natural gas prices contributed a $3.1 million positive~~negative impact.

For the three months ended ~~September~~June 30, ~~2020,~~2021, our natural gas sales averaged ~~198.7~~174.0 MMcf/d. Natural gas sales volumes ~~increased~~decreased by ~~3,859~~1,709 to ~~18,277~~15,834 MMcf for the three months ended ~~September~~June 30, ~~2020~~2021 as compared to ~~14,418~~17,543 MMcf for the three months ended ~~September~~June 30, ~~2019.~~2020. The volume ~~increase~~decrease is primarily due to ~~the completion of 51 gross wells from October 1, 2019 to September 30, 2020, partially offset by~~ the natural decline on existing producing ~~properties.~~properties, partially offset by the completion of 40 gross wells from July 1, 2020 to June 30, 2021, since during the second half of 2020 and in early 2021 prior to emergence from bankruptcy, our drilling program had been suspended.

The average price we realized on the sale of our natural gas was ~~$1.34~~$2.49 per Mcf for the three months ended ~~September~~June 30, ~~2020~~2021 compared to ~~$1.17~~$0.91 per Mcf for the three months ended ~~September~~June 30, ~~2019,~~2020, primarily due to an increase ~~of volumes on a certain gathering system for~~in pricing as compared to the three months ending ~~September~~June 30, ~~2019.~~2020.

NGL sales revenues. NGL sales revenues increased by ~~$13.6~~$34.2 million to ~~$22.7~~$45.0 million for the three months ended ~~September~~June 30, ~~2020~~2021 as compared to NGL sales revenues of ~~$9.1~~$10.8 million for the three months ended ~~September~~June 30, ~~2019.~~2020. An increase in ~~sales volumes~~prices between these periods contributed a ~~$4.8~~$34.2 million positive impact, while a decrease in volumes contributed an ~~increase in price contributed a $8.8 million positive~~immaterial negative impact.

For the three months ended ~~September~~June 30, ~~2020,~~2021, our NGL sales averaged ~~23.3~~21.8 MBbl/d. NGL sales volumes increased by ~~756~~8 to ~~2,146~~1,987 MBbl for the three months ended ~~September~~June 30, ~~2020~~2021 as compared to ~~1,390~~1,979 MBbl for the three months ended ~~September~~June 30, ~~2019.~~2020. The volume increase is primarily due to the completion of 5140 gross wells from ~~October~~July 1, ~~2019~~2020 to ~~September~~June 30, ~~2020,~~2021, partially offset by the natural decline on existing producing properties. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.

The average price we realized on the sale of our NGL was ~~$10.60~~$22.67 per Bbl for the three months ended ~~September~~June 30, ~~2020~~2021 compared to ~~$6.55~~$5.47 per Bbl for the three months ended ~~September~~June 30, ~~2019,~~2020, primarily due to an increase ~~of volumes on a certain gathering system.~~in pricing as compared to the three months ending June 30, 2020.

Lease operating ~~expenses.~~expenses (“LOE”). Our LOE decreased by ~~$10.6~~$9.3 million to ~~$12.4~~$13.7 million for the three months ended ~~September~~June 30, ~~2020,~~2021, from $23.0 million for the three months ended ~~September~~June 30, ~~2019. The decrease in LOE was primarily~~2020. While oil revenue increased for the ~~result of a decrease in labor, rental equipment and workover repairs in an effort~~three months ended June 30, 2021, oil volumes were down for the reasons mentioned above. This allowed the company to optimize our field cost structure during the three months ended ~~September~~June 30, ~~2020.~~2021. On a per unit basis, LOE decreased to ~~$1.55~~$1.97 per BOE sold for the three months ended ~~September~~June 30, ~~2020~~2021 from ~~$3.11~~$2.76 per BOE for the three months ended ~~September~~June 30, ~~2019.~~2020.

Transportation and gathering (“T&G”). Our T&G expense decreased by $4.7 million to $21.6 million for the three months ended June 30, 2021, from $26.3 million for the three months ended June 30, 2020. The decrease in T&G was primarily due to revenue contract changes and a decrease in production during the three months ended June 30, 2021 compared to the three months ended June 30, 2020. On a per unit basis, T&G decreased to $3.09 per BOE sold for the three months ended June 30, 2021 compared to $3.16 per BOE sold for the three months ended June 30, 2020.

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~~Transportation and gathering ("T&G").~~ Production taxes.Our ~~T&G expense~~production taxes increased by ~~$43.3~~$6.2 million to ~~$50.2~~$10.9 million for the three months ended ~~September~~June 30, ~~2020, from $6.9~~2021 as compared to $4.7 million for the three months ended ~~September~~June 30, ~~2019.~~2020. The increase in T&G was primarily due to an increase of volumes on a certain gathering system and a change in oil contracts during the three months ended September 30, 2020 compared to the three months ended September 30, 2019. On a per unit basis, T&G increased to $6.26 per BOE sold for the three months ended September 30, 2020 compared to $0.94 per BOE sold for the three months ended September 30, 2019.

~~Production taxes.~~ Our production taxes decreased by $8.0 million to $1.7 million for the three months ended September 30, 2020 as compared to $9.7 million for the three months ended September 30, 2019. The decrease is primarily attributable to ~~decreased~~increased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue ~~was 1.1%~~were 4.9% for the three months ended ~~September~~June 30, ~~2020~~2021 as compared to ~~5.5%~~7.4% for the three months ended September 30, 2019. The decrease in production taxes as a percentage of sales revenue relates to a decrease in the estimated ad valorem and severance tax rates and an adjustment to the estimated ad valorem tax payable for the three months ended SeptemberJune 30, 2020.

Exploration and abandonment expenses. Our exploration and abandonment expenses were ~~$9.8~~$3.6 million for the three months ended ~~September~~June 30, ~~2020, of which $9.5 million was lease abandonment expense.~~2021. For the three months ended ~~September~~June 30, ~~2019,~~2020, we recognized ~~$13.2~~$62.7 million in exploration and abandonment expenses. The decrease in abandonment expense during 2021 was because our assets were fair valued upon emergence from bankruptcy on January 20, 2021.

Depletion, depreciation, amortization and accretion expense ("(“DD~~&A"~~&A”). Our DD&A expense decreased ~~$29.7~~$32.5 million to ~~$85.3~~$50.1 million for the three months ended ~~September~~June 30, ~~2020~~2021 as compared to ~~$115.0~~$82.6 million for the three months ended ~~September~~June 30, ~~2019.~~2020. On a per unit basis, DD&A expense decreased to ~~$10.65~~$7.18 per BOE for the three months ended ~~September~~June 30, ~~2020~~2021 from ~~$15.56~~$9.93 per BOE for the three months ended ~~September~~June 30, ~~2019. This decrease is~~2020. These decreases are due to the $326.0 million downward fair value adjustment to the depletable asset base upon adoption of fresh start reporting, as well as an impairment of ~~$1.3 billion~~$208.5 million of proved oil and gas properties that occurred during ~~the fourth quarter of 2019.~~2020.

General and administrative expenses ("(“G~~&A"~~&A”). General and administrative expenses decreased by ~~$15.8~~$14.2 million to ~~$11.6~~$10.9 million for the three months ended ~~September~~June 30, ~~2020~~2021 as compared to ~~$27.4~~$25.1 million for the three months ended ~~September~~June 30, ~~2019.~~2020. This decrease is primarily due to reductions of workforce during ~~the first and second quarters of~~ 2020 and a decrease in ~~stock-based compensation expense~~pre-petition advisory fees recognized for the three months ended ~~September~~June 30, 2020 compared to the three months ended ~~September~~June 30, ~~2019.~~2021. On a per unit basis, G&A expense decreased to ~~$1.45~~$1.57 per BOE sold for the three months ended ~~September~~June 30, ~~2020~~2021 from ~~$3.71~~$3.02 per BOE sold for the three months ended ~~September~~June 30, ~~2019.~~2020.

Our G&A expenses for the three months ended June 30, 2020 includes $0.3 million related to the terms of a separation agreement with a former executive officer. No expenses of this nature were incurred during the three months ended June 30, 2021.

Our G&A expenses include the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the three months ended ~~September~~June 30, ~~2020,~~2021, there was ~~$1.9~~$2.8 million of stock-based compensation expense. For the three months ended ~~September~~June 30, ~~2019,~~2020, stock-based compensation expense was ~~$11.4~~$2.6 million.

Other operating expenses. Other operating expenses ~~were $9.8~~decreased by $7.8 million to $5.4 million for the three months ended ~~September~~June 30, 2021 as compared to $13.2 million for the three months ended June 30, 2020. This ~~amount~~decrease is due primarily ~~made up~~to non-recurring early termination penalties of $11.9 million, which includes a ~~$3.7~~$9.5 million early termination fee related to the termination of our crude oil marketing contract and a $2.4 million rig termination fee. The decrease is also due to a $2.2 million reduction of restructuring expenses from period to period. These decreases were partially offset by an increase in merger and acquisition costs of $6.6 million.

Commodity derivative loss. Primarily due to the increase in NYMEX crude oil future prices at June 30, 2021 as compared to March 31, 2021 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of $75.8 million for the three months ended June 30, 2021. Primarily due to the increase in NYMEX crude oil futures prices at June 30, 2020 as compared to March 31, 2020 and change in fair value from the execution and unwinds of hedged positions, we incurred a net loss on our commodity derivatives of $69.3 million for the three months ended June 30, 2020. These losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. During the three months ended June 30, 2021, we paid commodity derivatives totaling $19.2 million. During the three months ended June 30, 2020, we received settlements of commodity derivatives totaling $127.4 million.

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Reorganization items, net. Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we have incurred significant costs associated with our reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. For the three months ended June 30, 2020, we recognized $26.9 million of reorganization items, net due to the Company entering into bankruptcy proceedings. No reorganization gain or loss was recognized during the three months ended June 30, 2021.

Interest expense. Interest expense consists of interest expense on our long-term debt and amortization of debt issuance costs, net of capitalized interest. For the three months ended June 30, 2021, we recognized interest expense of $2.2 million as compared to $20.3 million for the three months ended June 30, 2020. Upon filing its petition for Chapter 11, we ceased accruing interest expense on our 2024 and 2026 Senior Notes. We had outstanding debt of $90.0 million as of June 30, 2021.

We incurred interest expense for the three months ended June 30, 2021 of $1.8 million related to our RBL Credit Facility. We incurred interest expense for the three months ended June 30, 2020 of approximately $20.2 million related to our Prior Credit Facility, DIP Credit Facility, our 2024 Senior Notes, and our 2026 Senior Notes. Also included in interest expense for the three months ended June 30, 2021 and the three months ended June 30, 2020 was the amortization of debt issuance costs of $0.5 million and $1.9 million, respectively. For the three months ended June 30, 2021 and the three months ended June 30, 2020, we capitalized interest expense of $0.1 million and $1.9 million, respectively.

Income tax expense. We recorded $4.8 million of income tax expense for the three months ended June 30, 2021 and no income tax expense for the three months ended June 30, 2020. This resulted in an effective tax rate of approximately 16.29% and zero for the three months ended June 30, 2021 and 2020, respectively. Our effective tax rates differ from the U.S. statutory income tax rate of 21.0% primarily due to the effects of state income taxes, estimated taxable permanent differences, and valuation allowance.

Gathering and facilities segment. Prior to March 31, 2020, we had two operating segments, (i) the exploration and production segment, and (ii) the gathering and facilities segment. Please see Note 1—Business and Organization—Deconsolidation of Elevation Midstream, LLC to the Company’s consolidated financial statements in its Annual Report for further information. After March 31, 2020, Extraction began reporting as a single reportable segment.

Combined Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Oil sales revenues. Crude oil sales revenues increased by $106.3 million to $266.8 million for the combined six months ended June 30, 2021 as compared to crude oil sales of $160.5 million for the six months ended June 30, 2020. An increase in crude oil prices contributed a $158.1 million positive impact, and a decrease in sales volumes between these periods contributed a $51.8 million negative impact. For the six months ended June 30, 2020, crude oil revenue decreased by approximately $12.3 million due to the contract term impacting the amount of consideration that could be included in the transaction price, which reduced oil sales revenue pursuant to ASC 606.

For the combined six months ended June 30, 2021, our crude oil sales averaged 25.9 MBbl/d. Our crude oil sales volume decreased by 2,236 to 4,687 MBbl for the combined six months ended June 30, 2021 compared to 6,923 MBbl for the six months ended June 30, 2020. The volume decrease is primarily due to the natural decline of our existing properties, partially offset by an increase in production ~~tax interest~~from the completion of 40 gross wells from July 1, 2020 to June 30, 2021, since during the second half of 2020 and in early 2021 prior to emergence from bankruptcy, our drilling program had been suspended.

The average price we realized on the sale of crude oil was $56.92 per Bbl for the combined six months ended June 30, 2021 compared to $23.18 per Bbl for the six months ended June 30, 2020, primarily due to changes in market prices for crude oil and the $12.3 million decrease of crude oil revenue explained above.

Natural gas sales revenues. Natural gas sales revenues increased by $126.3 million to $164.6 million for the combined six months ended June 30, 2021 as compared to natural gas sales revenues of $38.3 million for the six months ended June 30, 2020. An increase in natural gas prices contributed a $132.5 million positive impact, while a decrease in sales volumes between these periods contributed a $6.2 million negative impact.

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For the combined six months ended June 30, 2021, our natural gas sales averaged 169.1 MMcf/d. Natural gas sales volumes decreased by 5,936 to 30,610 MMcf for the combined six months ended June 30, 2021 as compared to 36,546 MMcf for the six months ended June 30, 2020. The volume decrease is primarily due to the the natural decline on existing producing properties, partially offset by the completion of 40 gross wells from July 1, 2020 to June 30, 2021, since during the second half of 2020 and in early 2021 prior to emergence from bankruptcy, our drilling program had been suspended.

The average price we realized on the sale of our natural gas was $5.38 per Mcf for the combined six months ended June 30, 2021 compared to $1.05 per Mcf for the six months ended June 30, 2020, primarily due to an increase in demand in February 2021 due to multiple days of severe cold as compared to the six months ended June 30, 2020.

NGL sales revenues. NGL sales revenues increased by $56.7 million to $84.7 million for the combined six months ended June 30, 2021 as compared to NGL sales revenues of $28.0 million for the six months ended June 30, 2020. An increase in price contributed a $58.6 million positive impact, while a decrease in sales volumes between these periods contributed a $1.9 million negative impact.

For the combined six months ended June 30, 2021, our NGL sales averaged 20.0 MBbl/d. NGL sales volumes decreased by 255 to 3,630 MBbl for the combined six months ended June 30, 2021 as compared to 3,885 MBbl for the six months ended June 30, 2020. The volume decrease is primarily due to the natural decline on existing producing properties, partially offset by the completion of 40 gross wells from July 1, 2020 to June 30, 2021. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.

The average price we realized on the sale of our NGL was $23.33 per Bbl for the combined six months ended June 30, 2021 compared to $7.21 per Bbl for the six months ended June 30, 2020, primarily due to an increase in demand in February 2021 due to multiple days of severe cold as compared to the combined six months ended June 30, 2020.

Lease operating expenses. Our LOE decreased by $26.5 million to $26.9 million for the combined six months ended June 30, 2021, from $53.4 million for the six months ended June 30, 2020. While oil revenue increased for the six months ended June 30, 2021, oil volumes were down for the reasons mentioned above. This allowed the company to optimize our field cost structure during the combined six months ended June 30, 2021. On a per unit basis, LOE decreased to $2.01 per BOE sold for the combined six months ended June 30, 2021 from $3.16 per BOE for the six months ended June 30, 2020.

Transportation and gathering ("T&G"). Our T&G expense increased by $1.9 million to $51.0 million for the combined six months ended June 30, 2021, from $49.1 million for the six months ended June 30, 2020. The increase in T&G was primarily due to revenue contract changes and ~~$2.9~~a decrease in production during the combined six months ended June 30, 2021 compared to the six months ended June 30, 2020. On a per unit basis, T&G increased to $3.80 per BOE sold for the combined six months ended June 30, 2021 compared to $2.91 per BOE sold for the six months ended June 30, 2020.

Production taxes. Our production taxes increased by $17.5 million to $35.6 million for the combined six months ended June 30, 2021 as compared to $18.1 million for the six months ended June 30, 2020. The increase is primarily attributable to increased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 6.9% for the combined six months ended June 30, 2021 as compared to 7.9% for the six months ended June 30, 2020.

Exploration and abandonment expenses. Our exploration and abandonment expenses were $4.7 million for the combined six months ended June 30, 2021. Due to the decrease in pricing, all of the unproved property in our northern field was abandoned and impaired in the first quarter of 2020. For the six months ended June 30, 2020, we recognized $175.1 million in exploration and abandonment expenses.

Depletion, depreciation, amortization and accretion expense. Our DD&A expense decreased $53.9 million to $104.8 million for the combined six months ended June 30, 2021 as compared to $158.7 million for the six months ended June 30, 2020. On a per unit basis, DD&A expense decreased to $7.81 per BOE for the combined six months ended June 30, 2021 from $9.39 per BOE for the six months ended June 30, 2020. These decreases are due to the $326.0

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million downward fair value adjustment to the depletable asset base upon adoption of fresh start reporting, as well as an impairment of $208.5 million of ~~accrued interest~~proved oil and gas properties that occurred during 2020.

Impairment of long lived assets. For the combined six months ended June 30, 2021 and for the six months ended June 30, 2020, impairment expense was $0.2 million and $1.7 million, respectively. The impairment expense recorded for the six months ended June 30, 2020 related to ~~an alleged breach~~the proved oil and gas properties in ~~contract.~~our northern field as the fair value did not exceed the carrying amount associated with the properties.

General and administrative expenses ("G&A"). General and administrative expenses decreased by $15.0 million to $20.7 million for the combined six months ended June 30, 2021 as compared to $35.7 million for the six months ended June 30, 2020. This decrease is primarily due to reductions of workforce during the first and second quarters of 2020, and a decrease in stock-based compensation expense recognized for the six months ended June 30, 2020 compared to the combined six months ended June 30, 2021. On a per unit basis, G&A expense decreased to $1.54 per BOE sold for the combined six months ended June 30, 2021 from $2.12 per BOE sold for the six months ended June 30, 2020.

Our G&A expenses for the six months ended June 30, 2020 includes $2.5 million related to the terms of separation agreements with two former executive officers. No expenses of this nature were incurred during the combined six months ended June 30, 2021.

Our G&A expenses include the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the combined six months ended June 30, 2021, there was $5.2 million of stock-based compensation expense. For the six months ended June 30, 2020, there was $2.6 million of stock-based compensation expense.

Other operating expenses. Other operating expenses decreased by $59.3 million to $10.4 million for the combined six months ended June 30, 2021 as compared to $69.7 million for the six months ended June 30, 2020. This $59.3 million decrease is primarily due to year-over-year decreases in litigation expense of $47.2 million and early termination penalties of $9.1 million.

Commodity derivative gain (loss). Primarily due to the increase in NYMEX crude oil ~~future~~futures prices at ~~September~~June 30, ~~2020~~2021 as compared to ~~June 30,~~December 31, 2020 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of ~~$9.7~~$116.9 million for the ~~three~~combined six months ended ~~September~~June 30, ~~2020.~~2021. Primarily due to the decrease in NYMEX crude oil futures prices at ~~September~~June 30, ~~2019~~2020 as compared to ~~June 30,~~December 31, 2019 and change in fair value from the execution of new positions and unwinds of existing positions, we incurred a net gain on our commodity derivatives of ~~$88.0~~$193.7 million for the ~~three~~six months ended ~~September~~June 30, ~~2019, including the amortization of premiums.~~2020. These gains and losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. During the ~~three~~combined six months ended ~~September~~June 30, ~~2020,~~2021, we ~~received~~paid commodity

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derivatives totaling ~~$14.0~~$29.9 million. During the ~~three~~six months ended ~~September~~June 30, ~~2019,~~2020, we received settlements of commodity derivatives totaling ~~$16.1~~$166.7 million.

~~Reorganization items, net.~~ Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we have incurred and will continue to incur significant costs associated with our reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. For the three months ended September 30, 2020, we recognized $501.1 million in reorganization items. No reorganization items were recognized during the same period in the preceding year. Please see to ~~Note 5—Reorganization Items, Net~~ ~~in Part I, Item I, Financial Information of this Quarterly Report.~~

~~Interest expense.~~ Interest expense consists of interest expense on our long-term debt and amortization of debt issuance costs, net of capitalized interest. For the three months ended September 30, 2020, we recognized interest expense of $7.4 million as compared to $23.2 million for the three months ended September 30, 2019, as a result of borrowings under our DIP Credit Facility, our Credit Facility, our 2024 Senior Notes, our 2026 Senior Notes and the amortization of debt issuance costs. As a result of the Chapter 11 Cases, no interest has been accrued on our 2024 and 2026 Senior Notes since June 14, 2020.

We incurred interest expense for the three months ended September 30, 2020 of $8.1 million related to our Credit Facility and DIP Credit Facility. We incurred interest expense for the three months ended September 30, 2019 of approximately $23.9 million related to our Credit Facility, our 2024 Senior Notes, and our 2026 Senior Notes. Also included in interest expense for the three months ended September 30, 2020 and 2019 was the amortization of debt issuance costs of $0.2 million and $1.0 million, respectively. For the three months ended September 30, 2020 and 2019, we capitalized interest expense of $0.9 million and $1.6 million, respectively.

~~Income tax expense.~~ We recorded no income tax expense for the three months ended September 30, 2020 and $14.8 million of income tax expense for the three months ended September 30, 2019. This resulted in an effective tax rate of approximately zero and 30.4% for the three months ended September 30, 2020 and 2019, respectively. Our effective tax rate for the three months ended September 30, 2020 and 2019 differs from the U.S. statutory income tax rates of 21.0% primarily due to the effects of state income taxes, estimated taxable permanent differences, and valuation allowance.

~~Gathering and facilities segment.~~ Prior to March 31, 2020, we had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction, operation and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Please see ~~Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC~~ in Part I, Item I, Financial Information of this Quarterly Report for further information related to the deconsolidation of Elevation Midstream, LLC. After March 31, 2020, Extraction began reporting as a single reportable segment.

~~Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019~~

~~Oil sales revenues.~~ Crude oil sales revenues decreased by $230.0 million to $271.6 million for the nine months ended September 30, 2020 as compared to crude oil sales of $501.6 million for the nine months ended September 30, 2019. A decrease in sales volumes between these periods contributed a $50.4 million negative impact, and a decrease in crude oil prices contributed a $179.6 million negative impact. For the nine months ended September 30, 2020, crude oil revenue decreased by approximately $12.3 million as compared to a crude oil revenue decrease of approximately $22.2 million for the nine months ended September 30, 2019 due to the contract term impacting the amount of consideration that can be included in the transaction price which reduced oil sales revenue pursuant to ASC 606.

For the nine months ended September 30, 2020, our crude oil sales averaged 35.6 MBbl/d. Our crude oil sales volume decreased by 10% to 9,741 MBbl for the nine months ended September 30, 2020 compared to 10,830 MBbl for the nine months ended September 30, 2019. The volume decrease is primarily due to the natural decline of our existing properties and 0.4 MBbl of oil that was produced but not sold due to line fill requirements under our long-term crude oil delivery commitment agreement, partially offset by an increase in production from the completion of 51 gross wells from October 1, 2019 to September 30, 2020.

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The average price we realized on the sale of crude oil was $27.88 per Bbl for the nine months ended September 30, 2020 compared to $46.31 per Bbl for the nine months ended September 30, 2019, primarily due to changes in market prices for crude oil and the decreases of $12.3 million and $22.2 million, respectively, in crude oil revenue explained above.

~~Natural gas sales revenues.~~ Natural gas sales revenues decreased by $11.7 million to $62.7 million for the nine months ended September 30, 2020 as compared to natural gas sales revenues of $74.4 million for the nine months ended September 30, 2019. An increase in sales volumes between these periods contributed a $19.5 million positive impact, while a decrease in natural gas prices contributed a $31.2 million negative impact.

For the nine months ended September 30, 2020, our natural gas sales averaged 200.1 MMcf/d. Natural gas sales volumes increased by 11,390 to 54,823 MMcf for the nine months ended September 30, 2020 as compared to 43,433 MMcf for the nine months ended September 30, 2019. The volume increase is primarily due to the completion of 51 gross wells from October 1, 2019 to September 30, 2020, partially offset by the natural decline on existing producing properties.

The average price we realized on the sale of our natural gas was $1.14 per Mcf for the nine months ended September 30, 2020 compared to $1.71 per Mcf for the nine months ended September 30, 2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative commodity price environment due to oversupply and a decrease in demand.

~~NGL sales revenues.~~ NGL sales revenues increased by $5.9 million to $50.8 million for the nine months ended September 30, 2020 as compared to NGL sales revenues of $44.9 million for the nine months ended September 30, 2019. An increase in sales volumes between these periods contributed a $21.1 million positive impact, while a decrease in price contributed a $15.2 million negative impact.

For the nine months ended September 30, 2020, our NGL sales averaged 22.0 MBbl/d. NGL sales volumes increased by 1,934 to 6,031 MBbl for the nine months ended September 30, 2020 as compared to 4,097 MBbl for the nine months ended September 30, 2019. The volume increase is primarily due to the completion of 51 gross wells from October 1, 2019 to September 30, 2020, partially offset by the natural decline on existing producing properties. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.

The average price we realized on the sale of our NGL was $8.42 per Bbl for the nine months ended September 30, 2020 compared to $10.97 per Bbl for the nine months ended September 30, 2019, primarily due to capacity constraints in transporting the wet gas associated with crude oil production coupled with a negative commodity price environment due to oversupply and a decrease in demand.

~~Lease operating expenses.~~ Our LOE decreased by $2.6 million to $65.8 million for the nine months ended September 30, 2020, from $68.4 million for the nine months ended September 30, 2019. The decrease in LOE was primarily the result of optimization of our field cost structure during the nine months ended September 30, 2020. On a per unit basis, LOE decreased to $2.64 per BOE sold for the nine months ended September 30, 2020 from $3.09 per BOE for the nine months ended September 30, 2019.

~~Transportation and gathering.~~ Our T&G expense increased by $70.2 million to $99.3 million for the nine months ended September 30, 2020, from $29.1 million for the nine months ended September 30, 2019. The increase in T&G was primarily due to an increase of volumes on a certain gathering system and a change in oil contracts during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. On a per unit basis, T&G increased to $3.98 per BOE sold for the nine months ended September 30, 2020 compared to $1.31 per BOE sold for the nine months ended September 30, 2019.

~~Production taxes.~~ Our production taxes decreased by $26.6 million to $19.8 million for the nine months ended September 30, 2020 as compared to $46.4 million for the nine months ended September 30, 2019. The decrease is primarily attributable to decreased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 5.1% for the nine months ended September 30, 2020 as compared to 7.5% for the nine months ended September 30, 2019. The decrease in production taxes as a percentage of sales

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~~revenue relates to a decrease in the estimated ad valorem and severance tax rates and an adjustment to the estimated ad valorem tax payable for the nine months ended September 30, 2020.~~

~~Exploration and abandonment expenses.~~ Our exploration and abandonment expenses were $184.9 million for the nine months ended September 30, 2020, of which $179.0 million was lease abandonment expense. Due to the decrease in pricing, all of the unproved property in our northern field was abandoned and impaired in the first quarter of 2020. For the nine months ended September 30, 2019, we recognized $32.7 million in exploration and abandonment expenses.

~~Depletion, depreciation, amortization and accretion expense.~~ Our DD&A expense decreased $108.1 million to $244.0 million for the nine months ended September 30, 2020 as compared to $352.1 million for the nine months ended September 30, 2019. On a per unit basis, DD&A expense decreased to $9.79 per BOE for the nine months ended September 30, 2020 from $15.89 per BOE for the nine months ended September 30, 2019. This decrease is due to an impairment of $1.3 billion of proved oil and gas properties that occurred during the fourth quarter of 2019.

~~Impairment of long lived assets.~~ For the nine months ended September 30, 2020 and 2019, impairment expense was $1.6 million and $11.2 million, respectively, related to impairment of the proved oil and gas properties in our northern field as the fair value did not exceed the carrying amount associated with the properties.

~~General and administrative expenses.~~ General and administrative expenses decreased by $38.4 million to $47.4 million for the nine months ended September 30, 2020 as compared to $85.8 million for the nine months ended September 30, 2019. This decrease is primarily due to reductions of workforce during the first and second quarters of 2020, and a decrease in stock-based compensation expense recognized for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. On a per unit basis, G&A expense decreased to $1.90 per BOE sold for the nine months ended September 30, 2020 from $3.87 per BOE sold for the nine months ended September 30, 2019.

Our G&A expenses include the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the nine months ended September 30, 2020, there was $4.3 million of stock-based compensation expense. For the nine months ended September 30, 2019, stock-based compensation expense was $39.3 million.

~~Other operating expenses.~~ Other operating expenses were $75.5 million for the nine months ended September 30, 2020. This amount is primarily made up of a $46.8 million loss contingency from an alleged breach in contract stemming from a purported failure to complete the pipeline extensions connecting certain wells to the Badger central gathering facility prior to April 1, 2020, $2.9 million of accrued interest related to the aforementioned alleged breach in contract, a $13.2 million early termination fee related to the termination of our crude oil marketing contract, a $7.5 million charge to income for expenses related to a workforce reduction in February and May 2020, a $2.4 million charge to income for expenses related to certain drilling rig standby charges during the second quarter of 2020 and a $2.4 million charge to income for interest expense on unpaid production taxes.

~~Commodity derivative gain.~~ Primarily due to the decrease in NYMEX crude oil futures prices at September 30, 2020 as compared to December 31, 2019 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of $184.0 million for the nine months ended September 30, 2020. Primarily due to the decrease in NYMEX crude oil futures prices at September 30, 2019 as compared to December 31, 2018 and change in fair value from the execution of new positions, we incurred a net gain on our commodity derivatives of $39.4 million for the nine months ended September 30, 2019, including the amortization of premiums. These gains are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. During the nine months ended September 30, 2020, we settled commodity derivatives totaling $180.8 million with $84.7 million in cash received and $96.1 million in unwound derivatives that reduced the amount drawn on the Credit Facility. During the nine months ended September 30, 2019, we paid settlements of commodity derivatives totaling $8.4 million.

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Loss on deconsolidation of Elevation Midstream, LLC. On March 16, 2020, we deconsolidated Elevation Midstream, LLC. Upon deconsolidation, we elected the fair value option to remeasure the Elevation equity method investment and determined it had no fair value. The Company recorded a $73.1 million loss on deconsolidation of Elevation Midstream, LLC in the condensed consolidated statements of operations for the ~~nine~~six months ended ~~September~~June 30, 2020.

Reorganization items, net. Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we have incurred ~~and will continue to incur~~ significant costs associated with our reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. For the ~~nine~~combined six months ended ~~September~~June 30, ~~2020,~~2021, we recognized ~~$528.0~~a $873.9 million gain in reorganization ~~items. No~~items, net due to emergence from bankruptcy and a gain on settlement of liabilities subject to compromise. A loss from reorganization items ~~were~~of $26.9 million was recognized during the ~~same period in the preceding year. Please see to~~ six months ended June 30, 2020.

~~Note 5—Reorganization Items, Net~~ ~~in Part I, Item I, Financial Information~~Table of ~~this Quarterly Report.~~Contents

Interest expense. Interest expense consists of interest expense on our long-term debt and amortization of debt issuance costs, net of capitalized interest. For the ~~nine~~combined six months ended ~~September~~June 30, ~~2020,~~2021, we recognized interest expense of ~~$49.1~~$6.7 million as compared to ~~$54.8~~$41.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, as a result of borrowings under our RBL Credit Facility, DIP Credit Facility, ~~our~~Prior Credit Facility, ~~our~~ 2024 Senior Notes, ~~our~~ 2026 Senior Notes and the amortization of debt issuance costs. ~~As a result of the Chapter 11 Cases, no interest has been accrued on our 2024 and 2026 Senior Notes since June 14, 2020.~~

We incurred interest expense for the ~~nine~~combined six months ended ~~September~~June 30, ~~2020~~2021 of ~~$50.6~~ $5.9��million related to our ~~2024 Senior Notes, 2026 Senior Notes,~~RBL Credit Facility, Prior Credit Facility and DIP Credit Facility. We incurred interest expense for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 of approximately ~~$66.9~~$42.5 million related to our Prior Credit Facility and DIP Credit Facility, our 2024 Senior Notes, and our 2026 Senior Notes. Also included in interest expense for the ~~nine~~combined six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~for the six months ended June 30, 2020 was the amortization of debt issuance costs of ~~$3.3~~$1.0 million and ~~$3.8~~$3.2 million, respectively. For the ~~nine~~combined six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~for the six months ended June 30, 2020, we capitalized interest expense of ~~$4.9~~$0.2 million and ~~$5.4~~$4.0 million, respectively. ~~Interest expense for the nine months ended September 30, 2019 also includes $10.5 million of gain on debt extinguishment upon the repurchase of our 2026 Senior Notes.~~

Income tax expense. We recorded income tax expense of $28.1 million for the combined six months ended June 30, 2021 and $2.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020 and $0.9 million for the nine months ended September 30, 2019.~~2020. This resulted in an effective tax rate of approximately ~~(0.27)%~~19.9% and ~~(5.7)~~(0.8)% for the ~~nine~~combined six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~for the six months ended June 30, 2020, respectively. Our effective tax ~~rate for the nine months ended September 30, 2020 and 2019 differs~~rates differ from the U.S. statutory income tax ~~rates~~rate of 21.0% primarily due to the effects of state income taxes, estimated taxable permanent differences, and valuation allowance.

~~Gathering and facilities segment.~~ Prior to March 31, 2020, we had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction, operation and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Please see ~~Note 1—Business and Organization — Deconsolidation of Elevation Midstream, LLC~~ ~~in Part I, Item I, Financial Information of this Quarterly Report for further information related to the deconsolidation of Elevation Midstream, LLC.~~

In October 2019, Elevation commenced moving crude oil, natural gas and water through its Badger central gathering facility. Because Elevation had no revenue and insignificant operating expenses for the three and nine months ended September 30, 2019, comparison to the three and nine months ended September 30, 2020 is not relevant. Extraction's condensed consolidated statements of operations for the three months ended September 30, 2020 did not contain any Elevation activity due to their deconsolidation on March 16, 2020. The following amounts were incurred entirely during the first quarter of 2020, but are still included in the nine months ended September 30, 2020. During the first quarter of 2020, the gathering and facilities segment had revenues of $6.0 million and direct operating expenses of $3.9 million. General and administrative expenses were $0.7 million for the nine months ended September 30, 2020 and $3.7 million for the nine months ended September 30, 2019. Depreciation expense was $1.1 million during the first quarter of 2020 as the gathering facility was placed into service during the fourth quarter of 2019. Please see ~~Note 16—Segments~~ ~~in Part I, Item I, Financial Information of this Quarterly Report.~~

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Liquidity and Capital Resources

~~Chapter 11 Cases and Effect of Automatic Stay~~

On June 14, 2020, we filed for relief under chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing our Senior Notes, resulting in the automatic and immediate acceleration of all of our outstanding debt under the Credit Agreement and the Senior Notes. Any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. On June 14, 2020, we also entered into the RSA with certain holders of our Senior Notes to support a restructuring in accordance with the terms set forth therein. As more fully disclosed in ~~Note 1—Business and Organization and~~ ~~Note 6~~—~~Long-Term Debt~~ in Part I, Item 1. Financial Information of this Quarterly Report, the RSA contemplates a financial restructuring which would provide for the treatment of holders of certain claims and existing equity interests.

We expect to continue operations in the ordinary course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy Court of the First Day Motions to continue our ordinary course operations after the filing date. In addition, we have obtained a DIP Credit Facility to fund operations during the bankruptcy proceedings. However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our creditors. The significant risks and uncertainties related to our liquidity and Chapter 11 Cases described above raise substantial doubt about our ability to continue as a going concern. There can be no assurance that we will confirm and consummate a Restructuring Plan as contemplated by the RSA or complete another plan of reorganization with respect to the Chapter 11 Cases. As a result, we have concluded that management’s plans do not alleviate substantial doubt about our ability to continue as a going concern.

As a result of the Chapter 11 Cases, our total available liquidity as of September 30, 2020 consisted of cash on hand of $121.2 million. With cash on hand and DIP Credit Facility availability, we believe that we will have sufficient liquidity, including funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments.

Sources of Liquidity and Capital Resources

Please see Note 1—Business and Organization—Voluntary Reorganization under Chapter 11 of the Bankruptcy Codein Item 1 of the Company’s filed Form 10-Q from the first quarter of 2021 for information regarding our capital structure following emergence from bankruptcy on January 20, 2021.

Historically, our primary sources of liquidity have been borrowings under our ~~Credit Facility,~~credit facilities, proceeds from ~~notes~~securities offerings and ~~preferred stock offerings, equity provided by investors, including~~cash proceeds from divestitures of our ~~management team, cash from issuance of preferred stock,~~oil and ~~cash flows from divestitures~~gas properties and from the sale of oil, gas and NGL production. During the combined six months ended June 30, 2021, our primary sources of liquidity came from issuing New Common Stock, borrowings on our new RBL Credit Facility and cash from operations. Our primary uses of capital have been for the ~~acquisition~~repayment of borrowings on the RBL Credit Facility and development of our oil and gas ~~properties to increase our acreage position, as well as development and exploration of oil and gas~~ properties.

As of ~~September~~June 30, ~~2020,~~2021, our ~~DIP~~outstanding RBL Credit Facility borrowings were ~~$110.0~~$90.0 million. Our total available liquidity as of June 30, 2021 consisted of cash and cash equivalents of $34.4 million ~~with $75.0~~and $409.5 million ~~total outstanding including amounts that were rolled over from~~of availability on the RBL Credit Facility. ~~Our~~As of the date of this filing, we had drawn $70.0 million on the RBL Credit Facility ~~borrowings were $453.7 million~~ and $470.0 million at September 30, 2020, and December 31, 2019, respectively. We had senior notes totaling $1.1 billion outstanding at September 30, 2020 and December 31, 2019. We also have other contractual commitments, which are described in ~~Note 14—Commitments and Contingencies~~ ~~in Part I, Item 1, Financial Information of this Quarterly Report~~.

~~With the Bankruptcy Court’s authorization of the DIP~~total funds available for borrowing under our RBL Credit Facility, after giving effect to an aggregate of $0.5 million of undrawn letters of credit, were $429.5 million. With available borrowings under our RBL Credit Facility and cash flow from operations, we believe ~~that~~ we have sufficient ~~liquidity~~sources of cash to ~~execute~~meet our ~~business plan through~~obligations for the ~~bankruptcy proceedings.~~next twelve months.

We ~~plan to continue our practice of entering~~enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from ~~operations. Under this strategy,~~operations, or alternatively, we ~~intend~~may decide to ~~enter~~unwind or restructure the hedging arrangements into ~~commodity derivative contracts at times and on terms desired~~which we previously entered. The RBL Credit Agreement requires us to maintain commodity hedges covering a ~~portfolio~~minimum of ~~commodity derivative contracts covering approximately 50% to 70%~~65% of our ~~projected~~anticipated oil and ~~natural~~ gas production ~~over a one~~from PDP reserves for the succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the next succeeding twelve months.

Material Cash Requirements

Our material short-term cash requirements include payments under our short-term lease agreements, recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. Working capital, defined as total current assets less total current liabilities, fluctuates depending on commodity pricing and effective management of receivables from our purchasers and working interest partners and payables to ~~two year period at a given point in time, although we may from time to time hedge more or less than this approximate range.~~our vendors.

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We had a Stock Repurchase Program that ended in 2019. During the nine months ended September 30, 2019, spending under this program was $136.9 million. We also had a Senior Notes Repurchase Program in place. Spending under this program during the nine months ended September 30, 2019 was $39.3 million. No common stock or Senior Notes were repurchased during the nine months ended September 30, 2020.As commodity prices improve, our working capital requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity hedge contracts.

Our long-term material cash requirements from currently known obligations include repayment of outstanding borrowings and interest payment obligations under our RBL Credit Facility, settlements on our outstanding commodity hedge contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and operating lease obligations. The following table summarizes our estimated material cash requirements for known obligations as of June 30, 2021 (in thousands). This table does not include repayments of outstanding borrowings on our RBL Credit Facility, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. This table also does not include amounts payable under obligations where we cannot forecast with certainty the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement.


	Payments Due by Period
Material Cash Requirements	Total		<1 Year		1-3 Years		3-5 Years		>5 Years
Asset retirement obligations(1)	$	88,714	$	13,976	$	22,473	$	28,725	$	23,540
Operating leases(2)	8,428		4,537		3,891		—		—
Total	$	97,142	$	18,513	$	26,364	$	28,725	$	23,540

_______________

(1) Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug and abandon oil and gas wells, remediate oil and gas properties and dismantle their related plants and facilities.

(2) We have operating leases for certain compressors, office facilities and equipment. The obligations reported above represent our minimum financial commitments pursuant to the terms of these contracts, however our actual expenditures under these contracts may exceed the minimum commitments presented above. Refer to Note 7—Leases to the Company’s consolidated financial statements in its Annual Report for more information.

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Cash Flows

The following table summarizes our cash flows for the periods indicated (in thousands):


		For the Nine Months Ended					Successor		Predecessor
		September 30,					For the Period from January 21 through June 30,		For the Period from January 1 through January 20,		For the Six Months Ended June 30,
		2020		2019			2021		2021		2020
Net cash provided by operating activities	Net cash provided by operating activities	$	149,053	$	356,561	Net cash provided by operating activities	$	141,769	$	15,346	$	83,954
Net cash used in investing activities	Net cash used in investing activities	$	(216,649)	$	(706,868)	Net cash used in investing activities	(41,173)		(9,120)		(191,413)
Net cash provided by financing activities		$	164,107	$	173,049
Net cash provided by (used in) financing activities						Net cash provided by (used in) financing activities	(176,831)		(101,454)		145,358

~~Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019~~

Net cash provided by operating ~~activities.~~activities

~~For the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019, our net~~

Net cash provided by operating activities ~~decreased by $207.5 million~~for the 2021 Successor period consisted primarily ~~due~~of cash receipts and disbursements attributable to our normal operating cycle. The 2021 Predecessor period also consisted primarily of cash receipts and disbursements attributable to our normal operating cycle, but also contained reorganization costs related to the ~~decrease in~~Company’s bankruptcy and subsequent emergence. Net cash provided by operating ~~revenues net~~activities for the 2020 Predecessor period was primarily comprised of ~~expenses~~settlements on commodity derivatives of ~~$279.2~~$65.4 million ~~primarily as a result of a decrease in commodity prices~~ and ~~a decrease of $60.6 million~~collections on accounts receivable related to ~~changes in working capital when excluding the $494.4 million change in accrued damages for rejected~~oil, natural gas and ~~settled contracts. These decreases were offset by a decrease~~NGLs of ~~$37.7 million in cash paid for interest and an increase of $95.5 million in commodity derivative settlement payments received.~~$56.8 million.

Net cash used in investing ~~activities.~~activities

For the ~~nine~~combined six months ended ~~September~~June 30, ~~2020,~~2021, net cash used in investing activities decreased by ~~$490.2~~$141.1 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 primarily as a result of ~~$307.8~~$129.1 million less spent on oil and gas property additions, ~~$173.4~~$10.0 million less spent on ~~gathering systems and facilities, $29.0~~our investment in unconsolidated subsidiaries, $2.5 million less spent on other property and equipment and ~~$12.5 million less spent on our investment~~an increase in ~~unconsolidated subsidiaries. Proceeds~~proceeds from the sale of assets ~~was $30.8~~of $9.1 million, ~~less during~~partially offset by an increase of $5.5 million spent on the ~~first nine months~~acquisition of ~~2020 than during~~properties in the ~~same~~current period and a decrease of $4.2 million from the prior period to the current period in ~~2019.~~the return of capital from gathering systems.

Net cash provided by ~~financing activities.~~ ~~For the nine months ended September 30, 2020, net cash provided by~~(used in) financing activities ~~was $8.9 million less than~~

Net cash used in financing activities for the ~~nine months ended September 30, 2019~~2021 Successor period consisted primarily ~~as a result~~ of ~~$137.7~~net repayments under our RBL Credit Facility in the amount of $183.7 million spent to repurchase common stock, $39.3 million spent to repurchase 2026 Senior Notes, $8.2 million spent on Preferred Stock Dividends, and $2.5 million spent on preferred stock issuance costs during the first nine months of 2019, partially offset by ~~$99.0~~$7.0 million ~~received~~of proceeds from the issuance of ~~Preferred Units, which did not occur during first nine months of 2020. Further, payments of employee payroll withholding taxes were $1.0~~common stock. We drew $145.5 million, ~~less and payments of deferred financing costs were $0.8 million less compared to the first nine months of 2019. Also,~~ net ~~borrowings~~ on ~~the~~our Prior Credit Facility and DIP Credit Facility during the ~~first nine~~six months ~~of 2020 were $99.5 million less compared to the first nine months of 2019.~~ended June 30, 2020.

During the Predecessor period from January 1, 2021 to January 20, 2021, we extinguished both our Prior Credit Facility in the amount of $453.9 million and DIP Credit Facility in the amount of $106.7 million. Prior to and upon emergence, we drew $265.0 million on our newly established RBL Credit Facility and issued New Common Stock in the amount $200.5 million. We also incurred $6.3 million of debt issuance costs and other financing fees.

Working Capital

Working capital is defined as total current assets less total current liabilities. Our working capital deficit was ~~$338.7~~$232.5 million and ~~$240.8~~$369.4 million at ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively. However, as of ~~September 30,~~December 31, 2020, ~~many of~~ our current liabilities in the amount of $279.6 million were classified as ~~liabilities subject~~“Liabilities Subject to ~~compromise.~~Compromise” (excluding approximately $1.8 billion of debt, accrued interest, damages for rejected and settled contracts and other). Our cash ~~balances~~and cash equivalents totaled ~~$121.2~~$34.4 million and ~~$32.4~~$205.9 million at ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively.

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Due to ~~the~~ amounts that we incur related to our drilling and completion program and the timing of such expenditures, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our RBL Credit Facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, ~~commodity prices and differentials to NYMEX~~realized prices for our oil, natural gas and NGL production will be the largest variables affecting our working ~~capital along with reorganization costs pertaining to the bankruptcy. As part of~~

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the Chapter 11 Cases, the Company filed a motion to reject its drilling rig contracts. As such, the Company recorded $6.7 million in liabilities subject to compromise on the condensed consolidated balance sheets as of September 30, 2020 and in reorganization items, net on the condensed consolidated statements of operations. Please see ~~Note 14—Commitments and Contingencies~~ ~~and~~ ~~Note 1—Business and Organization — Ability to Continue as a Going Concern~~ ~~in Part I, Item 1. Financial Information of this Quarterly Report.~~capital.

Debt Arrangements

For details of our ~~debt arrangements including our DIP~~RBL Credit Facility, ~~Credit Facility, 2024 Senior Notes and 2026 Senior Notes,~~ please see Note 6—4—Long-Term Debt in ~~Part I,~~ Item ~~1. Financial Information~~1 of this Quarterly Report. ~~Additional debt disclosures specific to this~~ ~~Management Discussion and Analysis~~ ~~section are as follows.~~

If we experience certain kinds of changes of control, holders of our 2024 and 2026 Senior Notes may have the right to require us to repurchase their notes at 101% of the principal amount of the notes, plus accrued and unpaid interest, if any, to the date of purchase.

Equity Arrangements

For details of our equity arrangements, ~~including our Series A Preferred Stock and Elevation Preferred Units,~~ please see Note ~~12—~~10—Equity in ~~Part I,~~ Item ~~1. Financial Information~~1 of this Quarterly Report.

Critical Accounting Policies and Estimates

Effective June 14, 2020 for the Predecessor Company, as a result of the filing of the Chapter 11 Cases, we began accounting and reporting according to ASC ~~852—Reorganizations~~,852, which specifies the accounting and financial reporting requirements for entities reorganizing through chapter 11 bankruptcy proceedings. These requirements include distinguishing transactions associated with the reorganization separate from activities related to ongoing operations of the business. ASC 852 did not apply to the Successor Company.

There were no other material changes to ~~our~~the Company’s critical accounting policies and estimates from those disclosed in ~~our~~its Annual ~~Report on Form 10-K for the year ended December 31, 2019 other than the deconsolidation of Elevation Midstream, LLC discussed in~~ ~~Note 1—Business and Organization~~ ~~in Part I, Item 1. Financial Information of this Quarterly~~ Report.

Recent Accounting Pronouncements

Please see Note 2—Basis of Presentation, Significant Accounting Policies and Recent Accounting Pronouncements in ~~Part 1,~~ Item 1 of this Quarterly Report for a detailed list of recent accounting pronouncements.

Impact of Inflation/Deflation and Pricing

All of our transactions are denominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to declining commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the ~~year ended December 31, 2019, commodity prices increased during the first, second and third quarter, and subsequently decreased in the fourth quarter. During the nine~~six months ended ~~September~~June 30, 2020, commodity prices ~~decreased~~decreased. During the combined six months ended June 30, 2021, commodity prices increased compared to the same period in ~~2019.~~2020. Changes in commodity prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel.

Off-Balance Sheet Arrangements

As of ~~September~~June 30, ~~2020,~~2021, we did not have material off-balance sheet arrangements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

We are ~~exposed to market risk, including the effects of adverse changes in commodity prices and interest rates~~a smaller reporting company as ~~described below. The primary objective~~defined by Rule 12b-2 of the ~~following information is~~Exchange Act and are not required to provide ~~quantitative and qualitative~~the information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. LIBOR is used as a reference rate for certain of our financial instruments, such as our Credit Facility. LIBOR is set to be phased out at the end of 2021. We are currently reviewing how the LIBOR phase-out will affect the Company, but we do not expect the impact to be material.required under this item.

~~Commodity Price Risk~~

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGL has been volatile and unpredictable for several years and this volatility is expected to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we have periodically entered into commodity derivative contracts with respect to certain of our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil price fluctuations.

~~For a summary of our commodity derivative contracts as of September 30, 2020, please see~~ ~~Note 7—Commodity Derivative Instruments~~ ~~in Part 1, Item 1 of this Quarterly Report.~~

As of September 30, 2020, the fair market value of our oil derivative contracts was a net asset of $32.9 million. Based on our open oil derivative positions at September 30, 2020, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $11.9 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $11.1 million. As of September 30, 2020, the fair market value of our natural gas derivative contracts was a net liability of $0.9 million. Based upon our open commodity derivative positions at September 30, 2020, a 10% increase in the NYMEX Henry Hub price would increase our net natural gas derivative liability by approximately $2.2 million, while a 10% decrease in the NYMEX Henry Hub price would decrease our net natural gas derivative liability by approximately $2.2 million, which would result in a net asset position. Please see “—How We Evaluate Our Operations—Derivative Arrangements.”

On June 14, 2020 we filed for relief under Chapter 11, which permitted the counterparties to our derivative instruments to terminate their outstanding hedges, and certain of our counterparties elected to exercise their right to terminate. Please refer to ~~Note 7—Commodity Derivative Instruments~~ in Part I, Item 1. Financial Information of this Quarterly Report for more information on these terminations, the effect such terminations will have on our cash flows, financial position and results of operations and other subsequent hedging activity.

~~Counterparty and Customer Credit Risk~~

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.

We sell oil, natural gas and NGL to various types of customers, including pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside of our control, none of

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which can be predicted with certainty. For the nine months ended September 30, 2020, we had certain major customers that exceeded 10% of total oil, natural gas and NGL revenues. We do not believe the loss of any single purchaser would materially impact our operating results because oil, natural gas and NGL are fungible products with well-established markets and numerous purchasers.

At September 30, 2020, we had commodity derivative contracts with 2 counterparties. We do not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Additionally, we use master netting agreements to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review. For the three and nine months ended September 30, 2020 and 2019, we did not incur any losses with respect to counterparty contracts. None of our existing derivative instrument contracts contain credit risk related contingent features.

~~Interest Rate Risk~~

At September 30, 2020, we had $110.0 million variable-rate debt outstanding related to our DIP Credit Facility. The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $1.1 million per year. At September 30, 2020, we had $453.7 million variable-rate debt outstanding related to our Credit Facility. The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $4.5 million per year. We may begin entering into interest rate swap arrangements on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR if we have variable-rate debt outstanding in the future. Please see “—Liquidity and Capital Resources—Debt Arrangements.”

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded,

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processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and to ensure that such information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. Based upon that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were ~~not~~ effective as of ~~September 30, 2020, due to the material weakness in internal control over financial reporting as described below.~~

~~Management's Material Weakness Remediation Plan~~

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Management determined that the Company did not design and maintain effective controls to determine the appropriate contract termination date and evaluate the potential accounting implications of changes in termination dates of contracts with customers. This material weakness resulted in a restatement of the Company’s condensed consolidated financial statements as of and for the three and nine month periods ended September 30, 2019 and immaterial errors to the condensed consolidated financial statements for the periods ended December 31, 2018, March 31, 2019 and June 30, 2019. The line items affected were oil sales, accounts payable and accrued liabilities, other non-current liabilities, inventory, prepaid expenses and other, and other non-current assets. Additionally, this material weakness could result in a misstatement of the aforementioned financial statement line items or disclosures that would result in a material misstatement to the annual or interim condensed consolidated financial statements that would not be prevented or detected.

The Company and its Board of Directors are committed to maintaining a strong internal control environment. Management has evaluated the material weakness described above and developed a remediation plan to address the material weakness. The remediation plan includes additional procedures around determining the contract termination

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~~date pursuant to the accounting treatment under~~ ~~ASC 606 - Revenue from Contracts with Customers. Management is committed to successfully implementing the remediation plan and plans to commence the evaluation of its updated design of internal controls for implementation expeditiously.~~2021.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three ~~and nine~~ months ended ~~September~~June 30, ~~2020~~2021 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding our legal proceedings can found in Note ~~14—~~12—Commitments and ~~Contingencies —~~ Contingencies—Litigation and Legal Items in ~~Part I,~~ Item ~~1. Financial Information in~~1 of this Quarterly Report.

ITEM 1A. RISK FACTORS

Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described ~~below and under~~in Item 1A ~~"Risk Factors," included in our~~of the Company’s Annual ~~Report on Form 10-K filed with the SEC on March 12, 2020 and the Quarterly Reports on Form 10-Q filed with the SEC on May 11, 2020 and August 10, 2020.~~Report. The risks described ~~below and~~ in our annual and quarterly reports are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. This information should be considered carefully, together with other information in this ~~report~~Quarterly Report and other reports and materials we file with the SEC.

~~We have substantial liquidity needs and may not be able to obtain sufficient liquidity for the duration of the Chapter 11 Cases or to confirm a plan of reorganization or liquidation.~~

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred, and expect to continue to incur, significant costs associated with our reorganization, primarily from damages for rejected or settled contracts, legal and professional fees, and other costs in connection with the Chapter 11 Cases. As of September 30, 2020, available liquidity consisted of cash on hand of $121.2 million and availability of $15.0 million on the DIP Credit Agreement. We expect to continue using additional cash that will further reduce this liquidity. As is described in ~~Note 6—Long-Term Debt~~ in Part I, Item 1. Financial Information in this Quarterly Report, on July 20, 2020, the Bankruptcy Court approved the Final DIP Order which increased the DIP Credit Facility's aggregate commitments to $125.0 million. In addition to a total of $90.0 million outstanding, we drew $20.0 million on July 27, 2020 leaving $15.0 million of availability on the facility. With the Bankruptcy Court’s approval of the Final DIP Order, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of the Restructuring Plan. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.

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As of September 30, 2020, we have only $15.0 million of availability under our DIP Credit Facility. Unless we are able to successfully discharge or restructure our existing indebtedness, obtain further waivers or forbearance from our existing lenders or otherwise raise significant capital, it is unlikely that we will be able to meet our obligations as they become due, and we may not be able to continue as a going concern.

Our working capital deficit was $338.7 million and $240.8 million at September 30, 2020 and December 31, 2019, respectively. However, as of September 30, 2020, many of our current liabilities were classified as liabilities subject to compromise. Our cash balances totaled $121.2 million and $32.4 million at September 30, 2020 and December 31, 2019, respectively. For the year ended December 31, 2019, the Company incurred net losses of approximately $1.4 billion. Our continuation as a going concern is dependent upon attaining and maintaining profitable operations and, until that time, raising additional capital as needed, but there can be no assurance that we will be able to obtain sufficient financing. Our ability to generate positive cash flow from operations is dependent upon generating sufficient revenues. To date, our operations have been funded by the sale of oil, gas and NGL production based on prevailing market prices, which decreased significantly in March and April 2020. Our operations have also been funded through availability on our DIP Credit Facility and previously, our Credit Facility. As is described in ~~Note 6—Long-Term Debt~~ in Part I, Item 1. Financial Information in this Quarterly Report, on July 20, 2020, the Bankruptcy Court approved the Final DIP Order which increased the DIP Credit Facility's aggregate commitments to $125.0 million. In addition to a total of $90.0 million outstanding, we drew $20.0 million on July 27, 2020 leaving $15.0 million of availability on the facility. With the Bankruptcy Court’s approval of the Final DIP Order, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor and royalty obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of the Restructuring Plan and thus continue as a going concern. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs to continue as a going concern.

The proposed adoption of new rules by the Colorado Oil & Gas Conservation Commission to require, among other things, new siting criteria for any oil and gas locations that are within 2,000 feet from residential building units, could reduce the area available for future oil and gas development in Colorado and have a material adverse effect on our business.

Resulting from Colorado’s adoption of SB181 during 2019, the COGCC is currently in the process of promulgating rules associated with that legislation that, if passed, would among other things, impose mandatory 2,000 foot setbacks for all schools and childcare centers, as well as new siting criteria for any oil and gas locations that are within 2,000 feet from residential building units. The rules additionally require local government permitting approval that could add additional timing and complexity burdens and curtail the pace of our new oil and gas development. A formal vote related to these proposed rules is expected to take place in late November 2020, and if passed, the new rules are expected to take effect on January 1, 2021. We cannot predict the ultimate impact of implementation of these new rules, including the imposition of 2,000-foot siting zones, but their enactment may lead to delays and additional costs to our operations and reduce the area available for future development of our operations.

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

~~None.~~Information regarding our unregistered sales of equity securities can found in Note 1—Business and Organization—Voluntary Reorganization under Chapter 11 of the Bankruptcy Code inItem 1 of the Company’s filed Form 10-Q from the first quarter of 2021.

The 974,056 shares of New Common Stock issued on February 4, 2021 were issued pursuant to the exemption from the registration requirements of the Securities Act, under Section 1145 of the Bankruptcy Code.

The 133,705 shares of New Common Stock issued during the second quarter of 2021 were issued pursuant to the exemption from the registration requirements of the Securities Act, under Section 1145 of the Bankruptcy Code.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Credit Agreement and the indentures governing the Company’s Senior Notes, resulting in the automatic and immediate acceleration of all of the Company’s debt outstanding under the Credit Agreement and Senior Notes. Accordingly, the Company has classified its outstanding senior note debt as liabilities subject to compromise on its condensed consolidated balance sheet as of September 30, 2020. The Credit Facility was not classified as liabilities subject to compromise because it is fully secured in the Chapter 11 Cases and is expected to be unimpaired. Please refer

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to ~~Note 4—Liabilities Subject to Compromise~~ ~~and~~ ~~Note 6—Long-Term Debt~~ ~~in Part I, Item 1. Financial Information in this Quarterly Report.~~Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

(a) Exhibits:

The exhibits listed on the accompanying Exhibit Index are filed, furnished or incorporated by reference as part of this ~~report,~~Quarterly Report, and such Exhibit Index is incorporated herein by reference.

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INDEX TO EXHIBITS

Exhibit #

Description

~~3.1~~2.1

Agreement and Plan of Merger, dated October 17, 2016, by and between Extraction Oil & Gas, Inc. and Extraction Oil & Gas Holdings, LLC. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 21, 2016).

2.2

Sixth Amended Joint Plan of Reorganization of Extraction Oil & Gas, Inc. and its Debtor Affiliates Pursuant to Chapter 11 of the Bankruptcy Code (incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on December 30, 2020).

2.3

Agreement and Plan of Merger, dated as of May 9, 2021, by and among Bonanza Creek Energy, Inc., Raptor Eagle Merger Sub, Inc. and Extraction Oil & Gas, Inc.(incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on May 10, 2021).

2.4

Agreement and Plan of Merger, dated as of June 6, 2021, by and among Bonanza Creek Energy, Inc., Raptor Condor Merger Sub 1, Inc., Raptor Condor Merger Sub 2, LLC, Crestone Peak Resources LP, CPPIB Crestone Peak Resources America Inc., Crestone Peak Resources Management LP and Extraction Oil & Gas, Inc (incorporated by reference to Exhibit 2 .1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on June 8, 2021).

2.5

Amendment No. 1 to Agreement and Plan of Merger, dated as of June 6, 2021, by and among Bonanza Creek Energy, Inc., Raptor Eagle Merger Sub, Inc. and Extraction Oil & Gas, Inc (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on June 8, 2021).

3.1

Amended and Restated Certificate of Incorporation of Extraction Oil & Gas, Inc.~~, dated October 11, 2016~~ (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on ~~October 14, 2016)~~January 20, 2021).

3.2

Certificate of Designations of Series A Preferred Stock of Extraction Oil & Gas, Inc., filed with the Secretary of State of the State of Delaware on October 17, 2016 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on October 21, 2016).

~~3.3~~

Amended and Restated Bylaws of Extraction Oil & Gas, Inc.~~, dated October 11, 2016~~ (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on ~~October 14, 2016)~~January 20, 2021).

~~10.~~110.1

~~Superpriority Senior Secured Debtor-in-Possession~~Amendment No. 2 to Credit Agreement, dated ~~as of June 16, 2020,~~May 6, 2021, by and among ~~Extraction Oil & Gas, Inc.,~~ the ~~subsidiary~~Company, as borrower, certain subsidiaries of the Company, as guarantors, ~~party thereto,~~ the lenders party thereto and Wells Fargo Bank, National Association, ~~(incorporated~~as administrative agent for the Lenders and as issuing lender.

10.2

Voting Agreement, dated as of May 9, 2021, by and among Bonanza Creek Energy, Inc., Extraction Oil & Gas, Inc. and Kimmeridge Energy Management Company, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on ~~July 24, 2020)~~May 10, 2021).

10 .210.3

Amendment No. 13 to ~~Superpriority Senior Secured Debtor-in-Possession~~ Credit Agreement, dated ~~as of July 20, 2020,~~May 28, 2021, by and among ~~Extraction Oil & Gas, Inc.,~~ the ~~subsidiary~~Company, as borrower, certain subsidiaries of the Company, as guarantors, ~~party thereto,~~ the lenders party thereto and Wells Fargo Bank, National Association, ~~(incorporated~~as administrative agent for the Lenders and as issuing lender (incorporated by reference to Exhibit ~~10.2~~10.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on ~~July 24, 2020)~~June 1 , 2021).

~~10.3~~10.4

~~Amendment No. 2 to Superpriority Senior Secured Debtor-in-Possession Credit~~Amended and Restated Voting Agreement, dated as of ~~November 2, 2020,~~June 6, 2021 and effective as of May 9, 2021, by and among Bonanza Creek Energy, Inc., Extraction Oil & Gas, Inc.~~, the subsidiary guarantors party thereto, the lenders party thereto~~ and ~~Wells Fargo Bank, National Association~~Kimmeridge Energy Management Company, LLC (incorporated by reference to Exhibit ~~10.~~1 10.1 to the Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on ~~November 5, 2020~~June 8 ), 2021).

*31.1

Certification of Chief Executive Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934.

*31.2

Certification of Chief Financial Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934.

**32.1

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

*101

Interactive Data Files

†

Management contract or compensatory plan or agreement.

Filed herewith.

Furnished herewith.

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SIGNATURES

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

Date: ~~November~~August 9, ~~2020.~~

2021


			Extraction Oil & Gas, Inc.

			By:			/~~S/ MATTHEW R. OWENS~~s/ Thomas B. Tyree Jr.
						~~Matthew R. Owens~~Thomas B. Tyree Jr.
						~~President and~~ Chief Executive Officer ~~(principal executive officer)~~

						(Principal Executive Officer)

			By:			/~~S/ TOM~~s/ Marianella Foschi
						Marianella Foschi
						Chief Financial Officer
						(Principal Financial Officer)

			By:			/s/ Tom L. ~~BROCK~~Brock
						Tom L. Brock
						~~Vice President and~~ Chief Accounting Officer
						(~~principal financial officer)~~Principal Accounting Officer)

7061


	September 30, 2020		December 31, 2019
ASSETS
Current Assets:
Cash and cash equivalents	$	121,165	$	32,382
Accounts receivable, net
Trade	53,485		32,009
Oil, natural gas and NGL sales	54,349		105,103
Inventory, prepaid expenses and other	48,951		36,702
Commodity derivative asset	32,625		17,554
Total Current Assets	310,575		223,750
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	4,718,471		4,530,934
Unproved oil and gas properties	334,971		524,214
Wells in progress	140,290		149,733
Less: accumulated depletion, depreciation, amortization and impairment charges	(3,218,591)		(2,985,983)
Net oil and gas properties	1,975,141		2,218,898
Gathering systems and facilities, net of accumulated depreciation	0		315,777
Other property and equipment, net of accumulated depreciation	71,379		72,542
Net Property and Equipment	2,046,520		2,607,217
Non-Current Assets:
Commodity derivative asset	0		13,229
Other non-current assets	13,476		82,761
Total Non-Current Assets	13,476		95,990
Total Assets	$	2,370,571	$	2,926,957
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	38,481	$	190,864
Revenue payable	38,544		108,493
Production taxes payable	2,503		115,489
Commodity derivative liability	676		1,998
Accrued interest payable	5,369		20,625
Asset retirement obligations	0		27,058
DIP Credit Facility—Note 6	110,000		0
Credit Facility—Note 6	453,746		0
Total Current Liabilities	649,319		464,527
Non-Current Liabilities:
Credit Facility	0		470,000
Senior Notes, net of unamortized debt issuance costs	0		1,085,777
Production taxes payable	17,116		98,740
Commodity derivative liability	0		108
Other non-current liabilities	0		54,579
Asset retirement obligations	0		68,850

Total Non-Current Liabilities	17,116		1,778,054
Liabilities Subject to Compromise	2,109,446		0
Total Liabilities	2,775,881		2,242,581
Commitments and Contingencies—Note 14
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized, 185,280 issued and outstanding	189,840		175,639
Stockholders' Equity (Deficit):
Common stock, $0.01 par value; 900,000,000 share authorized; 138,370,948 and 137,657,922 issued and outstanding, respectively	1,336		1,336
Treasury stock, at cost, 38,859,078 shares	(170,138)		(170,138)
Additional paid-in capital	2,140,364		2,156,383
Accumulated deficit	(2,566,712)		(1,743,208)
Total Extraction Oil & Gas, Inc. Stockholders' Equity (Deficit)	(595,150)		244,373
Noncontrolling interest	0		264,364
Total Stockholders' Equity (Deficit)	(595,150)		508,737
Total Liabilities and Stockholders' Equity	$	2,370,571	$	2,926,957


	For the Three Months Ending		For the Nine Months Ending
	September 30, 2020		September 30, 2020
Professional fees	$	23,469	$	25,819
Professional services fees	0		2,200
Trustee fees	356		471
Damages for rejected and settled contracts	478,370		486,104
DIP Credit Facility fees	0		1,251
Write-off of debt issuance costs	272		13,541
Court approved vendor settlements	(1,394)		(1,394)
Total reorganization items, net	$	501,073	$	527,992


	As of September 30, 2020
Location on Balance Sheet	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offsets in the Balance Sheet(1)		Net Amounts of Assets and Liabilities Presented in the Balance Sheet		Gross Amounts not Offset in the Balance Sheet(2)		Net Amounts(3)
Current assets	$	40,595	$	(7,970)	$	32,625	$	0	$	32,625
Non-current assets	0		0		0		0		0
Current liabilities	(8,646)		7,970		(676)		0		(676)
Non-current liabilities	0		0		0		0		0

	As of December 31, 2019
Location on Balance Sheet	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offsets in the Balance Sheet(1)		Net Amounts of Assets and Liabilities Presented in the Balance Sheet		Gross Amounts not Offset in the Balance Sheet(2)		Net Amounts(3)
Current assets	$	48,605	$	(31,051)	$	17,554	$	0	$	30,783
Non-current assets	38,034		(24,805)		13,229		0		0
Current liabilities	(33,049)		31,051		(1,998)		0		(2,106)
Non-current liabilities	(24,913)		24,805		(108)		0		0


	At September 30, 2020				At December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Credit Facility	$	453,746	$	453,746	$	470,000	$	470,000
DIP Credit Facility	$	110,000	$	110,000	$	—	$	—
2024 Senior Notes(1)	$	400,000	$	102,500	$	394,824	$	250,000
2026 Senior Notes(2)	$	700,189	$	178,548	$	690,953	$	420,113


	Number of Shares (1)	Weighted Average Grant Date Fair Value
Non-vested PSAs at January 1, 2020	2,863,190	$	7.72
Granted	5,952,700	$	0.29
Forfeited(2)	(5,881,200)	$	(0.29)
Vested	0	$	0
Non-vested PSAs at September 30, 2020	2,934,690	$	8.18


	As of September 30, 2020			As of December 31, 2019
2020 - remaining	$	836	2020	$	19,040
2021	3,045		2021	5,247
2022	2,670		2022	2,211
2023	2,450		2023	2,246
2024	2,301		2024	2,301
Thereafter	8,273		Thereafter	8,273
Total lease payments	19,575		Total lease payments	39,318
Less imputed interest (1)	(2,347)		Less imputed interest (1)	(4,735)
Present value of lease liabilities (2)	$	17,228	Present value of lease liabilities (2)	$	34,583


	Oil (MBbl)	Gas (MMcf)	Total (MBOE)
2020 - remaining	2,466	10,260	4,176
2021	9,797	46,540	17,554
2022	8,944	49,758	17,237
2023	9,490	41,850	16,465
2024	9,516	34,160	15,209
Thereafter	29,860	40,260	36,570
Total	70,073	222,828	107,211


	For the Three Months Ended September 30, 2020
	Exploration and Production		Gathering and Facilities		Elimination of Intersegment Transactions		Consolidated Total
Revenues:
Revenues from third parties	$	158,226	$	0	$	0	$	158,226
Revenues from Extraction	0		0		0		—
Total Revenues	$	158,226	$	0	$	0	$	158,226

Operating Expenses and Other Income (Expense):
Direct operating expenses	$	(64,263)	$	0	$	0	$	(64,263)
Depletion, depreciation, amortization and accretion	(85,306)		0		0		(85,306)
Interest income	8		0		0		8
Interest expense	(7,388)		0		0		(7,388)
Earnings in unconsolidated subsidiaries	0		0		0		0
Subtotal Operating Expenses and Other Income (Expense):	$	(156,949)	$	0	$	0	$	(156,949)

Segment Assets	$	2,370,571	$	0	$	0	$	2,370,571
Capital Expenditures	(1,320)		0		0		(1,320)
Investment in Equity Method Investees	0		0		0		0
Segment EBITDAX	98,308		0		0		98,308