Unless indicated otherwise or the context otherwise requires, references in this Quarterly Report on Form 10-Q (“Quarterly Report”) to the "Company," “Extraction,” "us," "we," "our," or "ours" or like terms refer to Extraction Oil & Gas, Inc. following the completion

Table of our initial public offering on October 17, 2016, as described in our Annual Report on Form 10-K for the year ended December 31, 2016 (“Annual Report”). When used in the historical context, the "Company," "Holdings,” "us," "we," "our" and "ours" or like terms refer to Extraction Oil & Gas Holdings, LLC and its subsidiaries. Holdings is our accounting predecessor, for which we present the consolidated financial statements for the three and nine months ended September 30, 2016 in this Quarterly Report.Contents

~~The terms defined in this section are used throughout this Quarterly Report:~~

~~“Bbl”~~ ~~means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.~~

~~“Bbl/d”~~ ~~means Bbl per day.~~

~~“Btu”~~ ~~means one British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.~~

~~“BOE"~~ ~~means barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.~~

~~"BOE/d"~~ ~~means BOE per day.~~

~~"CIG"~~ ~~means Colorado Interstate Gas.~~

~~"Completion"~~ ~~means the installation of permanent equipment for the production of oil or natural gas.~~

~~"Field"~~ ~~means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.~~

~~“Fracturing” or “hydraulic fracturing”~~ means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability and porosity.

~~"Gas"~~ or ~~"Natural gas"~~ means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.

~~"Gross Acres"~~ or ~~"Gross Wells"~~ ~~means the total acres or wells, as the case may be, in which we have a working interest.~~

~~“Henry Hub”~~ ~~means Henry Hub index. Natural gas distribution point where prices are set for natural gas futures contracts traded on the NYMEX.~~

~~"Horizontal drilling"~~ or ~~“horizontal well”~~ ~~means a wellbore that is drilled laterally.~~

~~"Leases"~~ means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

~~"MBbl"~~ ~~One thousand barrels of oil, condensate or NGL.~~

~~“MBoe"~~ ~~One thousand barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.~~

~~"Mcf"~~ ~~is an abbreviation for "1,000 cubic feet," which is a unit of measurement of volume for natural gas.~~

~~"MMBtu"~~ ~~One million Btus.~~

~~"MMcf"~~ ~~is an abbreviation for "1,000,000 cubic feet," which is a unit of measurement of volume for natural gas.~~

~~"Net Acres"~~ or ~~"Net Wells"~~ ~~is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.~~

~~"NGL"~~ ~~means natural gas liquids.~~

~~"NYMEX"~~ ~~means New York Mercantile Exchange.~~

~~“Overriding royalty”~~ means an interest in the gross revenues or production over and above the landowner’s royalty carved out of the working interest and also unencumbered with any expenses of operation, development or maintenance.

~~"Proved reserves"~~ means those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

~~“Reasonable certainty”~~ means a high degree of confidence that the reserves quantities will be recovered, when a deterministic method is used. A high degree of confidence exists if the reserves quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

~~"Reservoir"~~ means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

~~"Royalty"~~ means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.

~~“SEC”~~ ~~means the Securities and Exchange Commission.~~

~~“Undeveloped leasehold acreage”~~ means the leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains estimated net proved reserves.

~~“Wattenberg Field”~~ means the Greater Wattenberg Area within the Denver-Julesburg Basin of Colorado as defined by the Colorado Oil and Gas Conservation Commission, which are the lands from and including Townships 2 South to 7 North and Ranges 61 West to 69 West, Six Principal Median.

~~"Working interest"~~ means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner's royalty, any overriding royalties, production costs, taxes and other costs.

~~"WTI"~~ ~~means the price of West Texas Intermediate oil on the NYMEX.~~

PART I. FINANCIAL INFORMATION

ITEM 1.CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)


	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

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

September 30,
2017 December 31,
2016
ASSETS
Current Assets:
Cash and cash equivalents $ 114,139
$ 588,736
Accounts receivable
Trade 52,638
23,154
Oil, natural gas and NGL sales 70,425
34,066
Inventory and prepaid expenses 13,262
7,722
Commodity derivative asset 986
—
Total Current Assets 251,450
653,678
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties 2,683,062
1,851,052
Unproved oil and gas properties 639,867
452,577
Wells in progress 130,668
98,747
Less: accumulated depletion, depreciation and amortization (610,390 ) (402,912 )
Net oil and gas properties 2,843,207
1,999,464
Other property and equipment, net of accumulated depreciation 26,866
32,721
Net Property and Equipment 2,870,073
2,032,185
Non-Current Assets:
Cash held in escrow —
42,200
Goodwill and other intangible assets, net of accumulated amortization 54,966
54,489
Other non-current assets 11,611
2,224
Total Non-Current Assets 66,577
98,913
Total Assets $ 3,188,100
$ 2,784,776
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 151,940
$ 131,134
Revenue payable 41,209
35,162
Production taxes payable 39,556
27,327
Commodity derivative liability 8,259
56,003
Accrued interest payable 14,068
19,621
Asset retirement obligations 4,998
5,300
Total Current Liabilities 260,030
274,547
Non-Current Liabilities:
Senior Notes, net of unamortized debt issuance costs 932,570
538,141
Production taxes payable 37,138
35,838
Commodity derivative liability 3,025
6,738
Other non-current liabilities 6,038
3,466
Asset retirement obligations 60,193
50,808
Deferred tax liability 98,470
106,026
Total Non-Current Liabilities 1,137,434
741,017
Total Liabilities 1,397,464
1,015,564
Commitments and Contingencies—Note 11

Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding 156,995
153,139
Stockholders' Equity:
Common stock, $0.01 par value; 900,000,000 shares authorized; 171,893,157 and 171,834,605 issued and outstanding 1,718
1,718
Additional paid-in capital 2,101,103
2,067,590
Treasury stock, at cost, 165,385 and 0 shares (2,105 ) —
Accumulated deficit (467,075 ) (453,235 )
Total Stockholders' Equity 1,633,641
1,616,073
Total Liabilities and Stockholders' Equity $ 3,188,100
$ 2,784,776

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

Table of Contents

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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.

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Revenues:
Oil sales $ 132,075
$ 51,760
$ 269,597
$ 135,896
Natural gas sales 24,672
12,792
63,095
27,730
NGL sales 24,114
8,350
57,574
19,773
Total Revenues 180,861
72,902
390,266
183,399
Operating Expenses:
Lease operating expenses 29,267
15,480
75,755
40,819
Production taxes 16,290
6,186
33,254
16,935
Exploration expenses 7,181
5,985
24,431
14,735
Depletion, depreciation, amortization and accretion 94,220
46,680
213,483
141,317
Impairment of long lived assets —
467
675
23,350
Other operating expenses —
—
451
891
Acquisition transaction expenses —
345
68
345
General and administrative expenses 28,741
20,071
77,916
35,189
Total Operating Expenses 175,699
95,214
426,033
273,581
Operating Income (Loss) 5,162
(22,312 ) (35,767 ) (90,182 )
Other Income (Expense):
Commodity derivatives gain (loss) (37,875 ) 16,225
46,423
(62,424 )
Interest expense (15,080 ) (31,216 ) (33,761 ) (57,914 )
Other income 891
36
1,709
120
Total Other Income (Expense) (52,064 ) (14,955 ) 14,371
(120,218 )
Loss Before Income Taxes (46,902 ) (37,267 ) (21,396 ) (210,400 )
Income tax benefit (17,106 ) —
(7,556 ) —
Net Loss $ (29,796 ) $ (37,267 ) $ (13,840 ) $ (210,400 )
Loss Per Common Share (Note 10)
Basic and diluted $ (0.20 ) $ (0.15 )
Weighted Average Common Shares Outstanding
Basic and diluted 171,845
171,838

Table of Contents

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

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED ~~STATEMENT~~STATEMENTS OF ~~CHANGES IN~~

~~STOCKHOLDERS’ EQUITY~~OPERATIONS

(In ~~thousands)~~thousands, except per share data)

(Unaudited)


	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
Revenues:
Oil sales	$	239,657	$	27,137	$	160,509
Natural gas sales	156,804		7,806		38,321
NGL sales	76,607		8,099		28,013
Gathering and compression	0		0		1,473
Total Revenues	473,068		43,042		228,316
Operating Expenses:
Lease operating expense	24,391		2,555		53,374
Transportation and gathering	44,742		6,256		49,092
Production taxes	32,351		3,294		18,133
Exploration and abandonment expenses	4,345		316		175,141
Depletion, depreciation, amortization and accretion	88,665		16,133		158,670
Impairment of long-lived assets	170		0		1,736
General and administrative expense	18,458		2,211		35,744
Other operating expenses	9,262		1,107		69,719
Total Operating Expenses	222,384		31,872		561,609
Operating Income (Loss)	250,684		11,170		(333,293)
Other Income (Expense):
Commodity derivative gain (loss)	(104,325)		(12,586)		193,714
Loss on deconsolidation of Elevation Midstream, LLC	0		0		(73,139)
Reorganization items, net	0		873,908		(26,919)
Interest expense(1)	(5,203)		(1,534)		(41,672)
Other income	42		12		612
Total Other Income (Expense)	(109,486)		859,800		52,596
Income (Loss) Before Income Taxes	141,198		870,970		(280,697)
Income tax expense	(28,100)		0		(2,200)
Net Income (Loss)	$	113,098	$	870,970	$	(282,897)
Net income attributable to noncontrolling interest	0		0		6,160
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	0		(418)		(12,336)
Net Income (Loss) Available to Common Shareholders, Basic and Diluted	$	113,098	$	870,552	$	(301,393)
Income (Loss) Per Common Share—Note 11
Basic	$	4.41	$	6.37	$	(2.18)
Diluted	$	4.31	$	6.37	$	(2.18)
Weighted Average Common Shares Outstanding
Basic	25,655		136,589		137,945
Diluted	26,262		136,589		137,945

_______________

(1) Absent the automatic stay described in Note 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 Predecessor period January 1, 2021 to January 20, 2021 would have included an additional $3.7 million related to 2024 and 2026 Senior Notes.

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

Common Stock Treasury Stock
Shares Amount Shares Amount Additional
Paid in
Capital Retained
Deficit Total Stockholders'
Equity
Balance at January 1, 2017 171,835
$ 1,718
—
$ —
$ 2,067,590
$ (453,235 ) $ 1,616,073
Common stock issuance costs —
—
—
—
(311 ) —
(311 )
Stock-based compensation —
—
—
—
46,707
—
46,707
Series A Preferred Stock dividends —
—
—
—
(8,164 ) —
(8,164 )
Accretion of beneficial conversion feature on Series A Preferred Stock —
—
—
—
(3,992 ) —
(3,992 )
Receipt of common stock from affiliate —
—
165
(2,105 ) —
—
(2,105 )
Restricted stock issued, including payment of tax withholdings using withheld shares 58
—
—
—
(727 ) —
(727 )
Net loss —
—
—
—
—
(13,840 ) (13,840 )
Balance at September 30, 2017 171,893
$ 1,718
165
$ (2,105 ) $ 2,101,103
$ (467,075 ) $ 1,633,641

Table of Contents

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

~~THESE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

EXTRACTION OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	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.

For the Nine Months Ended September 30,
2017 2016
Cash flows from operating activities:
Net loss $ (13,840 ) $ (210,400 )
Reconciliation of net loss to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion 213,483
141,317
Abandonment and impairment of unproved properties 5,684
3,331
Impairment of long lived assets 675
23,350
Loss on sale of property and equipment 451
—
Amortization of debt issuance costs and debt discount 3,181
18,330
Deferred rent (229 ) 600
Commodity derivatives (gain) loss (46,423 ) 62,424
Settlements on commodity derivatives (8,893 ) 43,015
Premiums paid on commodity derivatives —
(611 )
Earnings in unconsolidated affiliate (256 ) —
Distributions from unconsolidated affiliate 131
—
Deferred income tax expense (7,556 ) —
Unit and stock-based compensation 46,707
14,922
Changes in current assets and liabilities:
Accounts receivable—trade (29,099 ) 3,889
Accounts receivable—oil, natural gas and NGL sales (36,359 ) (8,506 )
Inventory and prepaid expenses (180 ) (273 )
Accounts payable and accrued liabilities 1,653
(18,242 )
Revenue payable 6,047
10,228
Production taxes payable 13,520
6,219
Accrued interest payable (5,553 ) 8,342
Asset retirement expenditures (1,408 ) (372 )
Net cash provided by operating activities 141,736
97,563
Cash flows from investing activities:
Oil and gas property additions (1,015,700 ) (223,684 )
Acquired oil and gas properties (17,225 ) (13,674 )
Sale of property and equipment 5,155
2,148
Other property and equipment additions (9,608 ) (3,336 )
Distributions from unconsolidated affiliate, return of capital 116
—
Cash held in escrow 42,200
(42,000 )
Net cash used in investing activities (995,062 ) (280,546 )
Cash flows from financing activities:
Borrowings under credit facility 250,000
60,000
Repayments under credit facility (250,000 ) (196,000 )
Proceeds from the issuance of Senior Notes 394,000
550,000
Repayment of Second Lien Notes —
(430,000 )
Proceeds from the issuance of units —
121,370
Repurchase of units —
(2,867 )
Payment of employee payroll withholding taxes (2,832 ) —
Dividends on Series A Preferred Stock (7,680 ) —
Debt issuance costs (3,273 ) (13,189 )
Equity issuance costs (1,486 ) (2,051 )
Net cash provided by financing activities 378,729
87,263
Decrease in cash and cash equivalents (474,597 ) (95,720 )
Cash and cash equivalents at beginning of period 588,736
97,106
Cash and cash equivalents at end of the period $ 114,139
$ 1,386
Supplemental cash flow information:
Property and equipment included in accounts payable and accrued liabilities $ 130,022
$ 53,371
Cash paid for interest $ 44,703
$ 30,531
Cash paid for Second Lien Notes prepayment penalty $ —
$ 4,300
Noncash settlement of promissory notes issued to officers $ —
$ 5,562
Accretion of beneficial conversion feature of Series A Preferred Stock $ 3,992
$ —
Non-cash contribution to unconsolidated affiliate $ 8,307
$ —
Increase in dividends payable $ 484
$ —

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~~THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF~~EXTRACTION OIL & GAS, INC.

~~THESE~~ CONDENSED CONSOLIDATED ~~FINANCIAL~~ STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND NONCONTROLLING INTEREST

(In thousands)

(Unaudited)


	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


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	—	—		—	—		(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 (Predecessor)	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 (Predecessor)	177,203	$	1,336	38,859	$	(170,138)	$	2,140,327	$	(2,026,105)	$	(54,580)	$	0	$	(54,580)

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

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EXTRACTION OIL & GAS, INC.

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Business and Organization

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

~~The~~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”) of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the ~~three and nine months ended September 30, 2016 are based on~~District of Delaware (the “Bankruptcy Court”). The Debtors’ Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered under the ~~financial statements of the Company’s accounting predecessor,~~caption In re Extraction Oil & ~~Gas Holdings, LLC, prior~~Gas., et al. Case No. 20-11548 (CSS).

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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 obtain votes on the Plan. The Plan was confirmed by order of the Bankruptcy Court on December 23, 2020 (the ~~"IPO"~~“Confirmation Order”). On January 20, 2021 (the “Emergence Date”), ~~(i) on October 11, 2016, a former subsidiary of Extraction Oil & Gas Holdings, LLC, Extraction Oil & Gas, LLC, converted into~~the Plan became effective in accordance with its terms and the Company ~~and (ii) on October 17, 2016, Holdings merged with and into~~emerged from the ~~Company with the Company as the surviving entity. For further information on the Corporate Reorganization please refer to the Company’s Annual Report.~~Chapter 11 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 ~~accounting principles~~ 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 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 ~~sheet~~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.~~Report on Form 10-K for the year ended December 31, 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. These unaudited~~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.

The Predecessor Company applied Accounting Standards Codification (“ASC”) Topic 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, ~~should be read in conjunction~~for periods subsequent to the Chapter 11 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 gain on settlement of debt and fresh-start valuations, are recorded as reorganization items, net. In addition, for periods after the Petition Date and through the Emergence Date, Predecessor Company pre-petition obligations that may have been impacted by the Chapter 11 process have been classified on the condensed consolidated balance sheets as “Liabilities Subject to Compromise.” These liabilities are reported at the amounts the Predecessor Company 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, net.

GAAP requires certain additional reporting for financial statements prepared between the Petition Date and ~~notes included~~the 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 to Compromise”; and

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

Accounting policies for the balance sheet accounts listed below are disclosed in the Company’s Annual Report. As of the Effective Date, the amounts for these accounts have been recorded at fair value. After the effective date, the Company will continue to follow the accounting policies within its 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.

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 August 3, 2021, the Debtors’ have received approximately 2,600 proofs of claim, primarily representing general unsecured claims, for an amount of approximately $5.8 billion. The Bankruptcy Court does not allow for claims 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 disallowed. As of August 3, 2021, there are a total of approximately $75.1 million in remaining asserted claims in the 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 are currently being investigated and resolved, including through filing 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 light of the substantial number of claims filed, the claims resolution process may take considerable time to complete and is continuing even after the Debtors emerged from bankruptcy.

Divestitures

In April 2021, the Company completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately $15.2 million, subject to customary purchase price adjustments. No gain or loss was 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 post-closing adjustments. The Company continues to explore divestitures as part of our ongoing initiative to divest non-strategic assets.

Segments

The Company has a single reportable segment.

Recent Accounting Pronouncements

In May ~~2017,~~2021, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. ~~2017-09, which provides clarification~~2021-04, Earnings Per Share (Topic 260), Debt—Modifications and ~~reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation -~~ Extinguishments (Subtopic 470-50), Compensation—Stock Compensation ~~to a change to the terms~~(Topic 718), and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40). This ASU clarifies accounting for modifications or ~~conditions~~exchanges of ~~a share-based payment award. For public entities, the new guidance is~~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 ~~fiscal years~~the Company beginning ~~after December 15, 2017, including interim reporting periods within that reporting period.~~January 1, 2022. Early adoption is permitted ~~for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company is currently evaluating the impact~~and

Table of ~~adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements.~~Contents

In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures.

~~In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions~~amendments should be ~~accounted for as acquisitions~~applied prospectively to modifications or ~~disposals of assets or businesses. For public entities,~~exchanges occurring on the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the ~~amendments, only when the transaction has not been reported in the financial statements that have been issued.~~amendments. The Company is ~~currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures.~~

In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently evaluating the ~~impact~~effect of adopting this ~~ASU, however it is not expected to have a significant effect on its consolidated financial statements.~~guidance.

In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. In addition, in November 2016, the FASB issued ASU No. 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company is currently evaluating this ASU to determine the potential impact to its financial statements and related disclosures.

In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASB Topic 815, Derivatives and Hedging, as amended by this ASU. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. The Company adopted this ASU in the first quarter of 2017 and the adoption of this ASU did not have a material impact on the its consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. In September 2017, the FASB issued ASU No. 2017-13, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on its financial statements and related disclosures and developing a strategy for implementation.

In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of reporting periods beginning after December 15, 2016. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, and ASU No. 2017-13, which provided additional implementation guidance. The Company is in the final stages of its review of contracts in each of its revenue streams and has developed accounting policies to address the provisions of this ASU. While the Company does not expect operating income (loss) to be materially impacted, the Company does expect total revenues and total expenses to change as a result of certain percentage of proceeds contracts. Further, the Company has begun evaluating the design of its pre-adoption and adoption controls and expects new or modification of certain controls to address risks associated with recognizing revenue under the new standard as we continue the implementation process. The Company will continue to evaluate the impact of this and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements and related disclosures and has not finalized any estimates of the potential impacts. The Company will

~~adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings.~~

Other than as disclosed ~~above or~~ in the Company’s Annual Report, there are no other accounting standards applicable to the Company ~~that would have a material effect on~~as of June 30, 2021 and through the ~~Company’s financial statements and related disclosures~~date of this filing that have been issued but not yet adopted by the Company ~~through~~that would have a material effect on the ~~date of this filing.~~Company’s unaudited condensed consolidated financial statements and related disclosures.

Note 3—~~Acquisitions~~Fresh Start Reporting

~~July 2017 Acquisition~~Fresh Start Reporting

On July 7, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 12,500 net acres of leasehold, and primarily non-producing properties and producing properties located primarily in Adams County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the "July 2017 Acquisition"). Upon closing the seller received total consideration of $84.0 million in cash, subject to customary purchase price adjustments. The effective date for the July 2017 Acquisition is July 1, 2017. This transaction has been accounted for as an asset acquisition. The acquisition provides new development opportunities in the DJ Basin.

~~June 2017 Acquisition~~

On June 8, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 160 net acres of leasehold and related producing properties located in Weld County, Colorado (the “June 2017 Acquisition”). The Company paid approximately $13.4 million in cash consideration inIn connection with the ~~closing~~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 apply fresh start reporting due to the fact that (i) the holders of existing voting shares of the ~~June 2017 Acquisition. The effective date~~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 ~~acquisition~~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 ~~January 1, 2017, with purchase price adjustments calculated~~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 ~~closing date~~Emergence Date. On the Emergence Date, pursuant to the terms of ~~June 8, 2017.~~ 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 ~~acquisition increased~~Company’s 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 wells included in the Company's ~~interest~~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 ~~existing operated wells.~~ the section titled “Fresh Start Adjustments.”

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The ~~acquired producing properties contributed $1.5~~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 ~~$2.2~~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	$	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 revenue and $1.1 million and $1.7 million of earnings, respectively, for three and nine months ended September 30, 2017. The acquired producing properties contributed de minimis revenue and earnings for the three and nine months ended September 30, 2016. No significant transactionfinancing costs related to the ~~acquisition~~RBL Credit Facility, which were ~~incurred~~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 ~~three~~Prior Credit Facility and ~~nine months ended September 30, 2017~~DIP Credit Facility.

(h) Represents $13.9 million and ~~2016.~~$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 ~~June 2017 Acquisition was accounted~~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	(72,860)
Other non-current liabilities	(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	$	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 ~~using~~claims against or interests in the ~~acquisition method under ASC 805,~~ ~~Business Combinations, which requires~~Debtors pursuant to the ~~acquired assets~~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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Fresh Start Adjustments

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

(s) Reflects the adjustments to fair value of ~~June 8, 2017.~~ 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.

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 ~~August 2017,~~estimating the ~~Company completed~~fair value of the ~~transaction’s post-closing settlement.~~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

Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases were recorded in reorganization items, net in the Company’s consolidated statements of operations. The following table summarizes the ~~purchase price and~~components of reorganization items, net for the ~~final allocation of the fair values of assets acquired and liabilities assumed~~periods presented (in thousands):

Purchase Price June 8, 2017
Consideration given
Cash $ 13,395
Total consideration given $ 13,395
Allocation of Purchase Price
Proved oil and gas properties $ 13,495
Total fair value of oil and gas properties acquired $ 13,495
Asset retirement obligations $ (100 )
Fair value of net assets acquired $ 13,395

~~November 2016 Acquisition~~

On November 22, 2016, the Company acquired an unaffiliated oil and gas company’s interest in approximately 9,200 net acres of unproved leaseholds located in the DJ Basin for approximately $120.0 million, including customary closing adjustments (the “November 2016 Acquisition”). This transaction has been accounted for as an asset acquisition. The Company also made a $41.1 million deposit in November 2016 in conjunction with November 2016 Acquisition, which has been reflected in the December 31, 2016 consolidated balance sheet within the cash held in escrow line item. The deposit was made for two additional closings of leaseholds located in the DJ Basin. The first closing occurred in January 2017 and added approximately 5,300 net acres for approximately $26.8 million. The second closing occurred in July 2017 and added approximately 640 net acres for approximately $10.9 million.

~~October 2016 Acquisition~~

On October 3, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 6,400 net acres of leasehold, and related producing and non‑producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “October 2016 Acquisition” or the “Bayswater Acquisition”). The seller received aggregate consideration of approximately $405.3 million in cash. The effective date for the acquisition was July 1, 2016, with purchase price adjustments calculated as of the closing date on October 3, 2016. The acquisition provides new development opportunities in the DJ Basin as well as increases the Company’s existing working interest, as the majority of the locations are located on acreage in which the Company already owns a majority working interest and operates. The Company incurred $2.6 million of transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item, $0.3 million in transaction costs related to the acquisition were incurred for the three and nine months ended September 30, 2016. No transaction costs related to the acquisition were incurred for the three and nine months ended September 30, 2017.

~~The acquisition is accounted for using the acquisition method under ASC 805,~~ ~~Business Combinations~~, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of October 3, 2016. In February 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price October 3, 2016
Consideration given
Cash $ 405,335
Total consideration given $ 405,335
Allocation of Purchase Price
Proved oil and gas properties $ 252,522
Unproved oil and gas properties 109,800
Total fair value of oil and gas properties acquired $ 362,322
Goodwill ⁽¹⁾
$ 54,220
Working capital (7,185 )
Asset retirement obligations (4,022 )
Fair value of net assets acquired $ 405,335
Working capital acquired was estimated as follows:
Accounts receivable $ 955
Revenue payable (3,012 )
Production taxes payable (4,244 )
Accrued liabilities (884 )
Total working capital $ (7,185 )


~~(1)~~	~~Goodwill is primarily attributable~~	Predecessor
		For the Period from January 1 through January 20,
		2021
Gain on settlement of liabilities subject to ~~a decrease in commodity prices from the time the acquisition was negotiated~~compromise		$	1,430,108
Adjustment to ~~commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result~~Backstop Commitment Agreement premium		5,365
Acceleration of ~~the Bayswater Acquisition is not deductible for income tax purposes.~~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

~~August 2016 Acquisition~~

On August 23, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 1,400 net acres of leasehold located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way and other assets (the “August 2016 Acquisition”). The seller received aggregate consideration of approximately $17.5 million in cash. The effective date for the acquisition was August 31, 2016, with purchase price adjustments calculated as of the closing date of August 23, 2016. The acquisition provided new development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area. The Company incurred $0.1 million of transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item in the third quarter of 2016.

~~The acquisition was accounted for using the acquisition method under ASC 805,~~ ~~Business Combinations~~, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of August 23, 2016. In March 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):

Purchase Price August 23, 2016
Consideration given
Cash $ 17,504
Total consideration given $ 17,504
Allocation of Purchase Price
Proved oil and gas properties $ 12,362
Unproved oil and gas properties 8,566
Total fair value of oil and gas properties acquired $ 20,928
Working capital $ (9 )
Asset retirement obligations (3,415 )
Fair value of net assets acquired $ 17,504
Working capital acquired was estimated as follows:
Production taxes payable $ (9 )
Total working capital $ (9 )

~~Pro Forma Financial Information (Unaudited)~~

The following pro forma results (in thousands, except per share data) do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. Asset acquisitions are not included in pro forma financial information, as it is not required. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. Net loss per common share is not applicable for the period prior to the Corporate Reorganization.

For the Three Months Ended September 30, For the Nine Months Ended September 30,
2017 2016 2017 2016
Revenues $ 180,861
$ 92,476
$ 392,430
$ 230,665
Operating expenses $ 175,699
$ 106,765
$ 427,912
$ 304,677
Net loss $ (29,796 ) $ (30,268 ) $ (13,663 ) $ (197,254 )
Loss per common share, basic and diluted $ (0.20 ) $ (0.15 )

Note 4—~~Long‑Term~~Long-Term Debt

~~As of the dates indicated, the~~The Company’s ~~long‑term~~long-term debt consisted of the following (in thousands):


	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

September 30,
2017 December 31,
2016
Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility) $ —
$ —
2021 Senior Notes due July 15, 2021 550,000
550,000
2024 Senior Notes due May 15, 2024 400,000
—
Unamortized debt issuance costs on Senior Notes (17,430 ) (11,859 )
Total long-term debt 932,570
538,141
Less: current portion of long-term debt —
—
Total long-term debt, net of current portion $ 932,570
$ 538,141
_______________

~~Credit Facility~~

~~In August 2017,~~(1) As a result of the Chapter 11 Cases and the adoption of ASC 852, the Company ~~entered into an amendment~~wrote off all unamortized debt issuance cost balances to reorganization items, net in the consolidated statements of operations during the year ended December 31, 2020.

(2) As of December 31, 2020, amounts reclassified to “Liabilities Subject to Compromise” included the principal balances of the Predecessor Company’s 2024 and ~~restatement of its existing credit facility (prior to amendment and restatement, the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is~~2026 Senior Notes.

(3) Total debt not subject to a borrowing base. The credit facility matures on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted into common equity or redeemed prior to April 15, 2021, 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 (d) the earlier termination in whole of the commitments.

~~As of September 30, 2017, the credit facility was subject to a borrowing base of $375.0 million. As of September 30, 2017 and, with respect to~~compromise includes all borrowings outstanding under the Prior Credit Facility ~~December 31, 2016,~~and DIP Credit Facility.

RBL Credit Facility

On the ~~Company had no outstanding borrowings. As of September 30, 2017 and, with respect~~Emergence Date, pursuant to the ~~Prior~~terms of the Plan, the Successor Company entered into a $1.0 billion reserve-based credit agreement (“RBL Credit ~~Facility, December 31, 2016,~~Agreement”) with Wells Fargo Bank, National Association (“RBL Credit Facility”) with 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 ~~had standby letters of credit of $25.7 million~~ and ~~$0.6 million, respectively. At September 30, 2017,~~its administrative agent between scheduled redeterminations during any 12-month period. On May 6, 2021, the ~~undrawn balance under the credit facility~~Successor Company’s borrowing base was ~~$375.0~~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 ~~had no borrowings outstanding~~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 of $0.5 million of undrawn letters of credit, ~~facility.~~

~~Redetermination~~were $429.5 million as of the ~~borrowing base was scheduled on August 1, 2017 and semiannually on May 1 and November 1, thereafter.~~ date of this filing.

The ~~Company and the administrative agent under the credit facility may each elect~~RBL Credit Facility provides for a ~~redetermination~~$50.0 million sub-limit of the ~~borrowing base between any two scheduled redeterminations.~~aggregate commitments that is available for the issuance of letters of credit. The ~~scheduled August 1, 2017 redetermination closed in October 2017, resulting in~~RBL Credit Facility bears interest either at a ~~borrowing base increase~~rate equal to ~~$525.0 million.~~

~~Interest on the credit facility is payable at one of the following two variable rates as selected by the Company:~~(i) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (ii) a base rate ~~based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by~~plus an applicable margin ~~based~~that varies from 2.00% to 3.00% per annum. The RBL Credit Facility matures on ~~the utilization percentage of the facility as outlined in the pricing grid below. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage.~~July 20, 2024. The grid below shows the ~~Base Rate Margin~~base rate margin and Eurodollar ~~Margin~~margin depending on the applicable ~~Borrowing Base Utilization Percentage (as defined in the credit facility)~~borrowing base utilization percentage as of the date of this filing:

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RBL Credit Facility Borrowing Base Utilization Grid


										Base Rate		Eurodollar		Commitment
Borrowing Base Utilization Percentage	Utilization	Eurodollar Margin	Base Rate Margin	Commitment Fee Rate	Borrowing Base Utilization Percentage	Utilization				Margin		Margin		Fee Rate
Level 1	< 25%	2.00%	1.00%	0.375%	Level 1	<25%				2.00	%	3.00	%	0.50	%
Level 2	≥ 25% < 50%	2.25%	1.25%	0.375%	Level 2	≥	25%	<	50%	2.25	%	3.25	%	0.50	%
Level 3	≥ 50% < 75%	2.50%	1.50%	0.500%	Level 3	≥	50%	<	75%	2.50	%	3.50	%	0.50	%
Level 4	≥ 75% < 90%	2.75%	1.75%	0.500%	Level 4	≥	75%	<	90%	2.75	%	3.75	%	0.50	%
Level 5	≥ 90%	3.00%	2.00%	0.500%	Level 5	≥90%				3.00	%	4.00	%	0.50	%

The credit facility 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; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; (iv) limitations onRBL Credit Facility requires the sale of property, mergers, consolidations and other similar transactions covenants; and (v) holding cash balances in excess of certain thresholds while carrying a balance on the credit facility. Additionally, the credit facility limits the Company entering into hedges in excess of 85% of its anticipated production volumes.

~~The credit facility also contains financial covenants requiring the~~Successor Company to ~~comply with~~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 ~~its consolidated~~greater than or equal to 1.00 to 1.00. Per the RBL Credit Agreement, for the purpose of calculating the current ~~assets (includes availability~~ratio for fiscal quarters ending March 31, 2021 and June 30, 2021, all ad valorem, severance or tax liabilities can be excluded from current liabilities in the calculation of the current ratio.

The Successor Company is required to pay a commitment fee of 0.50% per annum on the actual daily unused portion of the current aggregate commitments under the ~~revolving~~RBL Credit Facility. The Successor Company is also required to pay customary letter of credit ~~facility~~ and ~~unrestricted cash~~fronting fees.

The RBL Credit Agreement also contains customary affirmative and ~~excludes derivative assets)~~negative covenants, including, among other things, as to ~~its consolidated current liabilities (excludes obligations~~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 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 ~~revolving credit facility, senior notes~~RBL Credit Agreement and ~~certain derivative liabilities), of not less than 1.0~~any outstanding unfunded commitments may be terminated.

Prior Credit Facility, DIP Credit Facility, 2024 Senior Notes and 2026 Senior Notes

Information pertaining to ~~1.0 and to maintain, on~~these debt facilities can be found in the last day of each quarter, a ratio of consolidated debt less cash balances to its consolidated EBITDAX (EBITDAX is defined as net income adjusted for certain cash and non-cash items including DD&A, exploration expense, gains/losses on derivative instruments, amortization of certain debt issuance costs, non-cash compensation expense, interest expense and prepayment premiums on extinguishment of debt) for the four fiscal quarter period most recently ended, of not greater than 4.0:1.0. For the quarter ending September 30, 2017, consolidated EBITDAX will be based on the last six months’ consolidated EBITDAX multiplied by 2; and for the quarter ending December 31, 2017, consolidated EBITDAX will be based on the last nine months’ consolidated EBITDAX multiplied by 4/3. For the quarters ending on or after March 31, 2018, consolidated EBITDAX will be based on the last twelve months’ consolidated EBITDAX. The Company was in compliance with all financial covenants under the credit facility as of September 30, 2017 and through the filing of this report.

Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and its subsidiaries, including oil and gas properties, personal property and the equity interests of the subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility.Company’s Annual Report. The Company’s obligations under ~~these hedging contracts are secured by the collateral securing the credit facility.~~

~~2021 Senior Notes~~

In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes” and the offering, the “2021 Senior Notes Offering”). The 2021 Senior Notes bear an annual interest rate of 7.875%. The interest on the 2021 Senior Notes is payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.

~~The 2021 Senior Notes are the Company's 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 2021 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the Company's current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of the 2021 Senior Notes) that guarantees its indebtedness under a credit facility (the “Guarantors”). The notes are effectively subordinated to all of the Company's secured indebtedness (including all

borrowings and other obligations under its revolving 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 future subsidiaries that do not guarantee the notes.

The 2021 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the 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 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 2021 Senior Notes (the “2021 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2021 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2021 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2021 Senior Notes may declare all outstanding 2021 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2021 Senior Notes Indenture as of September 30, 2017, and through the filing of this report.

~~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”). ThePrior Credit Facility, DIP Credit Facility, 2024 Senior Notes ~~bear an annual interest rate of 7.375%. The interest on the 2024~~and 2026 Senior Notes ~~is payable on May 15 and November 15 of each year commencing on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting discounts and fees.~~were settled at the Effective Date.

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 each of its current subsidiaries and by certain future restricted subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its revolving 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 notes.

The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the 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 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 (the “2024 Senior Notes Indenture”) also contains customary events of 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. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may declare all outstanding 2024 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2024 Senior Notes Indenture through the filing of this report.

Debt Issuance Costs

Successor Company debt issuance costs include origination, legal and other fees incurred in connection with the Successor Company’s RBL Credit Facility. As of ~~September~~June 30, ~~2017,~~2021, the Successor Company had debt issuance costs, net of accumulated amortization, of ~~$3.1~~$5.5 million, ~~related to its credit facility~~ which has been reflected on the ~~Company’s~~Successor Company's condensed consolidated balance ~~sheet~~sheets within the line item ~~other non‑current~~“Other non-current assets. ~~As of September 30, 2017,~~” For the period from January 1, 2021 to January 20, 2021, the Predecessor Company ~~had~~recorded amortization expense related to debt issuance costs ~~net~~ of ~~accumulated~~$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 ~~of $17.4 million~~expense related to ~~its 2021 and 2024 Senior Notes (collectively, the "Senior Notes") which has been reflected on the Company's condensed consolidated balance sheet within the line item Senior Notes, net of unamortized~~ debt issuance ~~costs. Debt~~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 ~~engineering~~ and other fees incurred in connection with the Predecessor Company’s ~~credit facility, 2021~~Prior Credit Facility, DIP Credit Facility, 2024 Senior Notes and ~~2024~~2026 Senior Notes. ~~For~~As a result of the ~~three and nine months ended September 30, 2017,~~bankruptcy, the Company ~~recorded~~

~~amortization expense related to~~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 ~~$1.5 million and $3.2 million, respectively as compared to $11.6 million and $13.5 million~~operations for the three and ~~nine~~six months ~~ended September~~ending June 30, ~~2016, respectively. Debt issuance costs for the three and nine months ended September 30, 2016 include $10.8 million~~2020.

Table of acceleration of amortization expense upon the repayment of the Company's Second Lien Notes. For additional information regarding amortization expense on Second Lien Notes, see the Company's Annual Report.Contents

~~Debt Discount Costs on Second Lien Notes~~

For the three and nine months ended September 30, 2016, the Company recorded amortization expense related to the debt discount on its Second Lien Notes of $4.3 million and $4.8 million, respectively. The Company recorded no amortization expense related to the debt discount on its Second Lien Notes for the three and nine months ended September 30, 2017. For additional information regarding debt discount costs on Second Lien Notes, see the Company’s Annual Report.

Interest Incurred on ~~Long‑Term~~Long-Term Debt

For the ~~three and nine months ended September 30, 2017,~~period from January 1, 2021 to January 20, 2021, the Predecessor Company incurred interest expense on ~~long‑term~~long-term debt of ~~$16.5~~$1.5 million and ~~$39.2 million, respectively, as compared to $12.2~~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 ~~$38.9~~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 and capitalized interest expense on long-term debt of $0.1 million. For the three and six months ended June 30, 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, ~~2016,~~2020 would have been $23.2 million and $44.5 million, respectively. For the three and six months ended ~~September~~June 30, ~~2017,~~2020, the Predecessor Company capitalized interest expense on ~~long term~~long-term debt of ~~$2.9~~$1.9 million and ~~$8.6~~$4.0 million, respectively, as compared to $1.2 million and $3.6 million for the three and nine months ended September 30, 2016, respectively, which has been reflected in the Company’s condensed consolidated financial statements. Also included in interest expense for the three and nine months ended September 30, 2016 is a prepayment penalty of $4.3 million related to the Company's repayment of its Second Lien Notes in July 2016.respectively.

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

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 six counterparties. The Company has netting arrangements with the counterparties 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 are no 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.

The Company’s open commodity derivative contracts by quarter as of ~~September~~June 30, ~~2017~~2021 are summarized below:


										9/30/2021		12/31/2021		3/31/2022		6/30/2022		9/30/2022		12/31/2022		3/31/2023
	2017			2018			2019
NYMEX WTI⁽¹⁾ Crude Swaps:
NYMEX WTI Crude Swaps:									NYMEX WTI Crude Swaps:
Notional volume (Bbl)	1,850,000			5,100,000			—		Notional volume (Bbl)	1,153,000		1,041,000		828,000		—		—		—		—
Weighted average fixed price ($/Bbl)	$	50.64		$	51.61				Weighted average fixed price ($/Bbl)	$	49.64	$	50.01	$	50.05	$	—	$	—	$	—	$	—
NYMEX WTI⁽¹⁾ Crude Sold Calls:
NYMEX WTI Crude Purchased Puts:									NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)									Notional volume (Bbl)	—		—		—		345,839		320,247		297,903		94,820
Weighted average purchased put price ($/Bbl)									Weighted average purchased put price ($/Bbl)	$	—	$	—	$	—	$	40.00	$	40.00	$	40.00	$	40.00
NYMEX WTI Crude Sold Calls:									NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)	1,200,000			6,190,000			3,000,000		Notional volume (Bbl)	—		—		—		345,839		320,247		297,903		94,820
Weighted average sold call price ($/Bbl)	$	53.04		$	55.75		$	55.10	Weighted average sold call price ($/Bbl)	$	—	$	—	$	—	$	72.70	$	72.70	$	72.70	$	72.70
NYMEX WTI⁽¹⁾ Crude Sold Puts:
Notional volume (Bbl)	3,225,000			11,338,800			3,000,000
Weighted average sold put price ($/Bbl)	$	37.19		$	38.93		$	39.70
NYMEX WTI⁽¹⁾ Crude Purchased Puts:
Notional volume (Bbl)	1,800,000			6,838,800			3,000,000
Weighted average purchased put price ($/Bbl)	$	42.13		$	47.35		$	49.37
NYMEX HH⁽²⁾ Natural Gas Swaps:
NYMEX HH Natural Gas Swaps:									NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)	7,420,000			37,200,000			—		Notional volume (MMBtu)	8,482,141		7,904,240		6,468,277		—		—		—		—
Weighted average fixed price ($/MMBtu)	$	3.06		$	3.10				Weighted average fixed price ($/MMBtu)	$	2.93	$	2.93	$	3.00	$	—	$	—	$	—	$	—
NYMEX HH⁽²⁾ Natural Gas Purchased Puts:
NYMEX HH Natural Gas Purchased Puts:									NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)	—			2,400,000			—		Notional volume (MMBtu)	—		—		—		2,764,135		2,614,602		2,477,469		797,160
Weighted average purchased put price ($/MMBtu)				$	3.00				Weighted average purchased put price ($/MMBtu)	$	—	$	—	$	—	$	2.00	$	2.00	$	2.00	$	2.00
NYMEX HH⁽²⁾ Natural Gas Sold Calls:
NYMEX HH Natural Gas Sold Calls:									NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)	—			2,400,000			—		Notional volume (MMBtu)	—		—		—		2,764,135		2,614,602		2,477,469		797,160
Weighted average sold call price ($/MMBtu)				$	3.15				Weighted average sold call price ($/MMBtu)	$	—	$	—	$	—	$	3.25	$	3.25	$	3.25	$	3.25
CIG⁽³⁾ Basis Gas Swaps:
Notional volume (MMBtu)	5,215,000			6,300,000			—
Weighted average fixed basis price ($/MMBtu)	$	(0.31	)	$	(0.31	)


~~(1)~~	~~NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange.~~


~~(2)~~	~~NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange.~~


~~(3)~~	~~CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price.~~

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):

Table of Contents


	As of September 30, 2017
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⁾			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	$	25,250		$	(24,264	)	$	986		$	(146	)	$	840		Current assets	$	375	$	(375)	$	0	$	0	$	0
Non-current assets	$	25,141		$	(25,141	)	$	—		$	—		$	—		Non-current assets	1,207		(1,207)		0		0		0
Current liabilities	$	(32,523	)	$	24,264		$	(8,259	)	$	146		$	(11,138	)	Current liabilities	(79,290)		375		(78,915)		0		(82,217)
Non-current liabilities	$	(28,166	)	$	25,141		$	(3,025	)	$	—		$	—		Non-current liabilities	(4,509)		1,207		(3,302)		0		0

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

As of December 31, 2016
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 $ 12,620
$ (12,620 ) $ —
$ —
$ —
Non-current assets $ 14,993
$ (14,993 ) $ —
$ —
$ —
Current liabilities $ (68,623 ) $ 12,620
$ (56,003 ) $ —
$ (62,741 )
Non-current liabilities $ (21,731 ) $ 14,993
$ (6,738 ) $ —
$ —
(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.


~~(1)~~	Agreements are in place with all of the Company’s financial trading counterparties 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 item 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, 2017 and 2016~~periods presented (in thousands). ~~Commodity derivatives gain (loss) is 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,
2017 2016 2017 2016
Commodity derivatives gain (loss) $ (37,875 ) $ 16,225
$ 46,423
$ (62,424 )


	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 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~~non-current portions as of December 31, 2020 (Predecessor) were $14.3 million and $80.5 million, respectively, and have been included in “Liabilities Subject to Compromise” in the ~~estimated fair value~~condensed consolidated balance sheets as of its asset retirement obligations by calculating the present value of estimated cash flows related 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.

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):

Table of Contents

For the Nine Months Ended September 30, 2017 For the Year Ended December 31, 2016
Balance beginning of period $ 56,108
$ 44,367
Liabilities incurred or acquired 6,644
8,945
Liabilities settled (1,408 ) (1,155 )
Revisions in estimated cash flows —
(1,695 )
Accretion expense 3,847
5,646
Balance end of period $ 65,191
$ 56,108


Asset retirement obligations at December 31, 2020 (Predecessor)	$	94,769
Liabilities settled	(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	651
Accretion expense	3,267
Asset retirement obligations at June 30, 2021 (Successor)	$	88,714

_______________

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

Note 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:

~~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, 2017 and December 31, 2016~~ by level within the fair value ~~hierarchy (in thousands):~~hierarchy:


	Successor								Predecessor
	Fair Value Measurement at June 30, 2021								Fair Value Measurement at December 31, 2020
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Commodity derivative assets	$	0	$	0	$	0	$	0	$	0	$	6,971	$	0	$	6,971
Commodity derivative liabilities	0		82,217		0		82,217		0		2,147		0		2,147

Fair Value Measurements at
September 30, 2017 Using
Level 1 Level 2 Level 3 Total
Financial Assets:
Commodity derivative assets $ —
$ 986
$ —
$ 986
Financial Liabilities:
Commodity derivative liabilities $ —
$ 11,284
$ —
$ 11,284

Fair Value Measurements at
December 31, 2016 Using
Level 1 Level 2 Level 3 Total
Financial Assets:
Commodity derivative assets $ —
$ —
$ —
$ —
Financial Liabilities:
Commodity derivative liabilities $ —
$ 62,741
$ —
$ 62,741

The following ~~methods and assumptions were used to estimate~~table (in thousands) presents the fair value of the ~~assets and liabilities in the table 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. The~~ carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair value of the 2021 Senior Notes and 2024 Senior Notes were derived from available market data. As such, the Company has classified the 2021 Senior Notes and 2024 Senior Notes as Level 2. Please refer to ~~Note 4 — 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~~Company's financial position, results of operations or cash flows.


	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

At September 30, 2017 At December 31, 2016
Carrying Amount Fair Value Carrying Amount Fair Value
2021 Senior Notes⁽¹⁾
$ 539,804
$ 580,250
$ 538,141
$ 588,500
2024 Senior Notes⁽²⁾
$ 392,766
$ 419,000
$ —
$ —


~~(1)~~	~~The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $10.2 million and $11.9 million as of September 30, 2017 and December 31, 2016, respectively.~~


~~(2)~~	~~The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $7.2 million as of September 30, 2017.~~

~~Non‑Recurring~~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 and goodwill. 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 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~~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). No~~periods from January 1, 2021 to January 20, 2021 and January 21, 2021 to June 30, 2021, the Company recognized no impairment expense ~~was recognized for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016~~ on their proved oil and gas properties. For the ~~nine~~three and six months ended ~~September~~June 30, ~~2016,~~2020, the Predecessor Company recognized ~~$22.4~~$0.8 million and $1.6 million, respectively, in impairment expense on its proved oil and gas properties related to impairment of assets in its northern ~~field. The future undiscounted cash flows~~field as the fair value did not exceed the

~~Company’s~~ Predecessor Company's carrying amount associated with its proved oil and gas properties in its northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties was impaired at September 30, 2016.field.

~~The Company applies the provisions of ASC 350,~~ ~~Intangibles-Goodwill and Other. Goodwill represents the excess~~See Note 3—Fresh Start Reporting for discussion of the ~~purchase price over the estimated value~~revaluation of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed an assessment as of September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount.properties upon emergence from bankruptcy.

~~The Company’s other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to~~ ~~Note 3 — Acquisitions~~. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices, development costs and operating costs, based on market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is on a non-recurring basis and is not measured in periods after initial recognition.

Note 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 ~~annual effective rate~~AETR applied to the year-to-date ordinary income or loss, plus the tax effect of any significant ~~discrete~~ or infrequently occurring items recorded during the interim period. The computation of the ~~annual~~ estimated ~~effective tax rate~~AETR at each interim period requires certain estimates and significant ~~judgment~~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, ~~2017 was 35.3%. During~~2021: 16.29%

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

•For the three months ended ~~September~~June 30, ~~2017,~~2020: 0

•For the ~~Company recognized income tax benefit of $7.6 million.~~ six months ended June 30, 2020: (0.80)%

The effective rate ~~for~~differs from the ~~nine months ended September 30, 2017 differs from~~amount that would be provided by applying the statutory U.S. federal income tax rate of ~~35% primarily~~21% to pre-tax income due to (i) the effect of a full valuation allowance in effect at June 30, 2021, and (ii) the effects of state taxes, permanent taxable differences, and income ~~taxes and estimated permanent differences. Included~~attributable to non-controlling interest for the six months ended June 30, 2020. Net tax expense for the 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 ~~discrete item during~~result of net operating loss (“NOL”) carryovers limited under Section 382 of the ~~three months ended September 30, 2017~~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 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 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 attributes does not occur until January 1, 2022.

The Company has evaluated the impact of the reorganization, including the change in control, resulting from its emergence from bankruptcy. From an income tax 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 by the Predecessor Company in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers will be limited under Section 382 of the IRC due to the change in control as referenced in Note 3—Fresh Start Reporting. As the tax ~~deficiency related to equity compensation~~basis of the Company's assets, primarily our oil and gas properties, is in excess of ~~compensation recognized for financial reporting. The~~the carrying value, as adjusted in the fresh-start accounting process, the Successor Company ~~anticipates~~is in a net deferred tax asset position. Per authoritative guidance, historical results along with expected market conditions known on the ~~potential for increased periodic volatility in~~date of measurement, it is more likely than not that the Company will not realize future ~~effective~~income tax ~~rates~~benefits from the ~~impact of stock-based compensation~~additional tax deductions as they are treated as discrete tax items. The Company’s accounting predecessor was a limited liability company that was not subject to U.S. federal income tax during the first nine months of 2016.

~~The Company adopted ASU No. 2016-09 on January 1, 2017. There was no tax effect upon adoption as~~basis and its remaining NOL carryovers. This is periodically reassessed and could change. Accordingly, the Company ~~did not have an accumulated windfall pool as~~has provided for a full valuation allowance of ~~December 31, 2016.~~the underlying deferred tax assets.

Note 9—~~Unit and Stock‑Based~~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 Predecessor Company’s stockholders approved the amendment and restatement of the 2016 LTIP. The ~~Company reserved 20.2~~amended and restated 2016 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.

~~Stock Options~~

~~Expense on~~ Extraction granted awards under the 2016 LTIP to certain directors, officers and employees, including stock options, ~~is recognized on a straight-line basis over the service period~~restricted stock units, performance stock awards, performance stock units, performance cash awards and cash awards. Effective January 20, 2021, as part of the ~~award less~~emergence from bankruptcy, the 2016 LTIP was terminated and no longer in effect and all outstanding awards ~~forfeited. The fair value of the stock options~~ were ~~measured at the grant date using the Black-Scholes valuation model. The~~cancelled.

Successor 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.Restricted Stock ~~options granted~~Units (“RSUs”)

RSUs issued under the 2021 LTIP ~~vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company will issue new shares.~~

The Company recorded $3.3 million and $9.9 million of stock-based compensation costs related to the stock options for the three and nine months ended September 30, 2017, respectively. These costs were included in the condensed consolidated statements of operations within the general and administrative expenses line item. The Company did not record any stock-based compensation expense related to stock options for the three and nine months ended September 30, 2016. As of September 30, 2017, there was $26.6 million of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted average period of 2.0 years.

~~The following table summarizes the stock option activity from January 1, 2017 through September 30, 2017 and provides information for stock options outstanding at the dates indicated.~~

Number of Options Weighted Average Exercise Price
Non-vested Stock Options at January 1, 2017 4,500,000
$ 19.00
Granted —
$ —
Forfeited —
$ —
Vested —
$ —
Non-vested Stock Options at September 30, 2017 4,500,000
$ 19.00

~~Restricted Stock Units~~

~~Restricted stock units granted under the LTIP (“RSUs”)~~ generally vest over either a one or ~~three year~~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 on~~ the ~~date~~Successor Company’s New Common Stock pursuant to the terms of ~~issuance.~~the 2021 LTIP. The Successor Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. ~~As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09.~~

The Successor Company recorded ~~$8.9~~$1.7 million and ~~$24.6~~$3.1 million of stock-based compensation costs related to Successor Company RSUs for the three ~~and nine~~ months ended ~~September~~June 30, ~~2017, respectively. The Company did not record any stock-based compensation costs related to RSUs~~2021 and for the ~~three and nine months ended September~~period from January 21, 2021 through June 30, ~~2016.~~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, ~~2017,~~2021, there was ~~$52.7~~$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 ~~1.9 years.~~

1.0 year. The following table summarizes the Successor Company’s RSU activity ~~from January 1, 2017 through September 30, 2017~~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, 2017	3,237,500	$	21.41
Non-vested Successor Company RSUs at January 21, 2021				Non-vested Successor Company RSUs at January 21, 2021	0	$	0
Granted	1,305,033	$	16.43	Granted	394,795	20.46
Forfeited	(403,725)	$	19.72	Forfeited	(6,799)	20.41
Vested	(85,994)	$	16.82	Vested	0	0
Non-vested RSUs at September 30, 2017	4,052,814	$	20.07
Non-vested Successor Company RSUs at June 30, 2021				Non-vested Successor Company RSUs at June 30, 2021	387,996	$	20.46

Predecessor Company RSUs

~~Incentive Restricted Stock Units~~

~~Officers of~~RSUs issued under 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 RSUs2016 LTIP generally vested over either a ~~three year~~one or three-year service period, with either 100% vesting in year one or 25%, 25% and 50% of the units vesting in ~~year~~years 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 will to vest 25%, 25% and 25% each six months thereafter, over the remaining 18 month service period. Grant date fair value was determined based on the value of ~~Extraction’s common stock on~~ the ~~date~~Predecessor Common Stock pursuant to the terms of ~~issuance.~~the 2016 LTIP. The Predecessor Company assumed a forfeiture rate of ~~zero~~0 as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09. As the vesting of any Incentive RSUs will be satisfied with shares of common stock that are already issued and outstanding, the Incentive RSUs do not have any impact on the Company’s diluted earnings per share calculation.

The Predecessor Company recorded ~~$5.9 million and $12.2~~$0.2 million of stock-based compensation costs related to ~~Incentive~~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 ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2020, respectively. ~~The Company did not record any stock-based compensation costs related to Incentive RSUs for the three and nine months ended September 30, 2016.~~ These costs were included in the condensed consolidated statements of operations within the ~~general~~“General and administrative ~~expenses~~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 PSUs to certain executives under the 2021 LTIP. The number of shares of New Common Stock that may be issued to settle these various PSUs ranges from zero to two times the number of PSUs awarded. Generally, the shares issued for PSUs are determined based on the satisfaction of a time-based vesting schedule and absolute total stockholder return (“ATSR”) measured over a three-year period, and vest in their entirety at the end of the three-year measurement period. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. As the ATSR vesting criterion are linked to the Successor Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the 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 ~~September~~June 30, ~~2017,~~2021, there was ~~$26.5~~$5.5 million of total unrecognized compensation cost related to the unvested ~~Incentive RSUs~~Successor Company PSUs granted to certain ~~employees~~executives that is expected to be recognized over a weighted average period of ~~1.3~~2.6 years.

The Successor Company’s PSUs will be settled by issuing New Common Stock. The following table summarizes the ~~Incentive RSU~~Successor Company’s PSU activity ~~from January 1, 2017 through September 30, 2017~~for the period shown and provides information for ~~Incentive RSUs~~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

Number of Shares
Weighted Average Grant Date
Fair Value
Non-vested Incentive RSUs at January 1, 2017 2,714,368
$ 20.45
Granted —
$ —
Forfeited (703,868)
$ 20.45
Vested (507,200)
$ 20.45
Non-vested Incentive RSUs at September 30, 2017 1,503,300
$ 20.45
_______________

(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.

~~Unit-Based Compensation~~

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, 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 ~~$12.3 million and $14.9~~$0.1 million of ~~unit-based~~stock-based compensation costs related to ~~restricted unit awards~~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, ~~2016,~~2020, respectively. ~~There~~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 no unrecognized compensation cost related to the unvested Predecessor Company PSAs granted to certain

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executives as they were all cancelled at emergence. The following table summarizes the Predecessor Company’s PSA activity 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

_______________

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

Successor Company Deferred Stock Units (“DSUs”)

Upon emergence from bankruptcy on January 20, 2021, a new Board was appointed and each Board member (except the CEO) was granted 16,800 Successor Company DSUs, which vest in quarterly installments over a one-year period following the grant date. The Successor Company DSUs will be settled in shares of New Common Stock upon the Board member’s departure from the Company; thus, these DSUs may not be included in the Successor Company’s issued and outstanding shares, potentially for several years. Grant date fair value was determined based on the value of the Successor Company’s New Common Stock pursuant to the terms of the 2021 LTIP. The Company assumed a forfeiture rate of 0 as part of the grant date estimate of compensation cost.

The Successor Company recorded $0.5 million and $0.9 million of stock-based compensation costs related to ~~these restricted unit awards as~~Successor Company DSUs 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 ~~September~~operations within the “General and administrative expense” line item. As of June 30, ~~2017. For~~2021, there was $1.1 million of total unrecognized compensation cost related to the unvested Successor Company DSUs granted to certain 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 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 ~~disclosure regarding these restricted unit awards, see~~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 ~~Annual Report.~~filed Form 10-Q from the first quarter of 2021 and Note 3—Fresh Start Reporting for more information.

Series A Preferred Stock

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 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 “Tranche B Warrants” and, together with the Tranche A Warrants, the “New Warrants”) to certain former holders of the Predecessor Common Stock.

The Tranche A Warrants are exercisable from the date of 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 unless, until and only to the extent such holders become holders of record of shares of New Common Stock issued upon settlement of the New Warrants.

The number of shares of New Common 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.

Upon completion of the BCEI Merger, the current warrant structure described above could result in a modification.

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Note ~~10—~~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 (the “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, 2017. EPS information is not applicable for the three and nine months ended September 30, 2016.~~

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 June 30,		For the Three Months Ended June 30,
	2021		2020
Basic and Diluted Income (Loss) Per Share
Net income (loss)	$	24,544	$	(291,934)

Less: Adjustment to reflect Series A Preferred Stock dividends	0		(4,001)
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	$	24,544	$	(297,752)
Denominator
Weighted average common shares outstanding, basic(1)(2)	25,777		138,163
Weighted average common shares outstanding, diluted	26,429		138,163
Income (Loss) Per Common Share
Basic	$	0.95	$	(2.16)
Diluted	$	0.93	$	(2.16)

_______________

(1) For the three months ended 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, 6,532,472 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.

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For the Three Months Ended September 30, 2017 For the Nine Months Ended September 30, 2017
Basic and Diluted Loss Per Share
Net Loss $ (29,796 ) $ (13,840 )
Less: Adjustment to reflect Series A Preferred Stock dividend (2,721 ) (8,164 )
Less: Adjustment to reflect accretion of Series A Preferred Stock discount (1,365 ) (3,992 )
Adjusted net loss available to common shareholders, basic and diluted $ (33,882 ) $ (25,996 )
Denominator:
Weighted average common shares outstanding, basic and diluted⁽¹⁾
171,845
171,838
Loss Per Common Share
Basic and diluted $ (0.20 ) $ (0.15 )


	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 period from January 21, 2021 through June 30, 2021, 607,273 dilutive shares, including restricted stock units, performance stock units and deferred stock units outstanding, were included in the calculation above.


~~(1)~~	For the three and nine months ended September 30, 2017, the diluted EPS calculation excludes the anti-dilutive effect of 4,500,000 common shares for stock options that were out-of-the-money, 4,052,814 RSUs and 11,472,445 common shares issuable for Series A Preferred Stock under the if-converted method.

(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 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 ~~11—~~12—Commitments and Contingencies

~~Leases~~General

~~The Company leases two office spaces~~As is customary in ~~Denver, Colorado, one office space in Greeley, Colorado~~the oil and one office space in Houston, Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31, 2026, respectively. The Greeley and Houston leases expire on August 31, 2019 and October 31, 2017, respectively. Total rental commitments under non‑cancelable leases for office space were $19.6 million at September 30, 2017. The future minimum lease payments under these non‑cancelable leases are as follows: $0.6 million in 2017, $2.6 million in 2018, $2.5 million in 2019, $2.2 million in 2020, $2.2 million in 2021 and $9.5 million thereafter. Rent expense was $0.5 million and $1.7 million for the three and nine months ended September 30, 2017, respectively, as compared to $0.6 million and $1.3 million for the three and nine months ended September 30, 2016, respectively.

~~On June 4, 2015,~~gas industry, the Company ~~subleased~~may at times have commitments in place to reserve or earn certain acreage positions or wells. If the ~~remaining term of one of its Denver office leases that expires February 29, 2020. The sublease will decrease~~Company does not meet such commitments, the ~~Company’s future lease payments by $0.6 million.~~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 ~~September~~June 30, ~~2017,~~2021, the Company was subject to ~~commitments on four~~no drilling ~~rigs. In~~rig commitments.

Leases

The Company has entered into operating leases for certain compressors and office facilities and 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

_______________

(1) Calculated using the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $12.1 million as of September 30, 2017, as required under the terms of the contracts. The fourth rig is expected to be placed in service during the fourth quarter of 2017 and will replace a rig currently under contract.estimated interest rate for each lease.

Delivery Commitments

~~As of September 30, 2017, the Company’s oil marketer was subject to~~The Predecessor Company entered into a ~~firm transportation~~long-term gas gathering and processing agreement ~~that~~(the “Gathering Agreement”) with a third-party midstream provider in February 2019. The Gathering Agreement commenced in ~~November 2016~~January 2020 and has 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. The Company amended its agreement with its oil marketer that requires it to sell all of its crude oil from an area of mutual interest in exchange for a make-whole provision that allows 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 through October 31, 2018. The Company evaluates its contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable. The Company also has one long-term crude oil gathering commitment with an unconsolidated affiliate. It has a term of ten years ~~for~~with an ~~average~~annual minimum volume commitment of ~~9,167~~13.0 Bcf. The 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, 17,967~~of the Gathering Agreement and 7,500 Bbl/d in ~~year~~years two ~~18,800 Bbl/d for years three~~ through ~~five~~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 ~~10,000 Bbl/d for years six through ten. The aggregate amount~~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 ~~estimated payments under these agreements is $1.0 billion.~~the settlement and amendment.

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 two~~Basin, including through the addition of 2 new processing plants as well as the expansion of related gathering ~~systems, which are currently expected to be completed by late~~systems. The first plant commenced operations in August 2018 and ~~mid-2019, respectively, although~~ the ~~start-up date is undetermined at this time.~~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, ~~to be delivered after the plants' in-service date~~over a baseline volume of 65 MMcf per day 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 ~~volumes~~incremental volume 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~~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. ~~Under its current drilling plans, the Company expects~~

Litigation and Legal Items

From time to ~~meet these volume commitments.~~

None of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers. The Company believes that its future production is adequate to meet its commitments. If for some reason the Company’s production is not sufficient to satisfy its commitments, the Company expects to be able to purchase volumes in the market or make other arrangements to satisfy its commitments.

~~Acquisition of Undeveloped Leasehold Acreage~~

~~As of September 30, 2017,~~time, the Company is ~~party~~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 ~~an agreement with an unrelated third party for which it has paid $77.5 million~~time, may settle or otherwise resolve these matters on terms and ~~may be required to pay up to an additional $116.5 million, subject to certain customary~~ conditions ~~to lease up to a total of approximately 30,000 net acres of undeveloped leasehold.~~

~~General~~

that management believes are in the Company’s best interests. The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits and other proceedings, including those involving environmental, tax and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Suchhas provided the necessary estimated accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the ~~estimates~~condensed consolidated balance sheets where deemed appropriate for litigation and 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 ~~future costs, which management currently believes~~such proceedings will not have a material adverse effect on ~~the Company’s~~our business, financial position, results of operations or ~~cash flows.~~liquidity.

~~As is customary in~~Environmental. Due to the nature of the oil and natural gas industry, the Company ~~may at times have commitments~~is exposed to environmental liabilities in place to connect wells to gathering and transportation services and 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.

~~Legal Matters~~

In the ordinary course of ~~business,~~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 disclosed herein, the Company ~~may at times be subject to~~is not aware of any material environmental claims ~~and legal actions. Management believes it is remote~~existing as of June 30, 2021 that ~~the impact of such matters will~~have not been provided for or would otherwise have a material ~~adverse effect~~impact on the Company’s financial ~~position, results~~statements. However, there can be no assurance that current regulatory requirements will not change or that unknown

Table of ~~operations~~Contents

potential past non-compliance with environmental laws, compliance matters or ~~cash flows. Management is unaware~~other environmental liabilities will not be discovered on our properties. The liability ultimately incurred with respect to a matter may exceed the related accrual.

COGCC Notices of ~~any pending litigation brought against~~Alleged Violations (“NOAVs”). The Company previously received NOAVs from the Colorado Oil and Gas Conservation Commission (the “COGCC”) for alleged compliance violations. On July 27, 2021, the COGCC approved a global settlement agreement with the Company ~~requiring~~that resolves these NOAVs. The settlement agreement requires the ~~reserve of~~Company to make a ~~contingent liability as of the date of this filing.~~

~~The Company is currently in discussions with the Colorado Department of Public Health and Environment (“CDPHE”) regarding a Compliance Advisory issued~~cash payment to the ~~Company in July 2015, which alleged air quality violations at three Company facilities regarding leakages~~COGCC of ~~volatile organic compounds from storage tanks, all of which were promptly addressed. The Company continues to work with the CDPHE on its investigation into the Company's facilities~~$0.1 million and ~~it intends to seek a field-wide administrative settlement of these issues. At this time, we anticipate the remediation and compliance costs~~also contains an obligation that ~~this matter may impose upon us to be an immaterial amount.~~

~~Note 12—Related Party Transactions~~

~~Office Lease with Related Affiliate~~

~~In April 2016,~~ the Company ~~subleased office space to Star Peak Capital, LLC,~~complete pubic projects that will cost the Company approximately $0.5 million.

Table of ~~which a member of the board of directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expires on February 28, 2020.~~Contents

~~2021 Senior Notes~~

Several lenders of the 2021 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in July 2016 of the $550.0 million principal amount on the 2021 Senior Notes, such stockholders held $63.5 million.

~~2024 Senior Notes~~

Several lenders of the 2024 Senior Notes are also 5% stockholders of the Company. As of the initial issuance in August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million.

~~Series A Preferred Stock~~

Several holders of the Series A Preferred Stock are also 5% stockholders of the Company. As of the initial issuance in October 2016 of the $185.3 million of Series A Preferred Stock, such stockholders held $105.0 million.

~~Long-Term Crude Oil Gathering Commitment~~

The Company has a long-term crude oil gathering commitment with an unconsolidated affiliate. It has a term of ten years for an average of 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d in years three through five and 10,000 Bbl/d in years six through ten. The aggregate amount of estimate payments under this agreement is $71.9 million.

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:

•our ability to execute on our business strategy following emergence from bankruptcy;

•the COVID-19 pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and 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;

•asset impairments from commodity price declines;

•the willingness of the Organization of Petroleum Exporting Countries (“OPEC”) 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;

•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;

•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;

~~hazardous, risky~~ •drilling operations ~~including those~~ 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;

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

•changes in tax laws;

•effects of competition; and

•the outbreak of communicable diseases such as coronavirus.

~~seasonal weather conditions.~~

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.~~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 ~~our~~Item 1A of this Quarterly Report, in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2016 (our “Annual~~2020

(“Annual Report”), and in ~~our~~the Company’s other filings with the Securities and Exchange Commission, which could materially affect our ~~businesses,~~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. ~~There has been no material changes in our risk factors from those described in our Annual Report.~~

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 its Annual Report and analyzes the changes in the results of operations between the three and ~~nine~~combined six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016.~~the three and six months ended June 30, 2020.

EXECUTIVE SUMMARY

We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the ~~DJ Basin.~~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~~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. ~~We are focused on growing our proved reserves and production primarily through the development~~

Table of ~~our large inventory of identified liquids‑rich horizontal drilling locations.~~Contents

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, ~~2017,~~2021, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, increased to ~~$183.7~~$204.4 million and ~~$384.3~~$486.2 million, respectively, as compared to ~~$77.6~~$94.5 million and ~~$215.9~~$299.0 million, respectively, in the same prior year periods due to an increase in sales volumes of 3,122 MBoe and 5,380 MBoe, respectively. The increase in crude oil, natural gas and NGL sales for the three and nine months ended September 30, 2017 as compared to the same prior year period ~~was also~~ due to an increase of ~~$2.64~~$17.95 and ~~$0.94,~~$18.64, respectively, in realized price per BOE, including settled ~~derivatives.~~derivatives, partially offset by a decrease in sales volumes of approximately 1,347 MBoe and 3,480 MBoe, respectively.

For the three and ~~nine~~combined six months ended ~~September~~June 30, ~~2017,~~2021, we had net ~~loss~~income of ~~$29.8~~$24.5 million and ~~$13.8~~$984.1 million, respectively, as compared to a net loss of ~~$37.3~~$291.9 million and ~~$210.4~~$282.9 million, respectively, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016, respectively.~~2020. The ~~changes~~change to net income for the three months ended June 30, 2021 from a net loss ~~were~~for the three months ended June 30, 2020 was primarily driven by an increase in sales revenues of ~~$108.0~~$160.5 million, ~~and $206.9~~a decrease in operating expenses of $122.2 million, ~~respectively~~a decrease in reorganization items, net of $26.9 million and a decrease of $18.1 million in interest expense, of $16.1 million and $24.2 million, respectively. Additionally, net loss decreased due to an increase in the income tax benefit of $17.1 million and $7.6 million for the three and nine months ended September 30, 2017 as compared to September 30, 2016, respectively. These increases werepartially offset by an increase in ~~operating~~income tax expenses of ~~$80.5 million and $152.5 million, respectively, primarily related~~$4.8 million. The change to ~~increased sales volumes. The increase to~~net income for the combined six months ended June 30, 2021 from a net loss for the ~~three~~six months ended ~~September~~June 30, ~~2017 and 2016~~2020 was ~~also driven by an decrease from a gain to a loss on commodity derivatives of $54.1 million. The decrease to net loss for the nine months ended September 30, 2017 and 2016 was also~~primarily driven by an increase ~~from~~in sales revenues of $287.8 million, a decrease in operating expenses of $307.4 million, an increase in reorganization items, net of $900.8 million, a decrease in the loss toon deconsolidation of Elevation of $73.1 million and a ~~gain on~~decrease of $34.9 million in interest expense, partially offset by a decrease in commodity ~~derivatives~~derivative gains of ~~$108.8~~$310.6 million and an increase in income tax expenses of $25.9 million.

Adjusted EBITDAX was ~~$128.4~~$150.1 million and ~~$245.8~~$357.3 million, respectively, for the three and ~~nine~~combined six months ended ~~September~~June 30, ~~2017, respectively,~~2021 as compared to ~~$48.2~~$114.0 million and ~~$138.0~~$237.9 million, respectively, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016, respectively,~~2020, reflecting a ~~166.6%~~32% increase and ~~78.1%~~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 ~~read~~refer to “—Adjusted EBITDAX.”

Operational Results

During the three and combined six months ended June 30, 2021, we focused on improving free cash flow and implemented operational efficiencies to reduce drilling and completion costs. During the three months ended ~~September~~June 30, ~~2017, our aggregate~~2021, we incurred approximately $47.3 million in drilling completion, leasehold and midstream capital expenditures, excluding acquisitions and business combinations, totaled $302.7 million, $252.4 million of which was drilling and completion. We invested $47.2 million on leasehold and $3.1 million for midstream. Our total drilling and completion capital expenditures for the nine months ended September 30, 2017 were approximately $701.1 million, including $30.7 million for non-operated drilling and completion.

~~During the three months ended September 30, 2017, we reached total depth on 53~~9 gross ~~(35~~(6.4 net) wells with an average lateral length of ~~approximately 8,300 feet~~2.1 miles and ~~completed 51~~completing 24 gross ~~(34~~(14.9 net) wells with an average lateral length of 2.2 miles. In addition, we incurred approximately ~~10,300 feet.~~$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 ~~(27~~(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 ~~7,900 feet.~~$4.6 million of leasehold and surface acreage additions. We ~~completed 3,053 total fracturing stages~~turned 22 gross (16.3 net) wells to sales during the ~~quarter while pumping approximately 965 million pounds of proppant.~~combined six months ended June 30, 2021.

Recent Developments

~~October 2017 Credit Facility Amendment~~Emergence from Chapter 11 Bankruptcy

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”) 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 Debtors’ Chapter 11 cases (the “Chapter 11 Cases”) were jointly administered under the caption In re Extraction Oil & Gas., et al. Case No. 20-11548 (CSS).

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 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 approved the adequacy of the Disclosure Statement and the Debtors commenced a solicitation process to obtain votes on the Plan. The Plan was confirmed by order of 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 the Company emerged from the Chapter 11 ~~2017,~~Cases.

NASDAQ Delisting and Relisting

Our common stock was traded on the NASDAQ Global Select Market (the “NASDAQ”) under the symbol “XOG” prior to June 25, 2020. On June 16, 2020, we ~~amended~~received a letter from NASDAQ notifying us that in accordance with NASDAQ rules, our securities would be delisted at the ~~revolving credit facility to,~~opening of business on June 25, 2020. On June 25, 2020, our common stock 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.”

Bonanza Creek Energy, Inc. Merger and Crestone Peak Merger

~~August 2017 Credit Facility Amendment and Restatement~~

~~On August 16, 2017, we entered into an amendment and restatement of our existing credit facility, which provides commitments of $1.5 billion with a syndicate of banks, which~~Crestone Peak Merger is ~~subject to a borrowing base of $375.0 million. The credit facility matures~~expressly conditioned on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the convertible preferred equity interests issued by the Company has not been converted into common equity or redeemed prior to April 15, 2021, and (ii) prior to April 15, 2021, the maturity dateclosing 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 (d) the earlier termination in whole~~BCEI Merger. Upon completion of the ~~commitments.~~

~~2024 Senior Notes~~

~~On August 1, 2017, we issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the "2024 Senior Notes"~~BCEI Merger and Crestone Peak Merger, the ~~offering, the "2024 Senior Notes Offering"~~combined company will be named Civitas Resources, Inc. (“Civitas”). ~~The 2024 Senior Notes bear an annual interest rate~~Following the BCEI Merger and Crestone Peak Merger, Bonanza Creek President and Chief Executive Officer, Eric Greager, will serve as President and CEO of ~~7.375%. The interest on~~Civitas. Other senior leadership positions will be filled by current executives of Bonanza Creek and Extraction. As designated in the ~~2024 Senior Notes is payable on May 15~~BCEI Merger agreement, of the six named officers, three will be from Bonanza Creek and ~~November 15~~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 ~~year commencing on November 15, 2017.~~nominate four directors, and CPP Investments will nominate one director to Civitas’ diverse, nine-member Board. We ~~received net~~anticipate the BCEI Merger will be completed during the latter half of 2021.

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Divestiture

In April 2021, we completed the sale of certain non-operated producing properties for aggregate sales proceeds of approximately ~~$392.6~~$15.2 million, ~~after deducting discounts and fees. We intend~~subject to ~~use~~customary purchase price adjustments. No gain or loss was recognized. In conjunction with the ~~net proceeds from~~April 2021 divestiture,we recorded a receivable of approximately $2.7 million in the ~~2024 Senior Notes Offering to partially fund our 2017 capital expenditures and~~condensed consolidated balance sheet as of June 30, 2021 for ~~general corporate purposes.~~post-closing adjustments.

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; ~~and~~

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

•Free cash flow (a 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 ~~NGL~~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, ~~2017,~~2021, our revenues were derived ~~73% from oil sales, 14% from natural gas sales and 13% from NGL sales. For the three months ended September 30, 2016, our revenues were derived 71%~~62% from oil sales, 18% from natural gas sales and ~~11%~~20% from NGL sales. For the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2020, our revenues were derived ~~69%~~58% from oil sales, ~~16%~~25% from natural gas sales and ~~15%~~17% from NGL sales. For the ~~nine~~combined six months ended ~~September~~June 30, ~~2016,~~2021, our revenues were derived ~~74%~~52% from oil sales, ~~15%~~32% from natural gas sales and ~~11%~~16% from NGL sales. For the six months ended June 30, 2020, our revenues were derived 71% from oil sales, 17% from natural gas sales and 12% 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 ~~our properties for~~ the periods indicated:


						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,
	2017	2016	2017	2016		2021	2020
Oil (MBbl)	3,184	1,290	6,496	3,808	Oil (MBbl)	2,349	3,419
Natural gas (MMcf)	8,953	4,792	21,713	12,851	Natural gas (MMcf)	15,834	17,543
NGL (MBbl)	1,109	574	2,695	1,479	NGL (MBbl)	1,987	1,979
Total (MBoe)	5,785	2,663	12,809	7,429	Total (MBoe)	6,975	8,322
Average net sales (BOE/d)	62,884	28,948	46,921	27,114	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 ~~pressure declines,~~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. ~~Accordingly, we plan to maintain our focus on adding reserves through organic growth as well as acquisitions.~~ 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 ~~read~~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.

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, ~~2017,~~2021, NYMEX West Texas Intermediate (“WTI”) oil prices ranged from a high of ~~$107.26~~$74.05 per Bbl to a low of ~~$26.21~~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 ~~$1.64~~$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 ~~continuing into 2017~~2021 are due to a combination of factors including increased U.S. supply, global economic concerns stemming from COVID-19, the price war between Russia and ~~geopolitical risks.~~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 ~~predominately~~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 September 30,						For the Nine Months Ended September 30,								For the Three Months Ended June 30,										For the Six Months Ended June 30,
	2017			2016			2017			2016					2021					2020					2021					2020
Oil													Oil
NYMEX WTI High ($/Bbl)	$	52.22		$	48.99		$	54.45		$	51.23		NYMEX WTI High ($/Bbl)		$	74.05				$	40.46				$	74.05				$	63.27
NYMEX WTI Low ($/Bbl)	$	44.23		$	39.51		$	42.53		$	26.21		NYMEX WTI Low ($/Bbl)		$	58.65				$	(37.63)				$	47.62				$	(37.63)
NYMEX WTI Average ($/Bbl)	$	48.20		$	44.94		$	49.36		$	41.53		NYMEX WTI Average ($/Bbl)		$	66.10				$	28.00				$	62.21				$	36.82
Average Realized Price ($/Bbl)	$	41.48		$	40.11		$	41.50		$	35.68
Average Realized Price, with derivative settlements ($/Bbl)	$	42.14		$	42.73		$	40.61		$	41.93
Average Realized Price ($/Bbl)(1)													Average Realized Price ($/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)		$	50.60				$	18.11				$	50.27				$	31.97
Average Realized Price as a % of Average NYMEX WTI	86.1		%	89.3		%	84.1		%	85.9		%	Average Realized Price as a % of Average NYMEX WTI		89.6		%			37.9		%			91.5		%			63.0		%
Differential ($/Bbl) to Average NYMEX WTI	$	(6.72	)	$	(4.83	)	$	(7.86	)	$	(5.85	)
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
NYMEX Henry Hub High ($/MMBtu)	$	3.15		$	3.06		$	3.42		$	3.06		NYMEX Henry Hub High ($/MMBtu)		$	3.65				$	2.13				$	3.65				$	2.20
NYMEX Henry Hub Low ($/MMBtu)	$	2.77		$	2.55		$	2.56		$	1.64		NYMEX Henry Hub Low ($/MMBtu)		$	2.46				$	1.48				$	2.45				$	1.48
NYMEX Henry Hub Average ($/MMBtu)	$	2.95		$	2.79		$	3.05		$	2.35		NYMEX Henry Hub Average ($/MMBtu)		$	2.97				$	1.75				$	2.85				$	1.81
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)	$	2.76		$	2.67		$	2.91		$	2.16		$	2.49				$	0.91				$	5.38				$	1.05
Average Realized Price, with derivative settlements ($/Mcf)(5)	$	2.84		$	2.94		$	2.90		$	2.84		$	2.56				$	1.24				$	5.42				$	1.32
Average Realized Price as a % of Average NYMEX Henry Hub⁽¹⁾⁽⁵⁾	84.9		%	87.0		%	86.6		%	83.4		%	76.1		%			47.2		%			171.3		%			52.8		%
Differential ($/Mcf) to Average NYMEX Henry Hub⁽¹⁾⁽⁵⁾	$	(0.49	)	$	(0.40	)	$	(0.45	)	$	(0.43	)	$	(0.78)				$	(1.02)				$	2.24				$	(0.94)
NGL													NGL
Average Realized Price ($/Bbl)(5)	$	21.74		$	14.54		$	21.36		$	13.37		$	22.67				$	5.47				$	23.33				$	7.21
Average Realized Price as a % of Average NYMEX WTI	45.1		%	32.4		%	43.3		%	32.2		%
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
Average Realized Price per BOE(1)													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		$	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 three and six months ended June 30, 2020, pursuant to ASC Topic 606—Revenue Recognition (“ASC 606”).

(2) Excludes non-cash amounts allocated to a satisfied performance obligation, recognized within oil sales for the three and six months ended June 30, 2020, pursuant to ASC 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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~~(1)~~	~~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.~~

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, ~~where we have unrealized gains in our derivative portfolio,~~ we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. 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.

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. ~~As a result of recent volatility in the price of oil and natural gas, we~~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.

~~A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays~~ The RBL Credit Agreement requires us ~~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, we pay our 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~~maintain commodity hedges covering a minimum 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. Some65% of our ~~purchased put options have deferred premiums. For~~anticipated oil and gas production from PDP reserves for the ~~deferred premium puts, we agreed to pay a premium to~~succeeding twelve months and 50% of our anticipated oil and gas production from PDP reserves for the ~~counterparty~~next succeeding twelve months.

The hedge prices will depend on the commodity price environment at the time ~~of settlement.~~

~~We combine swaps, purchased put options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of our hedging strategies~~at which those hedge transactions 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. We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices.

~~We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in~~entered. In the current commodity price environment, our ability to enter into ~~comparable~~ derivative arrangements at favorable prices may be ~~limited, and, we are not obligated to hedge~~limited.

For a ~~specific portion~~description of our ~~oil or natural gas production. The following summarizes~~derivative instruments that we utilize and a summary of our commodity derivative ~~positions related to crude oil and natural gas sales in effect~~contracts as of ~~September~~June 30, ~~2017:~~2021, please see Note 5—Commodity Derivative Instruments in Item 1 of this Quarterly Report.

2017 2018 2019
NYMEX WTI⁽¹⁾ Crude Swaps:

Notional volume (Bbl) 1,850,000
5,100,000
—
Weighted average fixed price ($/Bbl) $ 50.64
$ 51.61

NYMEX WTI⁽¹⁾ Crude Sold Calls:

Notional volume (Bbl) 1,200,000
6,190,000
3,000,000
Weighted average sold call price ($/Bbl) $ 53.04
$ 55.75
$ 55.10
NYMEX WTI⁽¹⁾ Crude Sold Puts:

Notional volume (Bbl) 3,225,000
11,338,800
3,000,000
Weighted average sold put price ($/Bbl) $ 37.19
$ 38.93
$ 39.70
NYMEX WTI⁽¹⁾ Crude Purchased Puts:

Notional volume (Bbl) 1,800,000
6,838,800
3,000,000
Weighted average purchased put price ($/Bbl) $ 42.13
$ 47.35
$ 49.37
NYMEX HH⁽²⁾ Natural Gas Swaps:

Notional volume (MMBtu) 7,420,000
37,200,000
—
Weighted average fixed price ($/MMBtu) $ 3.06
$ 3.10

NYMEX HH⁽²⁾ Natural Gas Purchased Puts:

Notional volume (MMBtu) —
2,400,000
—
Weighted average purchased put price ($/MMBtu) $ 3.00

NYMEX HH⁽²⁾ Natural Gas Sold Calls:

Notional volume (MMBtu) —
2,400,000
—
Weighted average sold call price ($/MMBtu) $ 3.15

CIG⁽³⁾ Basis Gas Swaps:

Notional volume (MMBtu) 5,215,000
6,300,000
—
Weighted average fixed basis price ($/MMBtu) $ (0.31 ) $ (0.31 )

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~~(1)~~	~~NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange~~


~~(2)~~	~~NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange~~


~~(3)~~	~~CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price.~~

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


								Successor		Predecessor		Predecessor
	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,
	2017			2016				2021		2021		2020
NYMEX HH⁽¹⁾ Natural Gas Swaps:
NYMEX WTI Crude Swaps:							NYMEX WTI Crude Swaps:
Notional volume (Bbl)							Notional volume (Bbl)	2,788,200		—		525,000
Weighted average fixed price ($/Bbl)							Weighted average fixed price ($/Bbl)	$	50.34	$	—	$	60.05
NYMEX WTI Crude Purchased Puts:							NYMEX WTI Crude Purchased Puts:
Notional volume (Bbl)							Notional volume (Bbl)	—		—		4,950,000
Weighted average purchased put price ($/Bbl)							Weighted average purchased put price ($/Bbl)	$	—	$	—	$	54.48
NYMEX WTI Crude Purchased Calls:							NYMEX WTI Crude Purchased Calls:
Notional volume (Bbl)							Notional volume (Bbl)	—		—		1,100,000
Weighted average purchased call price ($/Bbl)							Weighted average purchased call price ($/Bbl)	$	—	$	—	$	68.04
NYMEX WTI Crude Sold Calls:							NYMEX WTI Crude Sold Calls:
Notional volume (Bbl)							Notional volume (Bbl)	—		—		5,650,000
Weighted average sold call price ($/Bbl)							Weighted average sold call price ($/Bbl)	$	—	$	—	$	63.37
NYMEX WTI Crude Sold Puts:							NYMEX WTI Crude Sold Puts:
Notional volume (Bbl)							Notional volume (Bbl)	—		—		5,300,000
Weighted average sold put price ($/Bbl)							Weighted average sold put price ($/Bbl)	$	—	$	—	$	44.39
NYMEX HH Natural Gas Swaps:							NYMEX HH Natural Gas Swaps:
Notional volume (MMBtu)	18,000,000			9,879,600			Notional volume (MMBtu)	12,437,315		—		17,400,000
Weighted average fixed price ($/MMBtu)	$	3.05		$	3.15		Weighted average fixed price ($/MMBtu)	$	2.94	$	—	$	2.75
CIG⁽³⁾ Basis Gas Swaps:
NYMEX HH Natural Gas Purchased Puts:							NYMEX HH Natural Gas Purchased Puts:
Notional volume (MMBtu)							Notional volume (MMBtu)	—		—		600,000
Weighted average purchased put price ($/MMBtu)							Weighted average purchased put price ($/MMBtu)	$	—	$	—	$	2.90
NYMEX HH Natural Gas Sold Calls:							NYMEX HH Natural Gas Sold Calls:
Notional volume (MMBtu)							Notional volume (MMBtu)	—		—		600,000
Weighted average sold call price ($/MMBtu)							Weighted average sold call price ($/MMBtu)	$	—	$	—	$	3.48
CIG Basis Gas Swaps:							CIG Basis Gas Swaps:
Notional volume (MMBtu)	7,400,000			1,980,000			Notional volume (MMBtu)	—		—		22,800,000
Weighted average fixed basis price ($/MMBtu)	$	(0.35	)	(0.19		)	Weighted average fixed basis price ($/MMBtu)	$	—	$	—	$	(0.61)
NYMEX WTI⁽²⁾ Crude Swaps:
Notional volume (Bbl)	2,275,000			1,464,060
Weighted average fixed price ($/Bbl)	$	45.88		$	43.01
NYMEX WTI⁽²⁾ Crude Sold Puts:
Notional volume (Bbl)	4,495,000			1,350,000
Weighted average strike price ($/Bbl)	$	38.02		$	44.89
NYMEX WTI⁽²⁾ Crude Purchased Puts:
Notional volume (Bbl)	3,770,000			3,599,150
Weighted average strike price ($/Bbl)	$	46.63		$	51.94
NYMEX WTI⁽²⁾ Crude Sold Calls:
Notional volume (Bbl)	3,420,000			1,947,090
Weighted average strike price ($/Bbl)	$	55.28		$	61.29
NYMEX WTI⁽²⁾ Crude Purchased Calls:
Notional volume (Bbl)	300,000			216,000
Weighted average strike price ($/Bbl)	$	60.83		$	69.58
Total Amounts Received/(Paid) from Settlement (in thousands)	$	(6,022	)	$	37,947		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	$	(2,871	)	$	5,068		Cash provided by (used in) changes in Accounts Receivable and Accounts Payable related to Commodity Derivatives	8,703		542		(5,213)
Cash Settlements on Commodity Derivatives per Consolidated Statements of Cash Flows	$	(8,893	)	$	43,015
Derivative unwinds reducing the Prior Credit Facility balance							Derivative unwinds reducing the Prior Credit Facility balance	—		—		(96,065)
Settlements on Commodity Derivatives per Condensed Consolidated Statements of Cash Flows							Settlements on Commodity Derivatives per Condensed Consolidated Statements of Cash Flows	$	(21,168)	$	542	$	65,447


~~(1)~~	~~NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange~~


~~(2)~~	~~NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange~~


~~(3)~~	~~CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price~~

Lease Operating Expenses

All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface ~~constitute~~constitutes part of the current operating expenses of a working interest. Such costs include labor, superintendence, 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 ~~and~~or completion expenses. ~~LOE also includes expenses incurred to gather and deliver natural gas to the processing plant and/or selling point.~~

Capital Expenditures

For the ~~nine~~combined six months ended ~~September~~June 30, ~~2017,~~2021, we incurred approximately ~~$701.1~~$78.8 million in drilling and completion capital ~~expenditures in connection with~~expenditures. For the ~~drilling of 141~~combined six months ended June 30, 2021, we drilled 20 gross ~~(98~~(12.5 net) wells with an average lateral length of approximately ~~8,700 feet~~2.2 miles and completed ~~156~~39 gross ~~(133~~(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 ~~8,200 feet. We turned to sales 123 gross (116 net) wells with an average lateral length of approximately 7,300 feet.~~2.2 miles during the combined six months ended June 30, 2021. In addition, we incurred approximately ~~$98.6~~$4.6 million of leasehold and surface acreage additions ~~and approximately $7.8 million~~during the combined six months ended June 30, 2021.

On July 8, 2021, the board of ~~midstream and infrastructure additions, excluding amounts paid for asset acquisitions and business combinations.~~

~~Our initial 2017~~directors approved an increase in our 2021 capital expenditures budget. The 2021 total revised capital budget was ~~approximately $795~~approved to be $159 million, ~~to $935~~which includes $146 million substantially all of which we intend to allocate to the DJ Basin. We intend to allocate approximately $675 million to $775 million of our 2017 capital budget to the drilling of 185 to 190 gross operated wells and the completion of 190 to 195 gross operated wells, approximately $60 to $80 million of non-operatedfor drilling and completion activity and ~~approximately $60~~$13 million ~~to $80 million to undeveloped leasehold acquisitions, midstream,~~for plugging and abandoning and other ~~capital expenditures. We are currently running a three rig program and plan to remain with a three rig program throughout 2017. Our~~activity. Previously, our 2021 capital budget ~~excludes any amounts that were or may be paid~~was $142 million, which included $130 million for ~~potential acquisitions.~~

The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and ~~acquisition costs~~completions activity and ~~the level~~$12 million for plugging and abandoning and other activity.

Table of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.Contents

Adjusted EBITDAX

Adjusted EBITDAX is not a measure of net income (loss) as determined by ~~United States generally accepted accounting principles ("GAAP").~~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, exploration expenses, rig termination fees, acquisition transaction expenses, commodity derivative (gain) loss, settlements on commodity derivatives, premiums paid~~Adjusted EBITDAX to the GAAP financial measure of net income (loss) for ~~derivatives that settled during~~each of the ~~period, unit and stock-based compensation expense, amortization~~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 ~~debt discount and debt issuance costs, interest expense, income taxes and non-recurring charges.~~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:

(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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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) 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 and to return capital to stockholders.

The following ~~table presents~~tables present a reconciliation of ~~Adjusted EBITDAX~~Discretionary Cash Flow and Free Cash Flow to the GAAP financial measure of net ~~loss~~cash provided by operating activities for each of the periods ~~indicated (in thousands).~~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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For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,
2017 2016 2017 2016
Reconciliation of Net Loss to Adjusted EBITDAX:
Net loss $ (29,796 ) $ (37,267 ) $ (13,840 ) $ (210,400 )
Add back:
Depletion, depreciation, amortization and accretion 94,220
46,680
213,483
141,317
Impairment of long lived assets —
467
675
23,350
Exploration expenses 7,181
5,985
24,431
14,735
Rig termination fee —
—
—
891
Loss on sale of property and equipment —
—
451
—
Acquisition transaction expenses —
345
68
345
(Gain) loss on commodity derivatives 37,875
(16,225 ) (46,423 ) 62,424
Settlements on commodity derivative instruments 3,162
4,787
(6,022 ) 37,947
Premiums paid for derivatives that settled during the period (293 ) (132 ) 20
(5,470 )
Unit and stock-based compensation expense 18,110
12,315
46,707
14,922
Amortization of debt discount and debt issuance costs 1,469
15,905
3,181
18,330
Interest expense 13,611
15,311
30,580
39,584
Income tax benefit (17,106 ) —
(7,556 ) —
Adjusted EBITDAX $ 128,433
$ 48,171
$ 245,755
$ 137,975


	Predecessor
	Upstream		Midstream		Consolidated
	For the Six Months Ended
	June 30, 2020
Cash Flow from Operating Activities
Net cash provided by operating activities	$	81,074	$	2,880	$	83,954
Changes in current assets and liabilities	(48,064)		(1,907)		(49,971)
Discretionary Cash Flow	33,010		973		33,983
Cash Flow from Investing Activities
Net cash used in investing activities	(185,573)		(5,840)		(191,413)
Change in accounts payable and accrued liabilities related to capital expenditures	24,374		2,210		26,584
Adjusted Cash Flow used in Investing	(161,199)		(3,630)		(164,829)
Other Non-Recurring Adjustments(1)	1,170		—		1,170
Free Cash Flow	$	(127,019)	$	(2,657)	$	(129,676)

_______________

(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.

~~On October 3, 2016,~~•During the Chapter 11 Cases, our financial results were volatile as restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impacted our financial results. For the combined six months ended June 30, 2021, prior to emergence, we ~~acquired additional~~realized an $873.9 million reorganization items, net 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 combined six months ended June 30, 2021 compared to the six months ended June 30, 2020, exploration and abandonment expenses decreased primarily due to the abandonment of $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 gas ~~properties primarily located~~properties. See Note 3—Fresh Start Reporting in Item 1 of 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 ~~Wattenberg Field located primarily around our existing Greeley and Windsor areas. The October 2016 Acquisition consisted~~condensed consolidated statements of ~~working interest in approximately 6,400 net acres and 31 gross (19 net) drilled but uncompleted wells, as of~~operations for the ~~date of acquisition. The October 2016 Acquisition provided net daily production of approximately 6,900 BOE/d during the fourth quarter 2016.~~

As a result of the initial public offering (“IPO”), we expect to incur additional general and administrative expenses related to being a public company, including Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley Act compliance; expenses associated with listing on the NASDAQ Global Select Market; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and directors compensation.

In October 2016, our board of directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan ("LTIP") and granted awards to certain directors and officers, including stock options and restricted stock units. We recognized $18.1 million and $46.7 million of stock-based compensation expense for three and ninesix months ended ~~September~~June 30, ~~2017 related to these awards.~~2020.

Prior to the Corporate Reorganization, we were not subject to federal or state income taxes. Accordingly, the financial data attributable to us prior to such corporate reorganization contain no provision for federal or state income taxes because the tax liability with respect to Holdings’ taxable income was passed through to its members. Beginning October 12, 2016, we began to be taxed as a C corporation under the Internal Revenue Code and subject to federal and state income taxes at a blended statutory rate

Table of ~~approximately 38% of pretax earnings.~~Contents

Historical Results of Operations and Operating Expenses

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

~~The following table provides the~~For components of our revenues, operating expenses, other income (expense) and net ~~loss for the periods indicated (in thousands):~~income (loss), please see our condensed consolidated statements of operations in Item 1 of this Quarterly Report.

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,
2017 2016 2017 2016
(Unaudited)
Revenues:
Oil sales $ 132,075
$ 51,760
$ 269,597
$ 135,896
Natural gas sales 24,672
12,792
63,095
27,730
NGL sales 24,114
8,350
57,574
19,773
Total Revenues 180,861
72,902
390,266
183,399
Operating Expenses:
Lease operating expenses 29,267
15,480
75,755
40,819
Production taxes 16,290
6,186
33,254
16,935
Exploration expenses 7,181
5,985
24,431
14,735
Depletion, depreciation, amortization and accretion 94,220
46,680
213,483
141,317
Impairment of long lived assets —
467
675
23,350
Other operating expenses —
—
451
891
Acquisition transaction expenses —
345
68
345
General and administrative expenses 28,741
20,071
77,916
35,189
Total Operating Expenses 175,699
95,214
426,033
273,581
Operating Income (Loss) 5,162
(22,312 ) (35,767 ) (90,182 )
Other Income (Expense):
Commodity derivatives gain (loss) (37,875 ) 16,225
46,423
(62,424 )
Interest expense (15,080 ) (31,216 ) (33,761 ) (57,914 )
Other income 891
36
1,709
120
Total Other Income (Expense) (52,064 ) (14,955 ) 14,371
(120,218 )
Loss Before Income Taxes (46,902 )
(37,267 )
(21,396 )
(210,400 )
Income tax benefit (17,106 ) —
(7,556 ) —
Net Loss $ (29,796 ) $ (37,267 ) $ (13,840 ) $ (210,400 )

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


	Successor			Predecessor
	For the Three Months Ended June 30,			For the Three Months Ended June 30,
	2021			2020
Sales (MBoe)(1):	6,975			8,322
Oil sales (MBbl)	2,349			3,419
Natural gas sales (MMcf)	15,834			17,543
NGL sales (MBbl)	1,987			1,979
Sales (BOE/d)(1):	76,645			91,451
Oil sales (Bbl/d)	25,814			37,571
Natural gas sales (Mcf/d)	173,997			192,780
NGL sales (Bbl/d)	21,829			21,747
Average sales prices(2):
Oil sales (per Bbl)(3)	$	59.22		$	10.61
Oil sales with derivative settlements (per Bbl)(3)	50.60			18.11
Natural gas sales (per Mcf)(4)	2.49			0.91
Natural gas sales with derivative settlements (Mcf)(4)	2.56			1.24
NGL sales (per Bbl)(4)	22.67			5.47
Average price (per BOE)(4)(3)	32.06			7.59
Average price with derivative settlements (per BOE)(4)(3)	29.30			11.35
Expense per BOE:
Lease operating expenses	$	1.97		$	2.76
Transportation and gathering	3.09			3.16
Production taxes	1.56			0.56
Exploration and abandonment expenses	0.51			7.53
Depletion, depreciation, amortization and accretion	7.18			9.93
General and administrative expenses	1.57			3.02
Cash general and administrative expenses(5)	1.17			2.71
Stock-based compensation	0.40			0.31
Total operating expenses per BOE(6)	$	15.88		$	26.96

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 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 three months ended June 30, 2020, pursuant to ASC 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 impairment of long-lived assets 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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	For the Three Months Ended				For the Nine Months Ended					Successor			Predecessor			Non-GAAP			Predecessor
	September 30,				September 30,					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,
	2017		2016		2017		2016			2021			2021			2021			2020
Sales (MBoe)⁽¹⁾:	5,785		2,663		12,809		7,429		Sales (MBoe)(1):	11,927			1,492			13,419			16,899
Oil sales (MBbl)	3,184		1,290		6,496		3,808		Oil sales (MBbl)	4,141			546			4,687			6,923
Natural gas sales (MMcf)	8,953		4,792		21,713		12,851		Natural gas sales (MMcf)	27,198			3,412			30,610			36,546
NGL sales (MBbl)	1,109		574		2,695		1,479		NGL sales (MBbl)	3,254			376			3,630			3,885
Sales (BOE/d)⁽¹⁾:	62,884		28,948		46,921		27,114		Sales (BOE/d)(1):	74,081			74,600			74,137			92,852
Oil sales (Bbl/d)	34,607		14,025		23,794		13,899		Oil sales (Bbl/d)	25,719			27,312			25,895			38,038
Natural gas sales (Mcf/d)	97,311		52,083		79,536		46,902		Natural gas sales (Mcf/d)	168,933			170,588			169,113			200,802
NGL sales (Bbl/d)	12,059		6,242		9,871		5,397		NGL sales (Bbl/d)	20,209			18,820			20,049			21,346
Average sales prices⁽²⁾:									Average sales prices(2):
Oil sales (per Bbl)	$	41.48	$	40.11	$	41.50	$	35.68
Oil sales with derivative settlements (per Bbl)	42.14		42.73		40.61		41.93
Natural gas sales (per Mcf)	2.76		2.67		2.91		2.16
Natural gas sales with derivative settlements (per Mcf)	2.84		2.94		2.90		2.84
NGL sales (per Bbl)	21.74		14.54		21.36		13.37
Average price (per BOE)	31.26		27.38		30.47		24.69
Average price with derivative settlements (per BOE)	31.76		29.12		30.00		29.06
Oil sales (per Bbl)(3)									Oil sales (per Bbl)(3)	$	57.88		$	49.68		$	56.92		$	23.18
Oil sales with derivative settlements (per Bbl)(3)									Oil sales with derivative settlements (per Bbl)(3)	50.35			49.68			50.27			31.97
Natural gas sales (per Mcf)(4)									Natural gas sales (per Mcf)(4)	5.77			2.29			5.38			1.05
Natural gas sales with derivative settlements (Mcf)(4)									Natural gas sales with derivative settlements (Mcf)(4)	5.81			2.29			5.42			1.32
NGL sales (per Bbl)(4)									NGL sales (per Bbl)(4)	23.55			21.52			23.33			7.21
Average price (per BOE)(4)(3)									Average price (per BOE)(4)(3)	39.66			28.85			38.46			13.42
Average price with derivative settlements (per BOE)(4)(3)									Average price with derivative settlements (per BOE)(4)(3)	37.16			28.85			36.24			17.60
Expense per BOE:									Expense per BOE:
Lease operating expenses	$	5.06	$	5.81	$	5.91	$	5.49	Lease operating expenses	$	2.05		$	1.71		$	2.01		$	3.16
Operating expenses	2.67		3.57		3.25		3.46
Transportation and gathering	2.39		2.24		2.66		2.03		Transportation and gathering	3.75			4.19			3.80			2.91
Production taxes	2.82		2.32		2.60		2.28		Production taxes	2.71			2.21			2.66			1.07
Exploration expenses	1.24		2.25		1.91		1.98
Exploration and abandonment expenses									Exploration and abandonment expenses	0.36			0.21			0.35			10.36
Depletion, depreciation, amortization and accretion	16.29		17.53		16.67		19.02		Depletion, depreciation, amortization and accretion	7.43			10.81			7.81			9.39
Impairment of long lived assets	—		0.18		0.05		3.14
Other operating expenses	—		—		0.04		0.12
Acquisition transaction expenses	—		0.13		0.01		0.05
General and administrative expenses	4.97		7.54		6.08		4.74		General and administrative expenses	1.55			1.48			1.54			2.12
Cash general and administrative expenses	1.84		2.92		2.43		2.73
Unit and stock-based compensation	3.13		4.62		3.65		2.01
Total operating expenses per BOE	$	30.38	$	35.76	$	33.27	$	36.82
Cash general and administrative expenses(5)									Cash general and administrative expenses(5)	1.14			1.28			1.15			1.97
Stock-based compensation									Stock-based compensation	0.41			0.20			0.39			0.15
Total operating expenses per BOE(6)									Total operating expenses per BOE(6)	$	17.85		$	20.61		$	18.17		$	29.01

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

_______________


~~(1)~~	(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 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, ~~2017~~2021 Compared to Three Months Ended ~~September~~June 30, ~~2016~~2020

Oil sales revenues. Crude oil sales revenues increased by ~~$80.3~~$102.8 million to ~~$132.1~~$139.1 million for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to crude oil sales of ~~$51.8~~$36.3 million for the three months ended ~~September~~June 30, ~~2016.~~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 ~~$76.0~~$11.4 million ~~positive~~ ~~impact, while an~~ ~~increase~~ ~~in crude oil prices contributed a $4.3 million~~ ~~positive~~negative impact.

For the three months ended ~~September~~June 30, ~~2017,~~2020, crude oil revenue decreased by approximately $3.9 million 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 June 30, 2021, our crude oil sales averaged ~~34.6~~25.8 MBbl/d. Our crude oil sales volume ~~increased~~ ~~147%~~decreased by 1,070 to ~~3,184~~2,349 MBbl for the three months ended ~~September~~June 30, ~~2017~~2021 compared to ~~1,290~~3,419 MBbl for the three months ended ~~September~~June 30, ~~2016.~~2020. The volume ~~increase~~decrease is primarily due to the natural decline of our existing properties, only partially offset by an increase in production from the completion of ~~172~~40 gross wells from ~~October~~July 1, ~~2016~~2020 to ~~September~~June 30, ~~2017, partially offset by~~2021, since during the ~~natural decline~~second half of 2020 and in early 2021 prior to emergence from bankruptcy, our ~~existing properties.~~drilling program had been suspended.

The average price we realized on the sale of crude oil was ~~$41.48~~$59.22 per Bbl for the three months ended ~~September~~June 30, ~~2017~~2021 compared to ~~$40.11~~$10.61 per Bbl for the three months ended ~~September~~June 30, ~~2016.~~2020. For the three months ended June 30, 2020, crude oil revenue decreased $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 June 30, 2021, no such decrease in crude oil revenue was recorded.

Natural gas sales revenues. Natural gas sales revenues increased by ~~$11.9~~$23.5 million to ~~$24.7~~$39.5 million for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to natural gas sales revenues of ~~$12.8~~$16.0 million for the three months ended ~~September~~June 30, ~~2016.~~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 ~~$11.1~~$1.6 million ~~positive~~ ~~impact, while an~~ ~~increase~~ ~~in natural gas prices contributed a $0.8 million~~ ~~positive~~ ~~impact due to increasing natural gas prices.~~negative impact.

For the three months ended ~~September~~June 30, ~~2017,~~2021, our natural gas sales averaged ~~97.3~~174.0 MMcf/d. Natural gas sales volumes ~~increased~~decreased by ~~87%~~1,709 to ~~8,953~~15,834 MMcf for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to ~~4,792~~17,543 MMcf for the three months ended ~~September~~June 30, ~~2016.~~2020. The volume ~~increase~~decrease is primarily due to ~~the completion of 172 gross wells from October 1, 2016 to September 30, 2017, 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 ~~$2.76~~$2.49 per Mcf for the three months ended ~~September~~June 30, ~~2017~~2021 compared to ~~$2.67~~$0.91 per Mcf for the three months ended ~~September~~June 30, ~~2016.~~2020, primarily due to an increase in pricing as compared to the three months ending June 30, 2020.

NGL sales revenues. NGL sales revenues increased by ~~$15.7~~$34.2 million to ~~$24.1~~$45.0 million for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to NGL sales revenues of ~~$8.4~~$10.8 million for the three months ended ~~September~~June 30, ~~2016.~~2020. An increase in ~~sales volumes~~prices between these periods contributed a ~~$7.7~~$34.2 million positive impact, while a decrease in volumes contributed an ~~increase~~ ~~in price contributed a $8.0 million~~ ~~positive~~immaterial negative impact.

For the three months ended ~~September~~June 30, ~~2017,~~2021, our NGL sales averaged ~~12.1~~21.8 MBbl/d. NGL sales volumes increased by ~~93%~~8 to ~~1,109~~1,987 MBbl for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to ~~574~~1,979 MBbl for the three months ended ~~September~~June 30, ~~2016.~~2020. The volume increase is primarily due to the completion of ~~172~~40 gross wells from ~~October~~July 1, ~~2016~~2020 to ~~September~~June 30, ~~2017,~~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 ~~$21.74~~$22.67 per Bbl for the three months ended ~~September~~June 30, ~~2017~~2021 compared to ~~$14.54~~$5.47 per Bbl for the three months ended ~~September~~June 30, ~~2016.~~2020, primarily due to an increase in pricing as compared to the three months ending June 30, 2020.

Lease operating ~~expenses.~~expenses (“LOE”). Our LOE ~~increased~~decreased by ~~$13.8~~$9.3 million to ~~$29.3~~$13.7 million for the three months ended ~~September~~June 30, ~~2017,~~2021, from ~~$15.5~~$23.0 million for the three months ended ~~September~~June 30, ~~2016. The increase in LOE was comprised of an increase in transportation and gathering (“T&G”) expense of $7.8 million~~2020. While oil revenue increased for the three months ended ~~September~~June 30, ~~2017 compared~~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, 2016 and an increase in operating expenses of $6.0 million for the three months ended September 30, 2017 compared to the three months ended September 30, 2016. The increase in LOE was primarily the result of an increase in producing wells and in both residue natural gas and NGL sales volumes and realized prices, resulting in collectively higher T&G fees.

2021. On a per unit basis, LOE decreased ~~from $5.81~~ to $1.97 per BOE sold for the three months ended ~~September~~June 30, ~~2016~~2021 from $2.76 per BOE for the three months ended June 30, 2020.

Transportation and gathering (“T&G”). Our T&G expense decreased by $4.7 million to ~~$5.06~~$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 ~~September~~June 30, ~~2017. The decrease in LOE~~2021 compared to $3.16 per BOE ~~is primarily a result of flush production on several new pads turned-in-line during~~sold for the three months ended ~~September~~June 30, ~~2017.~~2020.

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Production taxes. Our production taxes increased by ~~$10.1~~$6.2 million to ~~$16.3~~$10.9 million for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to ~~$6.2~~$4.7 million for the three months ended ~~September~~June 30, ~~2016.~~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 9.0%~~were 4.9% for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to ~~8.5%~~7.4% for the three months ended ~~September~~June 30, ~~2016. The increase in production taxes as a percentage of sales revenue relates to a change in the estimated tax rate for the three months ended September 30, 2017.~~2020.

Exploration and abandonment expenses. Our exploration and abandonment expenses were ~~$7.2~~$3.6 million for the three months ended ~~September~~June 30, 2017. We recognized $4.6 million in expense attributable to the extension of certain leases, $1.4 million attributable to exploratory geological and geophysical costs and $1.2 million in impairment expense attributable to the abandonment and impairment of unproved properties for the three months ended September 30, 2017.2021. For the three months ended ~~September~~June 30, ~~2016,~~2020, we recognized ~~$6.0~~$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.~~expense (“DD&A”). Our DD&A expense ~~increased~~ ~~$47.5~~decreased $32.5 million to ~~$94.2~~$50.1 million for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to ~~$46.7~~$82.6 million for the three months ended ~~September~~June 30, ~~2016. This increase is due to an increase in volumes sold for the three months ended September 30, 2017 as sales~~ ~~increased~~ ~~by approximately 3,122 MBoe.~~2020. On a per unit basis, DD&A expense decreased ~~from $17.53~~ to $7.18 per BOE for the three months ended ~~September~~June 30, ~~2016 to $16.29~~2021 from $9.93 per BOE for the three months ended ~~September~~June 30, ~~2017.~~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 $208.5 million of proved oil and gas properties that occurred during 2020.

General and administrative ~~expenses.~~expenses (“G&A”). General and administrative ~~(“G&A”)~~ expenses ~~increased~~decreased by ~~$8.6~~$14.2 million to ~~$28.7~~$10.9 million for the three months ended ~~September~~June 30, ~~2017~~2021 as compared to ~~$20.1~~$25.1 million for the three months ended ~~September~~June 30, ~~2016.~~2020. This ~~increase~~decrease is primarily due to ~~an increase~~reductions of workforce during 2020 and a decrease in ~~our employee head count and unit and stock-based compensation~~pre-petition advisory fees recognized for the three months ended ~~September~~June 30, ~~2017~~2020 compared to the three months ended ~~September~~June 30, ~~2016.~~2021. On a per unit basis, G&A expense decreased ~~from $7.54~~to $1.57 per BOE sold for the three months ended ~~September~~June 30, ~~2016 to $4.97~~2021 from $3.02 per BOE sold for the three months ended ~~September~~June 30, ~~2017.~~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~~non-cash expense for ~~unit and stock‑based~~stock-based compensation for equity awards granted to our employees and directors. For the three months ended ~~September~~June 30, ~~2017, stock‑based~~2021, there was $2.8 million of stock-based compensation expense. For the three months ended June 30, 2020, stock-based compensation expense was ~~$18.1~~$2.6 million.

Other operating expenses. Other operating expenses decreased by $7.8 million ~~as compared~~ to ~~unit-based compensation of $12.3~~$5.4 million for the three months ended ~~September~~June 30, ~~2016. The increase~~2021 as compared to $13.2 million for the three months ended June 30, 2020. This decrease is due primarily to ~~additional equity awards granted~~non-recurring early termination penalties of $11.9 million, which includes a $9.5 million early termination fee related to ~~employees as part~~the termination of our ~~2016 Long Term Incentive Plan that was adopted~~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 ~~October 2016 in connection with our IPO.~~merger and acquisition costs of $6.6 million.

Commodity derivative ~~gain (loss).~~loss. Primarily due to the increase in NYMEX crude oil ~~futures~~future prices at ~~September~~June 30, ~~2017~~2021 as compared to ~~June 30, 2017~~March 31, 2021 and change in fair value from the execution of new positions, we incurred a net loss on our commodity derivatives of ~~$37.9~~$75.8 million for the three months ended ~~September~~June 30, ~~2017.~~2021. Primarily due to the ~~decrease~~increase in NYMEX crude oil futures prices at ~~September~~June 30, ~~2016~~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, ~~2016~~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 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 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 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 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 ("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 futures prices at June 30, 2021 as compared to December 31, 2020 and change in fair value from the execution of new positions, we incurred a net ~~gain~~loss on our commodity derivatives of ~~$16.2~~$116.9 million for the ~~three~~combined six months ended ~~September~~June 30, ~~2016, including~~2021. Primarily due to the ~~amortization~~decrease in NYMEX crude oil futures prices at June 30, 2020 as compared to December 31, 2019 and change in fair value from the execution of ~~premiums.~~new positions and unwinds of existing positions, we incurred a net gain on our commodity derivatives of $193.7 million for the six months ended June 30, 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, ~~2017,~~2021, we paid commodity derivatives totaling $29.9 million. During the six months ended June 30, 2020, we received ~~cash~~ settlements of commodity derivatives totaling ~~$3.2~~$166.7 million. ~~During~~

Loss on deconsolidation of Elevation Midstream, LLC. On March 16, 2020, we deconsolidated Elevation Midstream, LLC. Upon deconsolidation, we elected the ~~three~~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 six months ended ~~September~~June 30, ~~2016,~~2020.

Reorganization items, net. Due to the commencement of the Chapter 11 Cases during the second quarter of 2020, we ~~received~~ ~~cash settlements~~have incurred significant costs associated with our reorganization, primarily from damages for rejected or settled contracts and legal and professional fees. For the combined six months ended June 30, 2021, we recognized a $873.9 million gain in reorganization items, net due to emergence from bankruptcy and a gain on settlement of ~~commodity derivatives totaling $4.8 million.~~liabilities subject to compromise. A loss from reorganization items of $26.9 million was recognized during the six months ended June 30, 2020.

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Interest expense. Interest expense consists of interest expense on our ~~long term~~long-term debt and amortization of ~~debt discount and~~ debt issuance costs, net of capitalized interest. For the ~~three~~combined six months ended ~~September~~June 30, ~~2017,~~2021, we recognized interest expense of ~~approximately $15.1~~$6.7 million as compared to ~~$31.2~~$41.7 million for the ~~three~~six months ended ~~September~~June 30, ~~2016,~~2020, as a result of borrowings under our ~~revolving credit facility, Second Lien Notes in 2016, our 2021~~RBL Credit Facility, DIP Credit Facility, Prior Credit Facility, 2024 Senior Notes, ~~our 2024~~2026 Senior Notes and the amortization of debt issuance ~~costs and debt discount.~~costs.

We incurred interest expense for the ~~three~~combined six months ended ~~September~~June 30, ~~2017~~2021 of ~~approximately $16.5~~ $5.9��million related to our ~~2021 Senior Notes, 2024 Senior Notes,~~RBL Credit Facility, Prior Credit Facility and ~~credit facility.~~DIP Credit Facility. We incurred interest expense for the ~~three~~six months ended ~~September~~June 30, ~~2016~~2020 of approximately ~~$12.2~~$42.5 million related to our ~~credit facility, Second Lien~~Prior Credit Facility and DIP Credit Facility, our 2024 Senior Notes, and our ~~2021~~2026 Senior Notes. Also included in interest expense for the ~~three~~combined six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~for the six months ended June 30, 2020 was the amortization of debt issuance costs ~~and debt discount~~ of ~~$1.5~~$1.0 million and ~~$15.9~~$3.2 million, respectively. For the ~~three~~combined six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016,~~for the six months ended June 30, 2020, we capitalized interest expense of ~~$2.9~~$0.2 million and ~~$1.2~~$4.0 million, respectively. ~~Also included in interest~~

Income tax expense. We recorded income tax expense of $28.1 million for the ~~three~~combined six months ended ~~September~~June 30, ~~2016 is a prepayment penalty of $4.3~~2021 and $2.2 million ~~related to the Company's repayment of its Second Lien Notes in July 2016.~~

~~Income tax benefit.~~ ~~We recorded an income tax benefit~~ for the ~~three~~six months ended ~~September~~June 30, ~~2017 of $17.1 million, resulting~~2020. This resulted in an effective tax rate of approximately ~~36.5%.~~19.9% and (0.8)% for the combined six months ended June 30, 2021 and for the six months ended June 30, 2020, respectively. Our effective tax ~~rate for 2017 differs~~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 estimated permanent taxable differences. For 2017, our combined federal and state statutory tax rate was 38.0%. For the three months ended September 30, 2016, we were not subject to U.S. federal income tax.valuation allowance.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

~~Oil sales revenues.~~ ~~Crude oil sales revenues~~ ~~increased~~ ~~by $133.7 million to $269.6 million for the nine months ended September 30, 2017 as compared to crude oil sales of $135.9 million for the nine months ended September 30, 2016. An~~ ~~increase~~ ~~in sales volumes between these periods contributed a $95.9 million~~ ~~positive~~ ~~impact, while an~~ ~~increase~~ ~~in crude oil prices contributed a $37.8 million~~ ~~positive~~ ~~impact.~~

~~For the nine months ended September 30, 2017, our crude oil sales averaged 23.8 MBbl/d. Our crude oil sales volume~~ ~~increased~~ 71% to 6,496 MBbl for the nine months ended September 30, 2017 compared to 3,808 MBbl for the nine months ended September 30, 2016. The volume increase is primarily due to an increase in production from the completion of 172 gross wells from October 1, 2016 to September 30, 2017, partially offset by the natural decline of our existing properties.

~~The average price we realized on the sale of crude oil was $41.50 per Bbl for the nine months ended September 30, 2017 compared to $35.68 per Bbl for the nine months ended September 30, 2016.~~

~~Natural gas sales revenues.~~ ~~Natural gas sales revenues~~ ~~increased~~ ~~by $35.4 million to $63.1 million for the nine months ended September 30, 2017 as compared to natural gas sales revenues of $27.7 million for the nine months ended September 30, 2016. An~~ ~~increase~~ ~~in sales volumes between these periods contributed an $19.1 million~~ ~~positive~~ ~~impact, while an~~ ~~increase~~ ~~in natural gas prices contributed a $16.3 million~~ ~~positive~~ ~~impact.~~

~~For the nine months ended September 30, 2017, our natural gas sales averaged 79.5 MMcf/d. Natural gas sales volumes~~ ~~increased~~ by 69% to 21,713 MMcf for the nine months ended September 30, 2017 as compared to 12,851 MMcf for the nine months ended September 30, 2016. The volume increase is primarily due to the completion of 172 gross wells from October 1, 2016 to September 30, 2017, partially offset by the natural decline on existing producing properties.

~~The average price we realized on the sale of our natural gas was $2.91 per Mcf for the nine months ended September 30, 2017 compared to $2.16 per Mcf for the nine months ended September 30, 2016.~~

~~NGL sales revenues.~~ ~~NGL sales revenues~~ ~~increased~~ ~~by $37.8 million to $57.6 million for the nine months ended September 30, 2017 as compared to NGL sales revenues of $19.8 million for the nine months ended September 30, 2016. An~~ ~~increase~~ ~~in sales volumes between these periods contributed a $16.3 million~~ ~~positive~~ ~~impact, while an~~ ~~increase~~ ~~in price contributed a $21.5 million~~ ~~positive~~ ~~impact.~~

~~For the nine months ended September 30, 2017, our NGL sales averaged 9.9 MBbl/d. NGL sales volumes~~ ~~increased~~ by 82% to 2,695 MBbl for the nine months ended September 30, 2017 as compared to 1,479 MBbl for the nine months ended September 30, 2016. The volume increase is primarily due to the completion of 172 gross wells from October 1, 2016 to September 30, 2017, 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 $21.36 per Bbl for the nine months ended September 30, 2017 compared to $13.37 per Bbl for the nine months ended September 30, 2016.~~

~~Lease operating expenses.~~ ~~Our LOE~~ ~~increased~~ by $35.0 million to $75.8 million for the nine months ended September 30, 2017, from $40.8 million for the nine months ended September 30, 2016. The increase in LOE was primarily the result of an increase in producing wells.

On a per unit basis, LOE increased from $5.49 per BOE sold for the nine months ended September 30, 2016 to $5.91 per BOE sold for the nine months ended September 30, 2017. The increase in LOE was comprised of an increase in T&G expense of $19.1 million for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 and an increase in operating expenses of $15.9 million for the nine months ended September 30, 2017 compared to the

nine months ended September 30, 2016. The increase in LOE was primarily the result of an increase in both residue natural gas and NGL sales volumes and realized prices, resulting in collectively higher T&G fees.

~~Production taxes.~~ ~~Our production taxes~~ ~~increased~~ by $16.4 million to $33.3 million for the nine months ended September 30, 2017 as compared to $16.9 million for the nine months ended September 30, 2016. 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 8.5% for the nine months ended September 30, 2017 as compared to 9.2% for the nine months ended September 30, 2016. The decrease in production taxes as a percentage of sales revenue relates to a change in the estimated tax rate for the nine months ended September 30, 2017.

~~Exploration expenses.~~ Our exploration expenses were $24.4 million for the nine months ended September 30, 2017. We recognized $16.9 million in expense attributable to the extension of certain leases, $1.4 million attributable to exploratory geological and geophysical costs and $5.7 million in impairment expense attributable to the abandonment and impairment of unproved properties for the nine months ended September 30, 2017. For the nine months ended September 30, 2016, we recognized $14.7 million in exploration expenses.

~~Depletion, depreciation, amortization and accretion expense.~~ ~~Our DD&A expense~~ ~~increased~~ $72.2 million to $213.5 million for the nine months ended September 30, 2017 as compared to $141.3 million for the nine months ended September 30, 2016. This increase is due to an increase in volumes sold for the nine months ended September 30, 2017 as sales ~~increased~~ by approximately 5,380 MBoe. On a per unit basis, DD&A expense decreased from $19.02 per BOE for the nine months ended September 30, 2016 to $16.67 per BOE for the nine months ended September 30, 2017.

~~Impairment of long lived assets.~~ Our impairment expense was $0.7 million for the nine months ended September 30, 2017. We recognized this expense when certain well equipment inventory was evaluated to have a net realizable value less than the associated carrying value, after it was determined to no longer be useful in our current drilling operations. We recognized $23.4 million of impairment expense for the nine months ended September 30, 2016. The impairment expense for the nine months ended September 30, 2016 is primarily related to impairment of the assets in our northern field. The future undiscounted cash flows did not exceed the carrying amount associated with the proved oil and gas properties in the northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties was impaired at September 30, 2016.

~~Other operating expenses.~~ Other operating expenses for the nine months ended September 30, 2017 is comprised of a $0.5 million loss on the sale of property and equipment. Other operating expenses for the nine months ended September 30, 2016 is comprised of a $0.9 million rig termination fee in January 2016.

~~General and administrative expenses.~~ ~~G&A expenses~~ ~~increased~~ by $42.7 million to $77.9 million for the nine months ended September 30, 2017 as compared to $35.2 million for the nine months ended September 30, 2016. This increase is primarily due to an increase in our employee head count and unit and stock-based compensation for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016. On a per unit basis, G&A expense increased from $4.74 per BOE sold for the nine months ended September 30, 2016 to $6.08 per BOE sold for the nine months ended September 30, 2017.

Our G&A expenses include the non-cash expense for unit and stock-based compensation for equity awards granted to our employees and directors. For the nine months ended September 30, 2017, stock-based compensation expense was $46.7 million as compared to unit-based compensation of $14.9 million for the nine months ended September 30, 2016. The increase is due to additional equity awards granted to employees as part of our 2016 Long Term Incentive Plan that was adopted in October 2016 in connection with our IPO.

~~Commodity derivative gain (loss).~~ ~~Primarily due to the decrease in NYMEX crude oil futures prices at September 30, 2017 as compared to December 31, 2016 and change in fair value from the execution of new positions, we incurred a net~~ ~~gain~~ on our commodity derivatives of $46.4 million for the nine months ended September 30, 2017. Primarily due to the increase in NYMEX crude oil futures prices at September 30, 2016 as compared to December 31, 2015 and change in fair value from the execution of new positions, we incurred a net ~~loss~~ on our commodity derivatives of $62.4 million for the nine months ended September 30, 2016, including the amortization of premiums. 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. 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, 2017, we~~ ~~paid~~ ~~cash settlements of commodity derivatives totaling $6.0 million. During the nine months ended September 30, 2016, we~~ ~~received~~ ~~cash settlements of commodity derivatives totaling $37.9 million.~~

~~Interest expense.~~ Interest expense consists of interest expense on our long term debt, amortization of debt discount and debt issuance costs, net of capitalized interest. For the nine months ended September 30, 2017, we recognized interest expense of approximately $33.8 million as compared to $57.9 million for the nine months ended September 30, 2016, as a result of borrowings under our revolving credit facility, Second Lien Notes in 2016, our 2021 Senior Notes, our 2024 Senior Notes and the amortization of debt issuance costs and debt discount.

We incurred interest expense for the nine months ended September 30, 2017 of approximately $39.2 million related to our 2024 Senior Notes, 2021 Senior Notes and credit facility. We incurred interest expense for the nine months ended September 30, 2016 of approximately $38.9 million related to our Second Lien Notes, our 2021 Senior Notes and credit facility. Also included in interest expense for the nine months ended September 30, 2017 and 2016 was the amortization of debt issuance costs and debt discount of $3.2 million and $18.3 million, respectively. For the nine months ended September 30, 2017 and 2016, we capitalized interest expense of $8.6 million and $3.6 million, respectively. Also included in interest expense for the nine months ended September 30, 2016 is a prepayment penalty of $4.3 million related to the Company's repayment of its Second Lien Notes in July 2016.

~~Income tax benefit.~~ We recorded an income tax benefit for the nine months ended September 30, 2017 of $7.6 million, resulting in effective tax rate of approximately 35.3%. Our effective tax rate for 2017 differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes and estimated permanent taxable differences. For 2017, our combined federal and state statutory tax rate was 38.0%. For the nine months ended September 30, 2016, we were not subject to U.S. federal income tax.

Liquidity and Capital Resources

~~Our primary sources~~Sources of ~~liquidity~~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 resources are cash flows generated by operating activities and borrowings under our revolving credit facility. Depending upon market conditions and other factors, we may also issue equity and debt securities if needed.structure following emergence from bankruptcy on January 20, 2021.

Historically, our primary sources of liquidity have been borrowings under our ~~revolving~~ credit ~~facility, our Second Lien Notes,~~facilities, proceeds from ~~the~~securities offerings ~~of our 2021 Senior Notes~~ and ~~2024 Senior Notes (please refer to~~ ~~Note 4 – Long Term Debt), equity provided by investors, including our management team,~~cash proceeds from ~~the IPO and a private placement~~divestitures of our ~~common stock and cash flows from operations. To date, our primary use of capital has been for the acquisition of~~ oil and gas properties ~~to increase~~and from the sale of oil, gas and NGL production. During the combined six months ended June 30, 2021, our ~~acreage position, as well as~~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 repayment of borrowings on the RBL Credit Facility and development ~~and exploration~~ of our oil and gas properties.

As of June 30, 2021, our outstanding RBL Credit Facility borrowings were $90.0 million. Our ~~borrowings, net~~total available liquidity as of ~~unamortized debt discount~~June 30, 2021 consisted of cash and ~~debt issuance costs, were approximately $932.6~~cash equivalents of $34.4 million and ~~$538.1~~$409.5 million ~~at September 30, 2017, and December 31, 2016, respectively. We also have other contractual commitments, which are described in~~ ~~Note 11 – Commitments and Contingencies~~ ~~in Part I, Item I, Financial Information~~of availability on the RBL Credit Facility. As of the date of this ~~Quarterly Report~~.filing, we had drawn $70.0 million on the RBL Credit Facility and 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 we have sufficient sources of cash to meet our obligations for the 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 which we previously entered. 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.

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 our vendors.

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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 ~~times~~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 ~~on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 50% to 80% of~~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 ~~projected oil production over a one‑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.~~

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and available borrowings under our revolving credit facility to execute our current capital program, excluding any acquisitions we may consummate, make our interest payments on the 2021 Senior Notes and 2024 Senior Notes and pay dividends on our Series A Preferred Stock.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

~~Our initial 2017 capital budget was approximately $795 million to $935 million, substantially all of which we intend to allocate~~minimum financial commitments pursuant to the ~~Core DJ Basin. We intend~~terms of these contracts, however our actual expenditures under these contracts may exceed the minimum commitments presented above. Refer to ~~allocate approximately $675 million to $775 million of our 2017 capital budget~~Note 7—Leases to the ~~drilling~~Company’s consolidated financial statements in its Annual Report for more information.

Table of 185 to 190 gross operated wells and the completion of 190 to 195 gross operated wells, approximately $60 to $80 million of non-operated drilling and completion, and approximately $60 million to $80 million to undeveloped leasehold acquisitions, midstream, and other capital expenditures. We are currently running a three rig program and plan to remain with a three rig program throughout 2017.Contents

Cash Flows

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


	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
Net cash provided by operating activities	$	141,769	$	15,346	$	83,954
Net cash used in investing activities	(41,173)		(9,120)		(191,413)
Net cash provided by (used in) financing activities	(176,831)		(101,454)		145,358

For the Nine Months Ended
September 30,
2017 2016
Net cash provided by operating activities $ 141,736
$ 97,563
Net cash used in investing activities $ (995,062 ) $ (280,546 )
Net cash provided by financing activities $ 378,729
$ 87,263

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

Net cash provided by operating ~~activities.~~ ~~For the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, our net~~activities

Net cash provided by operating activities ~~increased by $44.2 million, primarily due to an increase in operating revenues, net of expenses, of $148.3 million from~~ ~~increased~~ ~~sales volumes and prices and a decrease in cash due to changes in current assets and liabilities of $52.7 million~~ for the ~~nine months ended September 30, 2017 compared~~2021 Successor period consisted primarily of cash receipts and disbursements attributable to ~~September 30, 2016. Offsetting these increases~~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 Company’s bankruptcy and subsequent emergence. Net cash provided by operating activities for the 2020 Predecessor period was ~~a decrease in~~primarily comprised of settlements on commodity derivatives of ~~$51.9~~$65.4 million and collections on accounts receivable related to oil, natural gas and NGLs of $56.8 million.

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

For the ~~nine~~combined six months ended ~~September~~June 30, ~~2017 as compared to the nine months ended September 30, 2016, our~~2021, net cash used in investing activities ~~increased~~decreased by ~~$714.5~~$141.1 million compared to the six months ended June 30, 2020 primarily ~~due to an increase~~as a result of ~~$798.8~~$129.1 million ~~used~~less spent on oil and gas property additions, $10.0 million less spent on our investment in ~~acquisitions, drilling and completion activities and~~unconsolidated subsidiaries, $2.5 million less spent on other property and equipment ~~for~~and an increase in proceeds from the ~~nine months ended September 30, 2017 as compared~~sale of assets of $9.1 million, partially offset by an increase of $5.5 million spent on the acquisition of properties in the current period and a decrease of $4.2 million from the prior period to the ~~nine months ended September 30, 2016. Offsetting this increase was~~current period in the ~~change in cash held in escrow~~return of ~~$84.2 million.~~capital from gathering systems.

Net cash provided by ~~financing activities.~~ ~~For the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, our net cash provided by~~(used in) financing activities ~~increased~~

Net cash used in financing activities for the 2021 Successor period consisted primarily of net repayments under our RBL Credit Facility in the amount of $183.7 million partially offset by ~~$291.5~~$7.0 million ~~as a result~~ of ~~an increase of $419.9 million~~proceeds from the issuance of ~~debt~~common stock. We drew $145.5 million, net on our Prior Credit Facility and ~~a reduction~~DIP Credit Facility during the six months 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 ~~expenditures for~~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. The increase from the issuance of debt is primarily due to the August 2017 issuance of our 2024 Senior Notes for net proceeds of $392.6 million. Additionally, for the nine months ended September 30, 2017 compared to September 30, 2016 our net cash provided bycosts and other financing activities decreased by $120.8 million related to the issuance of units during the nine months ended September 30, 2016 and $7.7 million related to dividend payments on our Series A Preferred Stock during the nine months ended September 30, 2017.fees.

Working Capital

Working capital is defined as total current assets less total current liabilities. Our working capital deficit was ~~$8.6~~$232.5 million and $369.4 million at ~~September~~June 30, ~~2017. Our working capital was $379.1 million at December 31, 2016. Our cash balances totaled $114.1 million and $588.7 million at September 30, 2017~~2021 and December 31, ~~2016,~~2020, respectively. However, as of December 31, 2020, our current liabilities in the amount of $279.6 million were classified as “Liabilities Subject to Compromise” (excluding approximately $1.8 billion of debt, accrued interest, damages for rejected and settled contracts and other). Our cash and cash equivalents totaled $34.4 million and $205.9 million at June 30, 2021 and December 31, 2020, respectively.

Table of Contents

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 ~~revolving credit facility~~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.

Debt Arrangements

~~Our revolving credit facility has a maximum credit amount of $1.5 billion, subject to a borrowing base, and all~~For details of our current and future subsidiaries are guarantors under such facility. Amounts repaid under our revolving credit facility may be re-borrowed from time to time, subject to the terms of the facility. For more information on the revolving credit facility,RBL Credit Facility, please see Note ~~4 —~~ 4—Long-Term Debt in ~~Part~~Item 1 ~~Item 1. Financial Information~~ of this Quarterly Report. ~~The revolving credit facility is secured by liens on substantially all~~

Equity Arrangements

For details of our ~~properties.~~equity arrangements, please see Note 10—Equity in Item 1 of this Quarterly Report.

In July 2016, we closed a private offering of our unsecured 7.875% Senior Notes due 2021 that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bear interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes is payable on January 15 and July 15 of each year, and the first interest payment was made on January 15, 2017. Our 2021 Senior Notes will mature on July 15, 2021. Our 2021 Senior Notes are guaranteed by all of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes).

In August 2017, we closed a private offering of our unsecured 7.375% Senior Notes due 2024 that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year commencing on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024. Our 2024 Senior Notes are guaranteed by all of our current and future restricted subsidiaries.

~~Revolving Credit Facility~~

The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually on August 1, 2017 and each May 1 and November 1 thereafter, and will depend on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under our revolving credit facility. As of September 30, 2017, the borrowing base was $375.0 million, and there were no borrowings outstanding under our revolving credit facility. In October 2017, the Company completed the August 1, 2017 borrowing base redetermination. As a result of the redetermination, the borrowing base increased to $525.0 million.

Principal amounts borrowed will be payable on the maturity date, and interest will be payable quarterly for alternate base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the product of: (a) the LIBOR rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the reserve percentages (expressed as a decimal) on such date at which the administrative agent under our revolving credit facility is required to maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 200 to 300 basis points, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the adjusted one-month LIBOR rate (as calculated above) plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the percentage of our borrowing base utilized. As of September 30, 2017, we had no outstanding borrowings under our revolving credit facility. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

The revolving credit facility is secured by liens on substantially all of our properties and guarantees from us and our current and future subsidiaries. The revolving credit facility contains restrictive covenants that may limit our ability to, among other things:

~~incur additional indebtedness;~~

~~sell assets;~~

~~make loans to others;~~

~~make investments;~~

~~make certain changes to our capital structure;~~

~~make or declare dividends;~~

~~hedge future production or interest rates;~~

~~enter into transactions with our affiliates;~~

~~holding cash balances in excess of certain thresholds while carrying a balance of our revolving credit facility;~~

~~incur liens; and~~

~~engage in certain other transactions without the prior consent of the lenders.~~

~~The revolving credit facility requires us to maintain the following financial ratios:~~

a current ratio, which is the ratio of our consolidated current assets (includes unused commitments under our revolving credit facility and unrestricted cash and excludes derivative assets) to our consolidated current liabilities (excludes obligations under our revolving credit facility, the senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and

a net leverage ratio, which is the ratio of (i) consolidated debt less cash balances to (ii) our consolidated EBITDAX for the four fiscal quarter period most recently ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter; provided that (a) for the quarter ended September 30, 2017, consolidated EBITDAX will be based on the last six months’ consolidated EBITDAX multiplied by 2, (b) for the quarter ending December 31, 2017, consolidated EBITDAX will be based on the last nine months' consolidated EBITDAX multiplied by 4/3, and (c) for the quarters ending on or after March 31, 2018, consolidated EBITDAX will be based on the last twelve months’ consolidated EBITDAX.

In August 2017, we amended and restated the revolving credit facility to, among other things, (i) increase the total aggregate commitment to $1.5 billion, subject to an initial borrowing base of $375.0 million, and (ii) increase the letter of credit sublimit to $50.0 million. The revolving credit facility matures on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted into common equity or redeemed prior to April 15, 2021, 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 (d) the earlier termination in whole of the commitments.

In October 2017, we amended the revolving credit facility to, among other things, (i) provide for the joinder of new lenders, (ii) increase the borrowing base under the credit facility from $375.0 million to $525.0 million, and (iii) amend certain provisions of the credit agreement, including the commitments and allocations of each lender.

~~2021 Senior Notes~~

In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bear interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes is payable on January 15 and July 15 of each year, and the first interest payment was made on January 15, 2017. Our 2021 Senior Notes will mature on July 15, 2021.

We may, at our option, redeem all or a portion of our 2021 Senior Notes at any time on or after July 15, 2018. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2021 Senior Notes before July 15, 2018, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.875% of the principal amount of our 2021 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to July 15, 2018, we may redeem some or all of our 2021 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2021 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.

Our 2021 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2021 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes) that guarantees our indebtedness under a credit facility. The notes are effectively

subordinated to all of our secured indebtedness (including all borrowings and other obligations under our revolving 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 future subsidiaries that do not guarantee the notes.

~~2024 Senior Notes~~

In August 2017, we closed a private offering of our 2024 Senior Notes that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year, and the first interest payment will be due on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024.

We may, at our option, redeem all or a portion of our 2024 Senior Notes at any time on or after May 15, 2020 at the redemption prices set forth in the indenture governing the 2024 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2024 Senior Notes before May 15, 2020, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of our 2024 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to May 15, 2020, we may redeem some or all of our 2024 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2024 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.

Our 2024 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that guarantees our indebtedness under a credit facility. The notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our revolving 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 our future subsidiaries that do not guarantee the notes.

~~Series A Preferred Stock~~

The Company's Series A Preferred Stock (the "Series A Preferred Stock") are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are partially paid in cash). Each of 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, we may elect to convert each share of Series A Preferred Stock at a conversion ratio of 61.9195, but only if the closing price of our common stock trades at or above a certain premium to our initial offering price, with such premiums decreasing with time. 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. For more information, see the Company’s Annual 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, 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, 2016.~~Report.

Recent Accounting Pronouncements

~~In May 2017, the Financial~~Please see Note 2—Basis of Presentation, Significant Accounting ~~Standards Board (“FASB”) issued~~Policies and Recent Accounting ~~Standards Update (“ASU”) No. 2017-09, which provides clarification and reduces both (1) diversity~~ Pronouncements in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal years beginning after December 15, 2016, including the interim reporting periods within that fiscal year. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements.

In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after JanuaryItem 1 ~~2017. The Company is currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures.~~

In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in the financial statements that have been issued. The Company is currently evaluating this ASU and believes it could have a material impact to its financial statements and related disclosures.

In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-06, which clarifies the requirements to assess whether an embedded put or call option is clearly and closely related to the debt host, solely in accordance with the four step decision sequence in FASB ASB Topic 815, Derivatives and Hedging, as amended by this ASU. This standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and should be applied using a modified retrospective approach. The Company adopted this ASU in the first quarter of 2017 and the adoption of this ~~ASU did not have~~Quarterly Report for a ~~material impact on the its consolidated financial statements.~~detailed list of recent accounting pronouncements.

flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. In September 2017, the FASB issued ASU No. 2017-13, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on its financial statements and related disclosures and developing a strategy for implementation.

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 ~~decline~~declining commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the ~~years~~six months ended ~~December 31, 2014 and 2015,~~June 30, 2020, commodity prices ~~decreased, while during~~decreased. During the ~~year~~combined six months ended ~~December 31, 2016,~~June 30, 2021, commodity prices increased ~~and remained stable during~~compared to the ~~nine months ended September 30, 2017.~~same period in 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 June 30, 2021, we did not have material off-balance sheet arrangements.

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.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 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 prices at targeted levels and to manage our exposure to oil price fluctuations.

~~The following tables present our derivative positions related to crude oil and natural gas sales in effect as of September 30, 2017:~~

December 31,
2017

March 31,
2018

June 30,
2018

September 30,
2018

December 31,
2018

March 31,
2019

June 30,
2019
NYMEX WTI⁽¹⁾ Crude Swaps:

Notional volume (Bbl) 1,850,000
1,500,000
1,500,000
1,050,000
1,050,000
—
—
Weighted average fixed price ($/Bbl) $ 50.64
$ 50.70
$ 50.70
$ 52.91
$ 52.91

NYMEX WTI⁽¹⁾ Crude Sold Calls:

Notional volume (Bbl) 1,200,000
1,735,000
1,335,000
1,560,000
1,560,000
1,500,000
1,500,000
Weighted average fixed price ($/Bbl) $ 53.04
$ 55.60
$ 56.22
$ 55.63
$ 55.63
$ 55.10
$ 55.10
NYMEX WTI⁽¹⁾ Crude Sold Puts:

Notional volume (Bbl) 3,225,000
3,269,400
3,269,400
2,400,000
2,400,000
1,500,000
1,500,000
Weighted average purchased put price ($/Bbl) $ 37.19
$ 38.14
$ 38.14
$ 40.00
$ 40.00
$ 39.70
$ 39.70
NYMEX WTI⁽¹⁾ Crude Purchased Calls:

Notional volume (Bbl) 450,000
285,000
285,000
210,000
210,000
—
—
Weighted average fixed price ($/Bbl) $ 61.65
$ 60.69
$ 60.69
$ 59.69
$ 59.69

NYMEX WTI⁽¹⁾ Crude Purchased Puts:

Notional volume (Bbl) 1,800,000
2,219,400
1,919,400
1,350,000
1,350,000
1,500,000
1,500,000
Weighted average purchased put price ($/Bbl) $ 42.13
$ 46.15
$ 45.71
$ 49.51
$ 49.51
$ 49.37
$ 49.37
NYMEX HH⁽²⁾ Natural Gas Swaps:

Notional volume (MMBtu) 7,420,000
10,500,000
9,300,000
8,700,000
8,700,000
—
—
Weighted average fixed price ($/MMBtu) $ 3.06
$ 3.30
$ 3.03
$ 3.03
$ 3.03

NYMEX HH⁽²⁾ Natural Gas Sold Calls:

Notional volume (MMBtu) —
600,000
600,000
600,000
600,000
—
—
Weighted average sold call price ($/MMBtu) $ 3.15
$ 3.15
$ 3.15
$ 3.15

NYMEX HH⁽²⁾ Natural Gas Purchased Puts:

Notional volume (MMBtu) —
600,000
600,000
600,000
600,000
—
—
Weighted average purchased put price ($/MMBtu) $ 3.00
$ 3.00
$ 3.00
$ 3.00

CIG⁽³⁾ Basis Gas Swaps:

Notional volume (MMBtu) 5,215,000
6,300,000
—
—
—
—
—
Weighted average fixed basis price ($/MMBtu) $ (0.31 ) $ (0.31 )


~~(1)~~	~~NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange~~


~~(2)~~	~~NYMEX HH refers to the Henry Hub natural gas price on the New York Mercantile Exchange~~


~~(3)~~	~~CIG refers to the NYMEX HH settlement price less the fixed basis price, the Rocky Mountains (CIGC) settlement price.~~

As of September 30, 2017, the fair market value of our oil derivative contracts was a net liability of $12.9 million. Based on our open oil derivative positions at September 30, 2017, a 10% increase in the NYMEX WTI price would increase our net oil derivative liability by approximately $69.9 million, while a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $60.7 million. As of September 30, 2017, the fair market value of our natural gas derivative contracts was a net asset of $2.6 million. Based upon our open commodity derivative positions at September 30, 2017, a 10% increase in the NYMEX Henry Hub price would decrease our net natural gas derivative asset by approximately $13.6 million, while a 10% decrease in the NYMEX Henry Hub price would increase our net natural gas derivate asset by approximately $13.6 million. Please see “—How We Evaluate Our Operations—Derivative Arrangements.”

~~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 which can be predicted with certainty. For the nine months ended September 30, 2017, 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, 2017, we had commodity derivative contracts with six 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. Three of the six counterparties to the derivative instruments are highly rated entities with corporate ratings at A3 classifications or above by Moody’s. The other three counterparties had a corporate rating of Baa1 by Moody’s. For the three and nine months ended September 30, 2017 and 2016, we did not incur any losses with respect to counterparty contracts. None of our existing derivative instrument contracts contains credit risk related contingent features.

~~Interest Rate Risk~~

At September 30, 2017, we had no variable rate debt outstanding. Assuming we had the full amount of variable-rate debt outstanding available to us at September 30, 2017 of $375.0 million, the impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $3.8 million. 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.”

~~Off‑Balance Sheet Arrangements~~

As of September 30, 2017, we did not have any off-balance sheet arrangements other than operating leases, contractual commitments for drilling rigs, gathering commitments, and acquisitions of undeveloped leasehold acreage. Additionally, our oil marketer is subject to a firm transportation agreement with a make-whole provision that allows us to satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2018. Please see ~~Note 11 – Commitments and Contingencies~~ ~~in Part 1, Item 1 of this Quarterly Report.~~

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

~~As required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and~~

Our management, with the participation of ~~management, including~~ our principal executive officer and principal financial officer, evaluated the effectiveness ~~of the design and operation~~ of our disclosure controls and procedures ~~(as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed~~ to ~~provide reasonable assurance~~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,

Table of Contents

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 and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.~~disclosure. Based upon that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2017.~~2021.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended ~~September~~June 30, ~~2017~~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 be found in Note ~~11 –~~ 12—Commitments and ~~Contingencies, to our condensed consolidated financial statements included elsewhere~~Contingencies—Litigation and Legal Items in ~~this report.~~

We are currently in discussions with the Colorado Department of Public Health and Environment (“CDPHE”) regarding a Compliance Advisory issued to us in July 2015, which alleged air quality violations at three of our facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. We continue to work with the CDPHE on its investigation into our facilities and it intends to seek a field-wide administrative settlement of these issues. At this time, we anticipate the remediation and compliance costs that this matter may impose upon us to be an immaterial amount.

~~From time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing date~~Item 1 of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.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 ~~under~~in Item 1A ~~“Risk Factors”, included~~of the Company’s Annual Report. The risks described in our ~~Annual Report.~~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.

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

~~None.~~Not applicable.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.OTHER INFORMATION

None.

Table of Contents

ITEM 6.EXHIBITS


~~(a)~~	~~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.

Table of Contents

INDEX TO EXHIBITS

Exhibit
~~Number~~ #

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).

~~4.1~~

10.1

~~Indenture,~~Amendment No. 2 to Credit Agreement, dated ~~August 1, 2017,~~May 6, 2021, by and among ~~Extraction Oil & Gas, Inc.,~~ the Company, as borrower, certain subsidiaries of the Company, as guarantors, the lenders party thereto and Wells Fargo Bank, National Association, as ~~trustee (incorporated by reference to Exhibit 4.1 to~~administrative agent for the ~~Company’s Current Report on Form 8-K (File No. 001-37907) filed with the Commission on August 3, 2017).~~Lenders and as issuing lender.

~~4.2~~

10.2

~~Second Supplemental Indenture,~~Voting Agreement, dated ~~December 22, 2016~~as of May 9, 2021, by and among Bonanza Creek Energy, Inc., Extraction Oil & Gas, Inc.~~, Extraction Finance Corp., the guarantors party thereto~~ and ~~Wells Fargo Bank, National Association, as trustee.~~

~~4.3~~

Third Supplemental Indenture, dated June 29, 2017 by and among Extraction Oil & Gas, Inc., Extraction Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee.

*10.1

~~Amendment No. 12 to the Credit Agreement, dated as of May 5, 2017, by and among Extraction Oil & Gas, Inc., as borrower, certain subsidiaries of the~~Kimmeridge Energy Management Company, ~~as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto.~~LLC

~~10.2~~

Amended and Restated Credit Agreement, dated as of August 16, 2017, by and between Extraction Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent and issuing lender, and the lenders party thereto (incorporated(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 ~~August 21, 2017)~~May 10, 2021).

10.3

~~Increase Agreement, Joinder and~~ Amendment No. 13 to ~~Amended and Restated~~ Credit Agreement, dated ~~as of October 11, 2017,~~May 28, 2021, by and ~~between Extraction Oil & Gas, Inc.,~~among the Company, as borrower, certain subsidiaries of the Company, as guarantors, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent for the Lenders and as issuing lender ~~and the lenders party thereto (incorporated~~(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 ~~October 13, 2017)~~June 1 , 2021).

*31.1

10.4

Amended and Restated Voting Agreement, dated as of June 6, 2021 and effective 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 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.

* Filed herewith.

Table of Contents

** Furnished herewith.

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 7, 2017.~~

August 9, 2021


	Extraction Oil & Gas, Inc.

	~~Extraction Oil & Gas, Inc.~~By:	/s/ Thomas B. Tyree Jr.
		Thomas B. Tyree Jr.
	~~By:~~	~~/S/ MARK A. ERICKSON~~
~~Mark A. Erickson~~
~~Chairman and~~ Chief Executive Officer ~~(principal executive officer)~~

						(Principal Executive Officer)

			By:			/~~S/ RUSSELL T. KELLEY, JR.~~s/ Marianella Foschi
						~~Russell T. Kelley, Jr.~~Marianella Foschi
						Chief Financial Officer
						(~~principal financial officer)~~Principal Financial Officer)

			By:			/s/ Tom L. Brock
						Tom L. Brock
						Chief Accounting Officer
						(Principal Accounting Officer)



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

370 17^th17th Street ~~Suite 5300~~ ~~Denver, Colorado~~		~~80202~~
Suite 5200
Denver,	Colorado	80202
(Address of principal executive offices)		(Zip Code)


					Page
PART I—FINANCIAL INFORMATION

				~~Page~~
~~PART I—FINANCIAL INFORMATION~~

Item 1.	Condensed Consolidated Financial Statements (Unaudited)			42
			Condensed Consolidated Balance Sheets ~~as of September 30, 2017 and December 31, 2016~~		42
			Condensed Consolidated Statements of Operations ~~for the three and nine months ended September 30, 2017 and 2016~~		53
			~~Condensed Consolidated Statement of Changes in Stockholders’ Equity for the nine months ended September 30, 2017~~		6
	Condensed Consolidated Statements of Cash Flows ~~for the nine months ended September 30, 2017 and 2016~~	75
			Condensed Consolidated Statements of Changes in Stockholders’ Equity		6
			Notes to the Unaudited Condensed Consolidated Financial Statements		87
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations		2732
Item 3.			Quantitative and Qualitative Disclosures about Market Risk		5058
Item 4.			Controls and Procedures		5358

PART II—OTHER INFORMATION

Item 1.			Legal Proceedings		5459
Item 1A.			Risk Factors		5459
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds		5459
Item 3.			Defaults upon Senior Securities		5459
Item 4.			Mine Safety Disclosures		5459
Item 5.			Other Information		5459
Item 6.			Exhibits		5461
			Signatures		5662



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



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



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



	September 30, 2017			December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	114,139		$	588,736
Accounts receivable
Trade	52,638			23,154
Oil, natural gas and NGL sales	70,425			34,066
Inventory and prepaid expenses	13,262			7,722
Commodity derivative asset	986			—
Total Current Assets	251,450			653,678
Property and Equipment (successful efforts method), at cost:
Proved oil and gas properties	2,683,062			1,851,052
Unproved oil and gas properties	639,867			452,577
Wells in progress	130,668			98,747
Less: accumulated depletion, depreciation and amortization	(610,390		)	(402,912		)
Net oil and gas properties	2,843,207			1,999,464
Other property and equipment, net of accumulated depreciation	26,866			32,721
Net Property and Equipment	2,870,073			2,032,185
Non-Current Assets:
Cash held in escrow	—			42,200
Goodwill and other intangible assets, net of accumulated amortization	54,966			54,489
Other non-current assets	11,611			2,224
Total Non-Current Assets	66,577			98,913
Total Assets	$	3,188,100		$	2,784,776
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	151,940		$	131,134
Revenue payable	41,209			35,162
Production taxes payable	39,556			27,327
Commodity derivative liability	8,259			56,003
Accrued interest payable	14,068			19,621
Asset retirement obligations	4,998			5,300
Total Current Liabilities	260,030			274,547
Non-Current Liabilities:
Senior Notes, net of unamortized debt issuance costs	932,570			538,141
Production taxes payable	37,138			35,838
Commodity derivative liability	3,025			6,738
Other non-current liabilities	6,038			3,466
Asset retirement obligations	60,193			50,808
Deferred tax liability	98,470			106,026
Total Non-Current Liabilities	1,137,434			741,017
Total Liabilities	1,397,464			1,015,564
Commitments and Contingencies—Note 11
Series A Convertible Preferred Stock, $0.01 par value; 50,000,000 shares authorized; 185,280 issued and outstanding	156,995			153,139
Stockholders' Equity:
Common stock, $0.01 par value; 900,000,000 shares authorized; 171,893,157 and 171,834,605 issued and outstanding	1,718			1,718
Additional paid-in capital	2,101,103			2,067,590
Treasury stock, at cost, 165,385 and 0 shares	(2,105		)	—
Accumulated deficit	(467,075		)	(453,235		)
Total Stockholders' Equity	1,633,641			1,616,073
Total Liabilities and Stockholders' Equity	$	3,188,100		$	2,784,776



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues:
Oil sales	$	132,075		$	51,760		$	269,597		$	135,896
Natural gas sales	24,672			12,792			63,095			27,730
NGL sales	24,114			8,350			57,574			19,773
Total Revenues	180,861			72,902			390,266			183,399
Operating Expenses:
Lease operating expenses	29,267			15,480			75,755			40,819
Production taxes	16,290			6,186			33,254			16,935
Exploration expenses	7,181			5,985			24,431			14,735
Depletion, depreciation, amortization and accretion	94,220			46,680			213,483			141,317
Impairment of long lived assets	—			467			675			23,350
Other operating expenses	—			—			451			891
Acquisition transaction expenses	—			345			68			345
General and administrative expenses	28,741			20,071			77,916			35,189
Total Operating Expenses	175,699			95,214			426,033			273,581
Operating Income (Loss)	5,162			(22,312		)	(35,767		)	(90,182		)
Other Income (Expense):
Commodity derivatives gain (loss)	(37,875		)	16,225			46,423			(62,424		)
Interest expense	(15,080		)	(31,216		)	(33,761		)	(57,914		)
Other income	891			36			1,709			120
Total Other Income (Expense)	(52,064		)	(14,955		)	14,371			(120,218		)
Loss Before Income Taxes	(46,902		)	(37,267		)	(21,396		)	(210,400		)
Income tax benefit	(17,106		)	—			(7,556		)	—
Net Loss	$	(29,796	)	$	(37,267	)	$	(13,840	)	$	(210,400	)
Loss Per Common Share (Note 10)
Basic and diluted	$	(0.20	)				$	(0.15	)
Weighted Average Common Shares Outstanding
Basic and diluted	171,845						171,838



Purchase Price	June 8, 2017
Consideration given
Cash	$	13,395
Total consideration given	$	13,395
Allocation of Purchase Price
Proved oil and gas properties	$	13,495
Total fair value of oil and gas properties acquired	$	13,495
Asset retirement obligations	$	(100	)
Fair value of net assets acquired	$	13,395



Purchase Price	October 3, 2016
Consideration given
Cash	$	405,335
Total consideration given	$	405,335
Allocation of Purchase Price
Proved oil and gas properties	$	252,522
Unproved oil and gas properties	109,800
Total fair value of oil and gas properties acquired	$	362,322
Goodwill ⁽¹⁾	$	54,220
Working capital	(7,185		)
Asset retirement obligations	(4,022		)
Fair value of net assets acquired	$	405,335
Working capital acquired was estimated as follows:
Accounts receivable	$	955
Revenue payable	(3,012		)
Production taxes payable	(4,244		)
Accrued liabilities	(884		)
Total working capital	$	(7,185	)



Purchase Price	August 23, 2016
Consideration given
Cash	$	17,504
Total consideration given	$	17,504
Allocation of Purchase Price
Proved oil and gas properties	$	12,362
Unproved oil and gas properties	8,566
Total fair value of oil and gas properties acquired	$	20,928
Working capital	$	(9	)
Asset retirement obligations	(3,415		)
Fair value of net assets acquired	$	17,504
Working capital acquired was estimated as follows:
Production taxes payable	$	(9	)
Total working capital	$	(9	)



	September 30, 2017			December 31, 2016
Credit facility due August 16, 2022 (or an earlier time as set forth in the credit facility)	$	—		$	—
2021 Senior Notes due July 15, 2021	550,000			550,000
2024 Senior Notes due May 15, 2024	400,000			—
Unamortized debt issuance costs on Senior Notes	(17,430		)	(11,859		)
Total long-term debt	932,570			538,141
Less: current portion of long-term debt	—			—
Total long-term debt, net of current portion	$	932,570		$	538,141



	As of December 31, 2016
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	$	12,620		$	(12,620	)	$	—		$	—	$	—
Non-current assets	$	14,993		$	(14,993	)	$	—		$	—	$	—
Current liabilities	$	(68,623	)	$	12,620		$	(56,003	)	$	—	$	(62,741	)
Non-current liabilities	$	(21,731	)	$	14,993		$	(6,738	)	$	—	$	—



	For the Nine Months Ended September 30, 2017			For the Year Ended December 31, 2016
Balance beginning of period	$	56,108		$	44,367
Liabilities incurred or acquired	6,644			8,945
Liabilities settled	(1,408		)	(1,155		)
Revisions in estimated cash flows	—			(1,695		)
Accretion expense	3,847			5,646
Balance end of period	$	65,191		$	56,108



	At September 30, 2017				At December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2021 Senior Notes⁽¹⁾	$	539,804	$	580,250	$	538,141	$	588,500
2024 Senior Notes⁽²⁾	$	392,766	$	419,000	$	—	$	—



	Number of Options	Weighted Average Exercise Price
Non-vested Stock Options at January 1, 2017	4,500,000	$	19.00
Granted	—	$	—
Forfeited	—	$	—
Vested	—	$	—
Non-vested Stock Options at September 30, 2017	4,500,000	$	19.00



	Number of Shares	Weighted Average Grant Date Fair Value
Non-vested Incentive RSUs at January 1, 2017	2,714,368	$	20.45
Granted	—	$	—
Forfeited	(703,868)	$	20.45
Vested	(507,200)	$	20.45
Non-vested Incentive RSUs at September 30, 2017	1,503,300	$	20.45



	For the Three Months Ended September 30, 2017			For the Nine Months Ended September 30, 2017
Basic and Diluted Loss Per Share
Net Loss	$	(29,796	)	$	(13,840	)
Less: Adjustment to reflect Series A Preferred Stock dividend	(2,721		)	(8,164		)
Less: Adjustment to reflect accretion of Series A Preferred Stock discount	(1,365		)	(3,992		)
Adjusted net loss available to common shareholders, basic and diluted	$	(33,882	)	$	(25,996	)
Denominator:
Weighted average common shares outstanding, basic and diluted⁽¹⁾	171,845			171,838
Loss Per Common Share
Basic and diluted	$	(0.20	)	$	(0.15	)



	December 31, 2017			March 31, 2018			June 30, 2018		September 30, 2018		December 31, 2018		March 31, 2019		June 30, 2019
NYMEX WTI⁽¹⁾ Crude Swaps:
Notional volume (Bbl)	1,850,000			1,500,000			1,500,000		1,050,000		1,050,000		—		—
Weighted average fixed price ($/Bbl)	$	50.64		$	50.70		$	50.70	$	52.91	$	52.91
NYMEX WTI⁽¹⁾ Crude Sold Calls:
Notional volume (Bbl)	1,200,000			1,735,000			1,335,000		1,560,000		1,560,000		1,500,000		1,500,000
Weighted average fixed price ($/Bbl)	$	53.04		$	55.60		$	56.22	$	55.63	$	55.63	$	55.10	$	55.10
NYMEX WTI⁽¹⁾ Crude Sold Puts:
Notional volume (Bbl)	3,225,000			3,269,400			3,269,400		2,400,000		2,400,000		1,500,000		1,500,000
Weighted average purchased put price ($/Bbl)	$	37.19		$	38.14		$	38.14	$	40.00	$	40.00	$	39.70	$	39.70
NYMEX WTI⁽¹⁾ Crude Purchased Calls:
Notional volume (Bbl)	450,000			285,000			285,000		210,000		210,000		—		—
Weighted average fixed price ($/Bbl)	$	61.65		$	60.69		$	60.69	$	59.69	$	59.69
NYMEX WTI⁽¹⁾ Crude Purchased Puts:
Notional volume (Bbl)	1,800,000			2,219,400			1,919,400		1,350,000		1,350,000		1,500,000		1,500,000
Weighted average purchased put price ($/Bbl)	$	42.13		$	46.15		$	45.71	$	49.51	$	49.51	$	49.37	$	49.37
NYMEX HH⁽²⁾ Natural Gas Swaps:
Notional volume (MMBtu)	7,420,000			10,500,000			9,300,000		8,700,000		8,700,000		—		—
Weighted average fixed price ($/MMBtu)	$	3.06		$	3.30		$	3.03	$	3.03	$	3.03
NYMEX HH⁽²⁾ Natural Gas Sold Calls:
Notional volume (MMBtu)	—			600,000			600,000		600,000		600,000		—		—
Weighted average sold call price ($/MMBtu)				$	3.15		$	3.15	$	3.15	$	3.15
NYMEX HH⁽²⁾ Natural Gas Purchased Puts:
Notional volume (MMBtu)	—			600,000			600,000		600,000		600,000		—		—
Weighted average purchased put price ($/MMBtu)				$	3.00		$	3.00	$	3.00	$	3.00
CIG⁽³⁾ Basis Gas Swaps:
Notional volume (MMBtu)	5,215,000			6,300,000			—		—		—		—		—
Weighted average fixed basis price ($/MMBtu)	$	(0.31	)	$	(0.31	)