UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

EXCHANGE ACT OF 1934

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

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

Commission File Number: 001-35371

Bonanza Creek Energy, Inc.

(Exact name of registrant as specified in its charter)


Delaware						61-1630631
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

410 17th Street,

Suite 1400

Denver,

Colorado

80202

(Address of principal executive offices)

(Zip Code)

(720) 440-6100

(Registrant’s telephone number, including area code)


Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol	Name of exchange on which registered
Common Stock, par value $0.01 per share	BCEI	New York Stock Exchange

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

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

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

Large Accelerated Filer

☐

Accelerated Filer

☒

Non-accelerated Filer

☐

Emerging growth company

☐

Smaller reporting company

☐

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

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

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

As of ~~November 2, 2020,~~August 5, 2021, the registrant had ~~20,834,427~~30,848,887 shares of common stock outstanding.

Table of Contents

BONANZA CREEK ENERGY, INC.

INDEX

PAGE

Part I.

FINANCIAL INFORMATION

Item 1.

Financial Statements

Condensed Consolidated Balance Sheets as of ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019~~2020

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020

Condensed Consolidated Statements of Stockholders' Equity for the Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020

Condensed Consolidated Statements of Cash Flows for the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020

Notes to the Condensed Consolidated Financial Statements

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

2026

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

3239

Item 4.

Controls and Procedures

Unregistered Sales of Equity Securities and Use of Proceeds

3946

Item 3.

Defaults Upon Senior Securities

3946

Item 4.

Mine Safety Disclosures

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share amounts)

September 30, 2020 December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents $ 3,777 $ 11,008
Accounts receivable, net:
Oil and gas sales 28,031 43,714
Joint interest and other 20,072 38,136
Prepaid expenses and other 3,562 7,048
Inventory of oilfield equipment 8,336 7,726
Derivative assets (note 10) 26,062 2,884
Total current assets 89,840 110,516
Property and equipment (successful efforts method):

Proved properties 1,052,004 935,025
Less: accumulated depreciation, depletion, and amortization (192,701) (126,614)
Total proved properties, net 859,303 808,411
Unproved properties 107,315 143,020
Wells in progress 50,911 98,750
Other property and equipment, net of accumulated depreciation of $3,601 in 2020 and $3,142 in 2019 3,375 3,394
Total property and equipment, net 1,020,904 1,053,575
Long-term derivative assets (note 10) 1,301 121
Right-of-use assets (note 3) 33,812 38,562
Other noncurrent assets 2,918 3,544
Total assets $ 1,148,775 $ 1,206,318
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4) $ 35,518 $ 57,638
Oil and gas revenue distribution payable 17,918 29,021
Lease liability (note 3) 12,622 11,690
Derivative liability (note 10) 5,463 6,390
Total current liabilities 71,521 104,739
Long-term liabilities:
Credit facility (note 5) 20,000 80,000
Lease liability (note 3) 21,618 27,540
Ad valorem taxes 19,442 28,520
Derivative liability (note 10) 2,939 921
Deferred income taxes (note 12) 4,689 0
Asset retirement obligations for oil and gas properties (note 9) 25,614 27,908
Total liabilities 165,823 269,628
Commitments and contingencies (note 6)
Stockholders’ equity:
Preferred stock, $0.01 par value, 25,000,000 shares authorized, NaN outstanding 0 0
Common stock, $0.01 par value, 225,000,000 shares authorized, 20,834,028 and 20,643,738 issued and outstanding as of September 30, 2020 and December 31, 2019, respectively 4,282 4,284
Additional paid-in capital 705,537 702,173
Retained earnings 273,133 230,233
Total stockholders’ equity 982,952 936,690
Total liabilities and stockholders’ equity $ 1,148,775 $ 1,206,318


	June 30, 2021		December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	24,403	$	24,743
Accounts receivable, net:
Oil and gas sales	77,533		32,673
Joint interest and other	20,082		14,748
Prepaid expenses and other	6,046		3,574
Inventory of oilfield equipment	13,990		9,185
Derivative assets (note 10)	0		7,482
Total current assets	142,054		92,405
Property and equipment (successful efforts method):
Proved properties	1,670,453		1,056,773
Less: accumulated depreciation, depletion, and amortization	(264,147)		(211,432)
Total proved properties, net	1,406,306		845,341
Unproved properties	96,348		98,122
Wells in progress	50,366		50,609
Other property and equipment, net of accumulated depreciation of $4,065 in 2021 and $3,737 in 2020	5,718		3,239
Total property and equipment, net	1,558,738		997,311

Right-of-use assets (note 4)	28,595		29,705
Deferred income tax assets (note 12)	181,262		60,520
Other noncurrent assets	5,531		2,871
Total assets	$	1,916,180	$	1,182,812
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4)	$	83,097	$	37,425
Oil and gas revenue distribution payable	54,090		18,613
Lease liability (note 2)	12,313		12,044
Derivative liability (note 10)	80,866		6,402
Total current liabilities	230,366		74,484
Long-term liabilities:
Senior notes (note 5)	100,000		0
Credit facility (note 5)	99,000		0
Lease liability (note 4)	16,543		17,978
Ad valorem taxes and other	22,678		15,069
Derivative liability (note 10)	11,285		1,330

Asset retirement obligations for oil and gas properties (note 9)	51,194		28,699

Total liabilities	531,066		137,560
Commitments and contingencies (note 6)	0		0
Stockholders’ equity:
Preferred stock, $0.01 par value, 25,000,000 shares authorized, NaN outstanding	0		0
Common stock, $0.01 par value, 225,000,000 shares authorized, 30,844,625 and 20,839,227 issued and outstanding as of June 30, 2021 and December 31, 2020, respectively	4,378		4,282
Additional paid-in capital	1,083,446		707,209
Retained earnings	297,290		333,761
Total stockholders’ equity	1,385,114		1,045,252
Total liabilities and stockholders’ equity	$	1,916,180	$	1,182,812

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

Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

(in thousands, except per share amounts)

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Operating net revenues:
Oil and gas sales $ 58,858 $ 75,176 $ 155,455 $ 233,553
Operating expenses:
Lease operating expense 5,393 6,696 16,887 18,512
Midstream operating expense 3,970 3,271 11,338 8,301
Gathering, transportation, and processing 4,778 4,423 11,970 12,776
Severance and ad valorem taxes (7,063) 6,738 1,588 18,697
Exploration 66 33 551 538
Depreciation, depletion, and amortization 23,439 19,900 67,306 54,557
Abandonment and impairment of unproved properties 223 879 30,589 2,636
Bad debt expense 102 0 678 0
General and administrative expense (including $1,723, $2,041, $4,436, and $5,189, respectively, of stock-based compensation) 8,919 9,920 26,754 30,001
Total operating expenses 39,827 51,860 167,661 146,018
Other income (expense):
Derivative gain (loss) (10,670) 12,894 64,603 (15,477)
Interest expense, net (356) (322) (1,557) (1,858)
Loss on property transactions, net 0 0 (1,398) (306)
Other income (expense) (65) 5 (1,853) 28
Total other income (expense) (11,091) 12,577 59,795 (17,613)
Income from operations before taxes 7,940 35,893 47,589 69,922
Income tax benefit (expense) (4,689) 0 (4,689) 0
Net income $ 3,251 $ 35,893 $ 42,900 $ 69,922
Comprehensive income $ 3,251 $ 35,893 $ 42,900 $ 69,922
Net income per common share:
Basic $ 0.16 $ 1.74 $ 2.07 $ 3.39
Diluted $ 0.16 $ 1.74 $ 2.06 $ 3.38
Weighted-average common shares outstanding:
Basic 20,832 20,634 20,753 20,603
Diluted 20,903 20,678 20,826 20,671


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Operating net revenues:
Oil and gas sales	$	156,035	$	36,192	$	230,194	$	96,597
Operating expenses:
Lease operating expense	11,358		5,795		17,089		11,494
Midstream operating expense	4,246		3,354		8,151		7,368
Gathering, transportation, and processing	13,721		3,711		18,688		7,192
Severance and ad valorem taxes	9,813		3,478		14,417		8,651
Exploration	3,547		112		3,643		485
Depreciation, depletion, and amortization	35,006		22,283		53,829		43,867
Abandonment and impairment of unproved properties	2,215		309		2,215		30,366
Unused commitments	4,328		0		4,328		0
Bad debt expense	0		0		0		576
Merger transaction costs	18,246		21		21,541		21
General and administrative expense (including $2,195, $1,474, $3,807, and $2,713 respectively, of stock-based compensation)	12,144		8,385		21,395		17,814
Total operating expenses	114,624		47,448		165,296		127,834
Other income (expense):
Derivative gain (loss)	(73,970)		(25,146)		(97,389)		75,273
Interest expense, net	(3,241)		(984)		(3,660)		(1,201)
Loss on property transactions, net	0		(1,398)		0		(1,398)
Other income (expense)	89		(118)		277		(1,788)
Total other income (expense)	(77,122)		(27,646)		(100,772)		70,886
Income (loss) from operations before taxes	(35,711)		(38,902)		(35,874)		39,649
Income tax benefit	10,392		0		10,436		0
Net income (loss)	$	(25,319)	$	(38,902)	$	(25,438)	$	39,649

Comprehensive income (loss)	$	(25,319)	$	(38,902)	$	(25,438)	$	39,649

Net income (loss) per common share:
Basic	$	(0.83)	$	(1.87)	$	(0.99)	$	1.91
Diluted	$	(0.83)	$	(1.87)	$	(0.99)	$	1.91
Weighted-average common shares outstanding:
Basic	30,655		20,776		25,774		20,713
Diluted	30,655		20,776		25,774		20,759

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

Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

(in thousands, except share amounts)

Additional
Common Stock Paid-In Retained
Shares Amount Capital Earnings Total
Balances, December 31, 2019 20,643,738 $ 4,284 $ 702,173 $ 230,233 $ 936,690
Restricted common stock issued 13,674 — — — 0
Stock used for tax withholdings (2,330) — (61) — (61)
Stock-based compensation — — 1,239 — 1,239
Net income — — — 78,551 78,551
Balances, March 31, 2020 20,655,082 4,284 703,351 308,784 1,016,419
Restricted common stock issued 228,149 — — — 0
Stock used for tax withholdings (56,904) (2) (951) — (953)
Stock-based compensation — — 1,474 — 1,474
Net loss — — — (38,902) (38,902)
Balances, June 30, 2020 20,826,327 4,282 703,874 269,882 978,038
Restricted common stock issued 10,849 — — — 0
Stock used for tax withholdings (3,148) — (60) — (60)
Stock-based compensation — — 1,723 — 1,723
Net income — — — 3,251 3,251
Balances, September 30, 2020 20,834,028 $ 4,282 $ 705,537 $ 273,133 $ 982,952


				Additional
	Common Stock			Paid-In		Retained
	Shares	Amount		Capital		Earnings		Total
Balances, December 31, 2020	20,839,227	$	4,282	$	707,209	$	333,761	$	1,045,252
Restricted common stock issued	109	—		—		—		—

Stock used for tax withholdings	(38)	—		—		—		—
Exercise of stock options	429	—		15		—		15
Stock-based compensation	—	—		1,612		—		1,612
Net loss	—	—		—		(119)		(119)
Balances, March 31, 2021	20,839,727	4,282		708,836		333,642		1,046,760
Issuance pursuant to acquisition	9,802,166	98		374,835		—		374,933
Restricted common stock issued	261,539	—		—		—		—

Stock used for tax withholdings	(70,330)	(2)		(2,814)		—		(2,816)
Exercise of stock options	11,523	—		394		—		394
Stock-based compensation	—	—		2,195		—		2,195
Dividends declared	—	—		—		(11,033)		(11,033)
Net loss	—	—		—		(25,319)		(25,319)
Balances, June 30, 2021	30,844,625	$	4,378	$	1,083,446	$	297,290	$	1,385,114


Balances, December 31, 2018		20,543,940	$	4,286	$	696,461	$	163,166	$	863,913
Balances, December 31, 2019											Balances, December 31, 2019	20,643,738	$	4,284	$	702,173	$	230,233	$	936,690
Restricted common stock issued											Restricted common stock issued	13,674	—		—		—		—

Stock used for tax withholdings											Stock used for tax withholdings	(2,330)	—		(61)		—		(61)

Stock-based compensation											Stock-based compensation	—	—		1,239		—		1,239
Net income											Net income	—	—		—		78,551		78,551
Balances, March 31, 2020											Balances, March 31, 2020	20,655,082	4,284		703,351		308,784		1,016,419
Restricted common stock issued	Restricted common stock issued	20,687	—		—		—		0		Restricted common stock issued	228,149	—		—		—		—

Stock used for tax withholdings	Stock used for tax withholdings	(6,036)	—		(153)		—		(153)		Stock used for tax withholdings	(56,904)	(2)		(951)		—		(953)

Stock-based compensation	Stock-based compensation	—	—		1,380		—		1,380		Stock-based compensation	—	—		1,474		—		1,474
Net loss	Net loss	—	—		—		(6,993)		(6,993)		Net loss	—	—		—		(38,902)		(38,902)
Balances, March 31, 2019		20,558,591	4,286		697,688		156,173		858,147
Restricted common stock issued		110,553	—		—		—		0

Stock used for tax withholdings		(36,145)	(1)		(930)		—		(931)

Stock-based compensation		—	—		1,768		—		1,768
Net income		—	—		—		41,022		41,022
Balances, June 30, 2019		20,632,999	4,285		698,526		197,195		900,006
Restricted common stock issued		2,178	—		—		—		0

Stock used for tax withholdings		(619)	(1)		(15)		—		(16)

Stock-based compensation		—	—		2,041		—		2,041
Net income		—	—		—		35,893		35,893
Balances, September 30, 2019		20,634,558	$	4,284	$	700,552	$	233,088	$	937,924
Balances, June 30, 2020											Balances, June 30, 2020	20,826,327	$	4,282	$	703,874	$	269,882	$	978,038

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

Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

Nine months ended September 30,
2020 2019
Cash flows from operating activities:
Net income $ 42,900 $ 69,922
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization 67,306 54,557
Deferred income tax expense 4,689 0
Abandonment and impairment of unproved properties 30,589 2,636
Well abandonment costs and dry hole expense (8) 62
Stock-based compensation 4,436 5,189
Non-cash lease component (168) 0
Amortization of deferred financing costs 772 371
Derivative (gain) loss (64,603) 15,477
Derivative cash settlements 42,494 3,766
Loss on property transactions, net 1,398 306
Other (1,158) (900)
Changes in current assets and liabilities:
Accounts receivable, net 24,262 (1,948)
Prepaid expenses and other assets 3,364 (1,180)
Accounts payable and accrued liabilities (41,692) 16,785
Settlement of asset retirement obligations (3,137) (2,035)
Net cash provided by operating activities 111,444 163,008
Cash flows from investing activities:
Acquisition of oil and gas properties (853) (12,968)
Exploration and development of oil and gas properties (56,216) (184,119)
Proceeds from sale of oil and gas properties 0 1,153
Additions to property and equipment - non oil and gas (440) (292)
Net cash used in investing activities (57,509) (196,226)
Cash flows from financing activities:
Proceeds from credit facility 45,000 40,000
Payments to credit facility (105,000) (10,000)
Payment of employee tax withholdings in exchange for the return of common stock (1,074) (1,100)
Deferred financing costs (13) (226)
Principal payments on finance lease obligations (71) 0
Net cash provided by (used in) financing activities (61,158) 28,674
Net change in cash, cash equivalents, and restricted cash (7,223) (4,544)
Cash, cash equivalents, and restricted cash:
Beginning of period 11,095 13,002
End of period $ 3,872 $ 8,458
Supplemental cash flow disclosure(1):
Cash paid for interest, net of capitalization $ 1,472 $ 3,151
Severance and ad valorem tax refund $ 0 $ 352
Receivables exchanged for additional interests in oil and gas properties $ 8,299 $ 0
Changes in working capital related to drilling expenditures $ 610 $ 20,592
(1) Refer to Note 3 - Leases in the notes to the condensed consolidated financial statements for discussion of right-of-use assets obtained in exchange for lease liabilities.


	Six Months Ended June 30,
	2021		2020
Cash flows from operating activities:
Net income (loss)	$	(25,438)	$	39,649
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	53,829		43,867
Deferred income tax benefit	(10,228)		0
Abandonment and impairment of unproved properties	2,215		30,366
Well abandonment costs and dry hole expense	0		(8)
Stock-based compensation	3,807		2,713
Non-cash lease component	(35)		(103)
Amortization of deferred financing costs	526		680
Derivative (gain) loss	97,389		(75,273)
Derivative cash settlement gain (loss)	(23,990)		33,867

Loss on property transactions, net	0		1,398
Other	0		(2,708)
Changes in current assets and liabilities:
Accounts receivable, net	(14,686)		24,521
Prepaid expenses and other assets	2,500		2,812
Accounts payable and accrued liabilities	(3,428)		(31,957)
Settlement of asset retirement obligations	(2,902)		(1,595)
Net cash provided by operating activities	79,559		68,229
Cash flows from investing activities:
Acquisition of oil and gas properties	(549)		(549)
Cash acquired	49,827		0

Exploration and development of oil and gas properties	(57,269)		(51,054)

Additions to other property and equipment	(38)		(416)
Net cash used in investing activities	(8,029)		(52,019)
Cash flows from financing activities:
Proceeds from credit facility	155,000		30,000
Payments to credit facility	(210,000)		(52,000)

Proceeds from exercise of stock options	409		0
Payment of employee tax withholdings in exchange for the return of common stock	(2,816)		(1,014)
Dividends paid	(10,789)		0
Deferred financing costs	(3,653)		(13)
Principal payments on finance lease obligations	(21)		(40)
Net cash used in financing activities	(71,870)		(23,067)
Net change in cash, cash equivalents, and restricted cash	(340)		(6,857)
Cash, cash equivalents, and restricted cash:
Beginning of period	24,845		11,095
End of period	$	24,505	$	4,238
Supplemental cash flow disclosure(1):
Cash paid for interest, net of capitalization	$	87	$	670

Receivables exchanged for additional interests in oil and gas properties	$	0	$	8,299
Changes in working capital related to drilling expenditures	$	(16,285)	$	(2,382)
(1) Refer to Note 4 - Leases in the notes to the condensed consolidated financial statements for supplemental cash flows related to leases.

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

Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - ORGANIZATION AND BUSINESS

Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, extracting, and producing oil and gas properties. The Company’s assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado.

NOTE 2 - BASIS OF PRESENTATION

These unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial statements and pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments consisting of normal recurring adjustments as necessary for a fair presentation of our financial position and results of operations.

The financial information as of December 31, ~~2019,~~2020, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 (“~~2019~~2020 Form 10-K”), but does not include all disclosures, including notes required by GAAP. As such, this quarterly report should be read in conjunction with the consolidated financial statements and related notes included in our ~~2019~~2020 Form 10-K. The Company follows the same accounting principles for preparing quarterly and annual reports. Certain prior period amounts have been reclassified to conform to the current period presentation. In connection with the preparation of the condensed consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of June 30, 2021, through the filing date of this report.

Principles of Consolidation

The condensed consolidated balance sheets (“balance sheets”) include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Boron Merger Sub, Inc., Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All ~~significant~~ intercompany accounts and transactions have been eliminated.

Use of Estimates

The preparation of the Company’s condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. The results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2020.~~2021. Further these estimates and other factors, including those outside of the Company's control, such as the impact of lower commodity prices, may impact the Company's business, financial condition, results of operations and cash flows.

~~Revenue Recognition~~Industry Segment and Geographic Information

~~Sales~~The Company operates in 1 industry segment, which is the development and production of oil, natural gas, and natural gas liquids (“NGLs”), and all of the Company's operations are conducted in the continental United States.

Revenue Recognition

Sales of oil, natural gas, and NGLs are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. The Company's contracts' pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.

As further described in Note 6 - Commitments and Contingencies, one contract with NGL Crude Logistics, LLP (“NGL Crude”, known as the “NGL Crude agreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL Crude agreement based on approved production plans to determine if liquidated damages to NGL Crude are probable. As of ~~September~~June 30, ~~2020,~~2021, the Company believes that the volumes

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delivered to NGL Crude will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL Crude agreement.

Under the oil sales contracts, the Company sells oil production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.

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Under the natural gas processing contracts, the Company delivers natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the outlet of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the Company's accompanying condensed consolidated statements of operations and comprehensive income (loss) (“statements of operations”). Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis.

Under the product sales contracts, the Company invoices customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under this guidance. At ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company's receivables from contracts with customers were ~~$28.0~~$77.5 million and ~~$43.7~~$32.7 million, respectively. Payment is generally received within 30 to 60 days after the date of production.

The Company records revenue in the month production is delivered to the purchaser. However, as stated above, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the period from January 1, ~~2020~~2021 through ~~September~~June 30, ~~2020,~~2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant.

Revenue attributable to each identified revenue stream is disaggregated below (in thousands):

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Operating Revenues:
   Crude oil sales $ 47,251 $ 66,175 $ 127,331 $ 201,981
   Natural gas sales 5,742 6,414 16,472 20,377
   Natural gas liquids sales 5,865 2,587 11,652 11,195
Oil and gas sales $ 58,858 $ 75,176 $ 155,455 $ 233,553


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Operating Revenues:
Crude oil sales	$	116,091	$	28,934	$	166,155	$	80,080
Natural gas sales	15,168		4,712		28,300		10,730
Natural gas liquids sales	24,776		2,546		35,739		5,787
Oil and gas sales	$	156,035	$	36,192	$	230,194	$	96,597

Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which ~~sum~~sums to the total of such amounts shown in the accompanying condensed consolidated statements of cash flows (“statements of cash flows”) (in thousands):

As of September 30,
2020 2019
Cash and cash equivalents $ 3,777 $ 8,371
Restricted cash included in other noncurrent assets(1)
95 87
Total cash, cash equivalents, and restricted cash as shown in the statements of cash flows $ 3,872 $ 8,458


	As of June 30,
	2021		2020
Cash and cash equivalents	$	24,403	$	4,144
Restricted cash(1)	102		94
Total cash, cash equivalents, and restricted cash	$	24,505	$	4,238

__________________________

(1) ~~Consists~~Included in other noncurrent assets and consists of funds for road maintenance and repairs.

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Unproved Property

Unproved oil and gas property costs are evaluated for impairment when there is an indication that the carrying costs may not be fully recoverable. During both the three and ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, the Company incurred ~~$0.2~~$2.2 million ~~and $30.6 million, respectively,~~ in abandonment and impairment of unproved properties compared to $0.3 million and $30.4 million during the three and six months ended June 30, 2020, respectively, due to ~~the expiration of non-core leases and~~ the reassessment of estimated probable and possible reserve locations based primarily upon economic ~~viability. During the three~~viability and ~~nine months ended September 30, 2019, the Company incurred $0.9 million and $2.6 million, respectively, in abandonment and impairment of unproved properties due to~~ the expiration of non-core leases.

Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses contain the following (in thousands):



	As of June 30, 2021		As of December 31, 2020
Accrued drilling and completion costs	$	16,738	$	453
Accounts payable trade	13,150		1,931
Accrued general and administrative expense	6,046		4,942
Accrued merger transaction costs	2,426		2,587
Accrued lease operating expense	4,298		1,793
Accrued interest expense	3,368		322
Accrued oil and gas hedging	8,820		0
Accrued production and ad valorem taxes and other	28,251		25,397
Total accounts payable and accrued expenses	$	83,097	$	37,425

Accounting Pronouncements Recently Adopted and Issued

~~In June 2016, the FASB issued~~ ~~Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments~~. The update changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amended standard was adopted using a modified retrospective approach on January 1, 2020. The Company considered past events (including historical experience), current economic and industry conditions, reasonable and supportable forecasts, and lives of receivable balances and loss experience. Historically and currently, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the adoption of this standard did not have a material impact on its condensed consolidated financial statements. As of September 30, 2020, the Company has an allowance of $0.3 million established against joint interest receivables.

~~In August 2018, the FASB issued~~ ~~Update No. 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement~~. The objective of this update is to improve the effectiveness of fair value measurement disclosures. The new standard was adopted on January 1, 2020. The standard only impacted the form of the Company's disclosures.

In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848),, which provides temporary optional guidance to companies impacted by the transition away from the ~~London Interbank Offered Rate (“LIBOR”).~~LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. ~~This amendment is~~Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and ~~expires~~expire on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition on the Company's condensed consolidated financial statements.

There are no other accounting standards applicable to the Company that would have a material effect on the Company's condensed consolidated financial statements and disclosures that have been issued but not yet adopted by the Company as of ~~September~~June 30, ~~2020,~~2021, and through the filing date of this report.

NOTE 3 - ACQUISITIONS & DIVESTITURES

HighPoint Acquisition

On April 1, 2021, Bonanza Creek completed its previously announced acquisition of HighPoint Resources Corporation, a Delaware corporation (“HighPoint”), pursuant to the terms of HighPoint’s prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code (the “Prepackaged Plan”), which was confirmed by the U.S. Bankruptcy Court for the District of Delaware on March 18, 2021 pursuant to a confirmation order, and went effective on April 1, 2021 (the “HighPoint Merger”).

The Prepackaged Plan implements the merger and restructuring transactions in accordance with the Agreement and Plan of Merger, dated as of November 9, 2020 (the “HighPoint Merger Agreement”), by and among Bonanza Creek, HighPoint and Boron Merger Sub, Inc., a wholly-owned subsidiary of Bonanza Creek (“Merger Sub”). Pursuant to the Prepackaged Plan and the HighPoint Merger Agreement, at the effective time of the HighPoint Merger (the “Effective Time”) and the effective date under the Prepackaged Plan, Merger Sub merged with and into HighPoint, with HighPoint continuing as the surviving corporation and wholly-owned subsidiary of Bonanza Creek. At the Effective Time, each eligible share of common stock, par value $0.001 per share, of HighPoint issued and outstanding immediately prior to the Effective Time was automatically converted into the right to receive 0.11464 shares of common stock, par value $0.01 per share, of Bonanza Creek (“Bonanza Creek Common Stock”), with cash paid in lieu of the issuance of any fractional shares. As a result, the Company issued approximately 487,952 shares of Bonanza Creek Common Stock to former HighPoint stockholders.

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Concurrently with the HighPoint Merger and pursuant to the Prepackaged Plan, and in exchange for the $625 million in aggregate principal amount outstanding of 7.0% Senior Notes due 2022 of HighPoint Operating Corporation (“HighPoint OpCo”) and 8.75% Senior Notes due 2025 of HighPoint OpCo (collectively, the “HighPoint Senior Notes”), Bonanza Creek issued to all holders of HighPoint Senior Notes an aggregate of (i) 9,314,214 shares of Bonanza Creek Common Stock and (ii) $100 million aggregate principal amount of 7.5% Senior Notes due 2026 of Bonanza Creek (“Bonanza Creek Senior Notes”). Please refer to Note 5 - Long-term Debt for further discussion of the Bonanza Creek Senior Notes.

Immediately after the Effective Time, in connection with the HighPoint Merger, Bonanza Creek entered into the Second Amendment, dated April 1, 2021, to the Credit Facility. Please refer to Note 5 - Long-term Debt for further discussion.

The following tables present the HighPoint Merger consideration and purchase price allocation of the assets acquired and the liabilities assumed in the HighPoint Merger:


Merger Consideration (in thousands except per share amount)
Shares of Bonanza Creek Common Stock issued to existing holders of HighPoint Common Stock(1)	488
Shares of Bonanza Creek Common Stock issued to existing holders of HighPoint Senior Notes	9,314
Total additional shares of Bonanza Creek Common Stock issued as merger consideration	9,802

Closing price per share of Bonanza Creek Common Stock(2)	$	38.25

Merger consideration paid in shares of Bonanza Creek Common Stock	$	374,933
Aggregate principal amount of Bonanza Creek Senior Notes	100,000
Total merger consideration	$	474,933

_________________________

(1) Based on the number of shares of HighPoint Common Stock issued and outstanding as of April 1, 2021 and the conversion ratio of 0.11464 per share of Bonanza Creek Common Stock.

(2) Based on the closing stock price of Bonanza Creek Common Stock on April 1, 2021.

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Purchase Price Allocation (in thousands)
Assets Acquired
Cash and cash equivalents	$	49,827
Accounts receivable - oil and gas sales	26,343
Accounts receivable - joint interest and other	9,161
Prepaid expenses and other	3,608
Inventory of oilfield equipment	4,688
Proved properties	539,820
Other property and equipment, net of accumulated depreciation	2,769
Right-of-use assets	4,010
Deferred income tax assets	110,513
Other noncurrent assets	797
Total assets acquired	$	751,536

Liabilities Assumed
Accounts payable and accrued expenses	$	51,088
Oil and gas revenue distribution payable	20,786
Lease liability	744
Derivative liability	13,481
Current portion of long-term debt	154,000
Lease liability (long-term)	3,266
Ad valorem taxes	3,746
Derivative liability (long-term)	5,019
Asset retirement obligations for oil and gas properties	24,473
Total liabilities assumed	276,603
Net assets acquired	$	474,933

As part of the HighPoint Merger, the Company obtained net operating losses of $170.6 million. The HighPoint Merger was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil and gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital rate of approximately 13%. These inputs require significant judgments and estimates by management at the time of the valuation.

The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the six months ended June 30, 2021 and for the three and six months ended June 30, 2020, assuming the acquisition had been completed as of January 1, 2020. The financial information for the three months ended June 30, 2021 is included in our statement of operations and therefore does not require a pro forma disclosure. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the business combination. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.

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	Three Months Ended June 30,		Six Months Ended June 30,
	2020		2021		2020
	(in thousands, except per share data)
Total revenue	$	79,492	$	302,213	$	219,463
Net loss	(78,410)		(66,717)		(1,023,673)

Net loss per common share:
Basic	$	(2.56)	$	(2.18)	$	(33.55)
Diluted	$	(2.56)	$	(2.18)	$	(33.55)

Extraction Merger

On May 9, 2021, Bonanza Creek, Raptor Eagle Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiary of Bonanza Creek, and Extraction Oil & Gas, Inc., a Delaware corporation (“XOG”), entered into an Agreement and Plan of Merger (the “XOG Merger Agreement”), providing for a merger of equals between Bonanza Creek and XOG (the “XOG Merger”). The XOG Merger is expected to close in the fourth quarter of 2021, contingent upon a number of factors disclosed in the XOG Merger Agreement. Once closed, the Company intends to increase annual dividend payments to approximately $1.60 per share.

Crestone Peak Merger

On June 6, 2021, Bonanza Creek, Raptor Condor Merger Sub 1, Inc., a Delaware corporation and a wholly owned subsidiary of Bonanza Creek (“Merger Sub 1”), Raptor Condor Merger Sub 2, LLC, a Delaware limited liability company and a wholly owned subsidiary of BCEI (“Merger Sub 2”), Crestone Peak Resources LP, a Delaware limited partnership (“CPR”), CPPIB Crestone Peak Resources America Inc., a Delaware corporation (“Crestone Peak”), Crestone Peak Resources Management LP, a Delaware limited partnership (“CPR Management LP”), and, Extraction Oil & Gas, Inc., a Delaware corporation, entered into an Agreement and Plan of Merger (the “Crestone Peak Merger Agreement”).

The Crestone Peak Merger Agreement, among other things, provides for the Company's acquisition of Crestone Peak through (i) the merger of Merger Sub 1 with and into Crestone Peak (the “Merger Sub 1 Merger”), with Crestone Peak continuing its existence as the surviving corporation following the Merger Sub 1 Merger (the “Surviving Corporation”), and (ii) the subsequent merger of the Surviving Corporation with and into Merger Sub 2 (the “Merger Sub 2 Merger” and together with the Merger Sub 1 Merger, the “Crestone Peak Merger”), with Merger Sub 2 continuing as the surviving entity as a wholly owned subsidiary of Bonanza Creek.

The closing of the Crestone Peak Merger is expressly conditioned on the closing of the previously announced XOG Merger pursuant to the XOG Merger Agreement. The Crestone Peak Merger is expected to close in conjunction with the XOG merger in the fourth quarter of 2021, contingent upon a number of factors disclosed in the Crestone Peak Merger Agreement. Once closed, the Company intends to increase annual dividend payments to approximately $1.85 per share.

Acquisition costs of $18.2 million and $21.5 million related to the aforementioned mergers and acquisitions were accounted for separately from the assets and liabilities assumed and are included in merger transaction costs in the Company's statements of operations for the three and six months ended June 30, 2021, respectively.

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NOTE 34 - LEASES

The Company's right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet, which include leases related to the asset classes reflected as of the dates indicated in the table below (in thousands):

September 30, 2020 December 31, 2019
Operating leases
Field equipment(1)
$ 31,251 $ 35,057
Corporate leases 1,756 2,462
Vehicles 586 1,043
Total right-of-use asset $ 33,593 $ 38,562
Field equipment(1)
$ 31,275 $ 35,075
Corporate leases 2,255 3,129
Vehicles 562 1,026
Total lease liability $ 34,092 $ 39,230
Finance leases
Right-of-use asset - field equipment(1)
$ 219 $ 0
Lease liability - field equipment(1)
$ 148 $ 0


	June 30, 2021		December 31, 2020
Operating leases
Field equipment(1)	$	23,606	$	27,537
Corporate leases	4,011		1,481
Vehicles	978		468
Total right-of-use asset	$	28,595	$	29,486

Field equipment(1)	$	23,606	$	27,537
Corporate leases	4,272		1,900
Vehicles	978		468
Total lease liability	$	28,856	$	29,905

Finance leases
Right-of-use asset - field equipment(1)	$	0	$	219
Lease liability - field equipment(1)	$	0	$	117

__________________________

(1) Includes compressors, certain gas processing equipment, and other field equipment.

The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs, once paid, are included in various line items on the statements of operations or capitalized to oil and gas properties or other property and equipment, as applicable.

The Company recognizes operating lease expense on a straight-line basis. Finance lease expense is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease payments are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. Drilling rig contracts are structured based on an allotted number of wells to be drilled consecutively at a daily operating rate. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component.

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The following table summarizes the components of the Company's gross lease costs incurred during the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 (in thousands):

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Operating lease cost(1)
$ 3,462 $ 3,088 $ 10,560 $ 8,124
Finance lease cost:
Amortization of right-of-use assets 6 0 13 0
Interest on lease liabilities 1 0 3 0
Short-term lease cost 129 2,153 2,011 5,975
Variable lease cost(2)
(89) 85 (133) 214
Sublease income(3)
(89) (87) (267) (261)
Total lease cost $ 3,420 $ 5,239 $ 12,187 $ 14,052


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Operating lease cost(1)	$	3,557	$	3,607	$	6,894	$	7,098
Finance lease cost:
Amortization of right-of-use assets	0		5		3		7
Interest on lease liabilities	0		1		1		2
Short-term lease cost	164		292		211		1,882
Variable lease cost(2)	95		(135)		65		(44)
Sublease income(3)	(91)		(89)		(183)		(178)
Total lease cost	$	3,725	$	3,681	$	6,991	$	8,767

____________________________

(1) Includes office rent expense of $0.5 million and $0.3 million for the three months ended ~~September~~June 30, 2021 and 2020, ~~and 2019~~respectively, and $0.8 million and $0.5 million for the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020, ~~and 2019.~~respectively.

(2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.

(3) The Company has subleased a portion of 1 of its office ~~space~~spaces for the remainder of the office lease term.

The Company does not have any leases with an implicit interest rate that can be readily determined. As a result, the Company used the incremental borrowing rate, based on the Credit Facility benchmark rate, adjusted for facility utilization and lease term, to calculate the respective discount rates. Please refer to Note 5 - Long-term Debt for additional information.

The Company has certain lease agreements that provide for the option to extend, purchase, or terminate early, which was evaluated on each lease to arrive at the proper lease term. There were some leases for which the option to extend or purchase was factored into the resulting lease term. There were no leases where early termination was factored into the resulting lease term. The Company's weighted-average remaining lease terms and discount rates for operating leases as of ~~September~~June 30, ~~2020~~2021 are as follows:


						Operating Leases
Weighted-average lease term (years)						2.9
Weighted-average discount rate						3.91%

Operating Leases Finance Leases
Weighted-average lease term (years) 3.02 0.41
Weighted-average discount rate 3.88% 3.47%

Supplemental cash flow information related to leases for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 consisted of the following (in thousands):

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 3,187 $ 2,705 $ 9,599 $ 7,071
Operating cash flows from finance leases 1 0 3 0
Financing cash flows from finance leases 31 0 71 0
Right-of-use assets obtained in exchange for new operating lease obligations $ 918 $ 2,811 $ 8,306 $ 12,892
Right-of-use assets obtained in exchange for new finance lease obligations 0 0 219 0


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	3,340	$	3,279	$	6,490	$	6,412
Operating cash flows from finance leases	0		1		1		2
Financing cash flows from finance leases	0		30		21		40

Right-of-use assets obtained in exchange for new operating lease obligations	$	4,010	$	1,944	$	5,499	$	7,388
Right-of-use assets obtained in exchange for new finance lease obligations	0		0		0		219

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~~Future~~As of June 30, 2021, future commitments by year for the Company's operating ~~and finance leases~~ with a lease term of one year or more ~~as of September 30, 2020~~ are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands):

Operating Leases Finance Leases
Remainder of 2020 $ 3,511 $ 32
2021 13,239 118
2022 10,192 0
2023 6,593 0
2024 2,439 0
Thereafter 108 0
Total lease payments 36,082 150
Less: imputed interest (1,990) (2)
Total lease liability $ 34,092 $ 148

~~NOTE 4- ACCOUNTS PAYABLE AND ACCRUED EXPENSES~~

~~Accounts payable and accrued expenses contain the following (in thousands):~~

As of September 30, 2020 As of December 31, 2019
Accrued drilling and completion costs $ 2,638 $ 3,248
Accounts payable trade 3,229 17,117
Accrued general and administrative expense 3,654 5,620
Accrued lease operating expense 2,113 2,187
Accrued interest 6 692
Accrued oil and gas hedging 0 453
Accrued production and ad valorem taxes and other 23,878 28,321
Total accounts payable and accrued expenses $ 35,518 $ 57,638


	Operating Leases
Remainder of 2021	$	7,179
2022	11,306
2023	7,074
2024	2,995
2025	680
Thereafter	1,328
Total lease payments	30,562
Less: imputed interest	(1,706)
Total lease liability	$	28,856

NOTE 5 - LONG-TERM DEBT

Senior Notes

In conjunction with the HighPoint Merger, Bonanza Creek issued $100 million aggregate principal amount of 7.5% Senior Notes due 2026 pursuant to an indenture (the “Indenture”), dated April 1, 2021, by and among Bonanza Creek, U.S. Bank National Association, as trustee (the “Trustee”), and the subsidiary guarantors party thereto. The Bonanza Creek Senior Notes are the senior unsecured obligations of Bonanza Creek and the subsidiaries of Bonanza Creek that are guarantors of the Bonanza Creek Senior Notes. The Indenture contains restrictive covenants that, among other things, restrict the ability of Bonanza Creek and each of its restricted subsidiaries to: (i) incur additional indebtedness and issue preferred stock; (ii) pay dividends or make other distributions in respect of Bonanza Creek common stock; (iii) make other restricted payments and investments; (iv) create liens; (v) restrict distributions or other payments from Bonanza Creek’s restricted subsidiaries; (v) sell assets, including capital stock of restricted subsidiaries; (vi) merge or consolidate with other entities; and (vi) enter into transactions with affiliates. These restrictive covenants are subject to a number of important qualifications and limitations. In addition, certain of these restrictive covenants will be suspended before the Bonanza Creek Senior Notes mature if at any time no default or event of default exists under the Indenture and the Bonanza Creek Senior Notes receive an investment grade rating from at least two ratings agencies. The Indenture also contains customary events of default.

The Bonanza Creek Senior Notes will be fully and unconditionally guaranteed, jointly and severally, on a senior basis by each restricted subsidiary that guarantees a credit facility (as defined in the Indenture) of Bonanza Creek.

Immediately after the Effective Time, HighPoint, HighPoint OpCo, and Fifth Pocket Production, LLC, a Colorado limited liability company (collectively, the “HighPoint guarantors”), Bonanza Creek, and the Trustee entered into a first supplemental indenture (the “First Supplemental Indenture”), dated April 1, 2021, to the Indenture, pursuant to which such HighPoint guarantors unconditionally guaranteed all of Bonanza Creek’s obligations under the Bonanza Creek Senior Notes and the Indenture.

Credit Facility

OnIn December 7, 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders (the “Credit Facility”). The ~~$750.0 million~~ Credit Facility has a maturity date of December 7, ~~2023 and was governed by an initial~~2023. The April 2021 redetermination as part of the Second Amendment (defined below) resulted in a borrowing base of ~~$350.0~~$500.0 million, with elected commitments set at $400.0 million. ~~The Credit Facility borrowing base is redetermined on a semi-annual basis.~~ The most recent redetermination was concluded on ~~June 18, 2020,~~July 20, 2021, resulting in a ~~reduction~~reaffirmation of the borrowing base at $500.0 million and aggregate elected commitments ~~to $260.0~~at $400.0 million. The next ~~scheduled~~ redetermination is set to occur in November ~~2020 but was not completed as~~2021, unless otherwise redetermined through the closing of the ~~date of this filing.~~XOG and Crestone Peak mergers.

The Credit Facility is guaranteed by all ~~wholly-owned~~wholly owned subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions.

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Under the original terms of the Credit Facility, borrowings bore interest at a per annum rate equal to, at the option of the Company, either (i) LIBOR, subject to a 0% LIBOR floor plus a margin of 1.75% to 2.75%, based on the utilization of the Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one-month interest period, subject to a 0% LIBOR floor plus a margin of 0.75% to 1.75%, based on the utilization of the Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears.

The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, ~~and~~ (xx) dividend ~~payments.~~payment thresholds, and (xi) cash balances. The Credit Parties are subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (i) a maximum ratio of the Company's consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) and (ii) a current ratio, as defined in the agreement, inclusive of the unused ~~Commitments~~commitments then available to be borrowed, to not be less than 1.00 to 1.00.

Under the terms of the Credit Facility, as amended in June 2020 (the “First Amendment”), borrowings bore interest at a per annum rate equal to, at the option of the Company, either (i) a LIBOR, subject to a 0% LIBOR floor plus a margin of 2.00% to 3.00%, based on the utilization of the Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one-month interest period, subject to a 0% LIBOR floor plus a margin of 1.00% to 2.00%, based on the utilization of the Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears.

On ~~June 18, 2020,~~April 1, 2021, in conjunction with the ~~borrowing base redetermination,~~HighPoint Merger, the Company, together with certain of its subsidiaries, entered into the ~~First~~Second Amendment (the ~~“First~~“Second Amendment”) to the Credit Facility (as amended, restated, supplemented or otherwise modified) to, among other things: (i) ~~implement certain anti-cash hoarding provisions, including a weekly mandatory prepayment requirement with respect~~increase the aggregate maximum commitment amount from $750.0 million to $1.0 billion; (ii) increase the ~~excess of~~available borrowing base from $260.0 million to $500.0 million; (iii) increase the ~~Company's consolidated cash balance over $35.0 million; (ii) require that, in order~~Eurodollar Rate margin to ~~borrow or issue a letter of credit under the Credit Agreement, the consolidated cash balance not exceed the greater of $35.0 million (both before and after giving effect~~3.00% to ~~such borrowing or letter of credit issuance), or expenditures in respect of oil and gas properties in the ordinary course of business (as agreed to by the administrative agent)~~4.00%; (iii) decrease the maximum permitted net leverage ratio from 4.00 to 3.50 and the maximum permitted leverage ratio for purposes of making a restricted payment, restricted investment or optional or voluntary redemption from 3.25 to 2.75; (iv) increase the ~~Eurodollar~~Reference Rate margin to 2.00% to 3.00%; (v) increase (A) the ~~Reference Rate margin~~LIBOR floor from 0% to ~~1.00%~~.50% and (B) the alternate base rate floor from 0% to ~~2.00%~~ 1.50%; (vi) decrease for any fiscal quarter ending on or after April 1, 2021, the maximum permitted net leverage ratio from 3.50 to 3.0; and ~~(vi)~~(viii) amend certain other covenants and provisions.

The Company was in compliance with all covenants as of ~~September~~June 30, ~~2020,~~2021, and through the filing date of this report.

As of ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company had ~~$20.0~~$99.0 million and ~~$80.0 million,~~0, respectively, outstanding on the Credit Facility. As of the date of this filing, the outstanding balance was ~~$10.0~~$85.0 million. The Company's Credit Facility approximates fair value as the applicable interest rates are floating.

In connection with the ~~Credit Facility,~~Second Amendment, the Company capitalized ~~a total of $2.5~~an incremental $3.7 million in deferred financing costs. Of the total post-amortization net capitalized ~~amounts,~~deferred financing costs, (i) ~~$0.8~~$2.5 million and ~~$1.4~~$0.7 million, as of ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively, are presented within other noncurrent assets and (ii) ~~$0.4~~$1.7 million and ~~$0.5~~$0.4 million, as of ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively, are presented within ~~the~~ prepaid expenses and other line items in the accompanying balance sheets.

Interest Expense

For the three months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~2020, the Company incurred interest expense of ~~$0.7~~$3.8 million and ~~$1.3~~$1.4 million, ~~respectively. The Company~~respectively, and capitalized ~~$0.3~~$0.6 million and ~~$1.0~~$0.4 million ~~of interest expense~~ during the three months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~2020, respectively. For the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~2020, the Company incurred interest expense of ~~$3.3~~$4.3 million and ~~$3.6~~$2.6 million, ~~respectively. The Company~~respectively, and capitalized ~~$1.7~~$0.6 million ~~of interest expense~~and $1.4 million during ~~each of~~ the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020, ~~and 2019.~~respectively.

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NOTE 6 - COMMITMENTS AND CONTINGENCIES

Legal Proceedings

From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its condensed consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. NaN claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company of which it was aware.

~~In February 2019,~~Upon closing of the HighPoint Merger, the Company assumed all obligations, whether asserted or unasserted, of HighPoint Resources Corporation. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company that were associated with HighPoint of which it was ~~sent~~aware, other than the following:

On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filed a ~~notice~~complaint against HighPoint OpCo, a subsidiary of ~~intent~~HighPoint Resources Corporation, for breach of contract related to ~~sue (“NOI”) letter~~a Gas Purchase Agreement dated effective November 1, 2017. Sterling alleges that HighPoint OpCo breached the contract by ~~WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure~~failing to ~~obtain required permits~~use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. HighPoint Resources OpCo filed a counterclaim against Sterling for breach of Sterling’s obligations under the ~~federal Clean Air Act before constructing~~Gas Purchase Agreement. The possible damages range from 0 to $5.5 million. At this time, the Company is unable to determine whether any loss is probable and ~~operating well production facilities in~~accordingly has not recognized any liability associated with this matter.

Disclosure of certain environmental matters is required when a governmental authority is a party to the ~~ozone non-attainment area around~~proceedings and the ~~Denver Metropolitan~~proceedings involve potential monetary sanctions that the Company believes could exceed $300,000. HighPoint Resources Corporation received Notices of Alleged Violations (“NOAV”) from the Colorado Oil and ~~North Front Range~~Gas Conservation Commission (“COGCC”) alleging violations of various Colorado ~~among other things. The Company was one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG,~~statutes and ~~these letters appeared to challenge long-established federal and state~~COGCC regulations ~~and policies for permitting the construction and initial operation of upstream~~governing oil and gas ~~production facilities~~operations. The Company continues to engage in ~~Colorado~~discussions regarding resolution of the alleged violations. As of June 30, 2021, the Company has recognized approximately $1.8 million associated with the NOAVs, as they are probable and ~~elsewhere under~~reasonably estimable.

Commitments

Firm Transportation Agreements. As part of the ~~Clean Air Act and state counterpart statutes.~~

~~In May 2019, WEG filed a lawsuit~~HighPoint Merger, the Company is now party to 2 firm transportation contracts to provide capacity on natural gas pipeline systems. The contracts require the Company to pay minimum volume transportation charges through July 2021 regardless of the amount of pipeline capacity utilized by the Company. These deficiency payments totaling $4.3 million for the three months ended June 30, 2021 are included in unused commitments expense in the ~~U.S. District Court for~~statements of operations. The Company will not utilize the ~~District of Colorado against~~firm capacity on the natural gas pipelines.

Additionally, the Company is party to 1 firm pipeline transportation contract to provide capacity on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges on 8,500 gross barrels per day through April 2022 and 12,500 barrels per day thereafter through April 2025, regardless of the ~~other six operators who received~~amount of pipeline capacity utilized by the ~~NOI, alleging claims consistent with those contained in~~Company. The aggregate financial commitment fee over the ~~NOI letters. The allegations made in the lawsuit were based on novel and unprecedented interpretations~~remaining term was $52.1 million as of ~~complex federal and state air quality laws and regulations.~~June 30, 2021. The Company ~~settled with WEG, and in September 2020~~expects to utilize most, if not all, ~~claims in~~of the ~~lawsuit against~~firm capacity on the ~~Company were dismissed with prejudice.~~oil pipeline system.

~~Commitments~~

Minimum Volume Agreements. The Company is party to a purchase agreement to deliver fixed determinable quantities of crude oil to NGL Crude. The NGL Crude agreement includes defined volume commitments over a term ending in 2023. Under the terms of the NGL Crude agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods. The minimum gross volume commitment will increase approximately 3% each year for the remainder of the contract, to a maximum of approximately 16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term was ~~$56.7~~$37.3 million as of ~~September~~June 30, ~~2020.~~

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2021. Upon notifying NGL Crude at least twelve months prior to the expiration date of the NGL Crude agreement, the Company may elect to extend the term of the NGL Crude agreement for up to three additional years.

~~The annual minimum commitment payments under the NGL Crude agreement for the next five years as of September 30, 2020 are presented below (in thousands):~~

NGL Crude Commitments(1)
Remainder of 2020 $ 3,694
2021 22,403
2022 23,097
2023 7,521
2024 0
2025 and thereafter 0
Total $ 56,715

~~____________________________~~

~~(1) The above calculation is based on the minimum volume commitment schedule (as defined in the NGL Crude agreement) and applicable differential fees.~~

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Since the commencement of the NGL Crude agreement and through the remainder of the term of the agreement, the Company has not and does not expect to incur any deficiency payments.

The Company is also party to 1 minimum volume commitment for the delivery of natural gas volumes to a midstream entity for gathering and processing and minimum volume commitments to purchase fresh water from water suppliers. These commitments require the Company to pay a fee associated with the minimum volumes regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $4.2 million as of June 30, 2021.

The minimum annual payments under the these agreements for the next five years as of June 30, 2021 are presented below (in thousands):


	Firm Transportation		Minimum Volume(1)
Remainder of 2021	$	6,505	$	13,170
2022	13,064		24,322
2023	14,600		4,052
2024	14,640		0
2025	4,800		0
2026 and thereafter	0		0
Total	$	53,609	$	41,544

____________________________

(1) The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreements) and applicable differential fees.

There have been no other material changes from the commitments disclosed in the notes to the Company's consolidated financial statements included in our ~~2019~~2020 Form 10-K. Refer to Note 34 - Leases, for lease commitments.

NOTE 7 - STOCK-BASED COMPENSATION

Long Term Incentive Plans

In 2017, the Company adopted a Long Term Incentive Plan

~~Upon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017~~ (“2017 LTIP”), as established by the ~~pre-emergence~~ Board, ~~of Directors,~~ which allows for the issuance of restricted stock units (“RSUs”), performance stock units (“PSUs”), and options, and reserved 2,467,430 shares of ~~new~~ common stock. Additionally, in June 2021, the Company adopted the 2021 Long Term Incentive Plan (“2021 LTIP”), as established by the Board, which reserved an incremental 700,000 shares of common stock in addition to the 2017 LTIP. The 2017 LTIP and 2021 LTIP shall be collectively referred herein as the “LTIP”. See below for further discussion of awards granted under the ~~2017~~ LTIP.

The Company recorded compensation expense related to the awards granted under the ~~2017~~ LTIP as follows (in thousands):


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Restricted stock units	Restricted stock units	$	1,350	$	1,535	$	3,935	$	3,966	Restricted stock units	$	1,746	$	1,284	$	3,067	$	2,585
Performance stock units	Performance stock units	373		362		375		775		Performance stock units	449		195		740		2
Stock options	Stock options	0		144		126		448		Stock options	0		(5)		—		126
Total stock-based compensation	Total stock-based compensation	$	1,723	$	2,041	$	4,436	$	5,189	Total stock-based compensation	$	2,195	$	1,474	$	3,807	$	2,713

As of ~~September~~June 30, ~~2020,~~2021, unrecognized compensation expense will be amortized through the relevant periods as follows (in thousands):


	Unrecognized Compensation Expense		Final Year of Recognition
Restricted stock units	$	10,411	2023
Performance stock units	5,639		2023
	$	16,050

Unrecognized Compensation Expense Final Year of Recognition
Restricted stock units $ 9,141 2023
Performance stock units 2,319 2022
$ 11,460

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Restricted Stock Units

The ~~2017~~ LTIP allows for the issuance of RSUs to members of the Board of Directors (the “Board”) and employees of the Company at the discretion of the Board. Each RSU represents ~~one~~1 share of the Company's common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. The RSUs are valued at the grant date share price and are recognized as general and administrative expense over the vesting period of the award.

During the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, the Company granted ~~306,945~~175,549 RSUs with a fair value of ~~$4.9~~$6.0 million. A summary of the status and activity of non-vested restricted stock units for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 is presented below:

Restricted Stock Units Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year 557,817 $ 26.95
Granted 306,945 15.90
Vested (252,672) 15.56
Forfeited (54,547) 25.53
Non-vested, end of quarter 557,543 $ 20.40


	Restricted Stock Units	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	550,056	$	20.30
Granted	175,549	34.21
Vested	(261,648)	20.97
Forfeited	(17,926)	17.55
Non-vested, end of quarter	446,031	$	25.49

Cash flows resulting from excess tax benefits are to be classified as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the periods presented.

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Performance Stock Units

The ~~2017~~ LTIP allows for the issuance of PSUs to employees at the sole discretion of the Board. The number of shares of the Company's common stock that may be issued to settle PSUs ranges from 0 to 2 times the number of PSUs awarded. The PSUs vest in their entirety at the end of the three-year performance period. ~~The total number of PSUs granted is split between two performance criteria.~~ The first criterion is based on a comparison of the Company's absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group of peer companies for the same performance period. The TSR for the Company and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion, when applicable, is based on the Company's annual return on average capital employed (“ROCE”) for each year during the three-year performance period. The total number of PSUs granted was split ~~between the two performance criteria is even~~as follows for the ~~PSUs granted in 2018 and 2019, whereas the split is two-thirds weighted to the TSR criterion and one-third weighted to the ROCE criterion for the PSUs granted in 2020.~~ relevant grant years:


	2021		2020		2019
TSR	100	%	67	%	50	%
ROCE	0	%	33	%	50	%

Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period. Because these awards depend on a combination of performance-based and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company's expected ROCE performance. As of ~~September~~June 30, ~~2020,~~2021, the Company does not expect any of the ROCE portion of the PSUs granted in ~~2018 and~~ 2019 to vest and has accordingly adjusted the related compensation expense.

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The fair value of the PSUs was measured at the grant date. The portion of the PSUs tied to the TSR required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These 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 Company's TSRs, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR. 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 performance period, as well as the volatilities for each of the Company's peers.

During the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, the Company granted ~~83,209~~64,258 PSUs with a fair value of ~~$1.9~~$4.4 million. The PSUs granted in 2018 expired as of December 31, 2020, with zero distribution of shares to the recipients, as neither the TSR nor the ROCE performance criteria were met. A summary of the status and activity of performance stock units for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 is presented below:

Performance Stock Units(1)
Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year 153,470 $ 24.74
Granted 83,209 23.22
Vested 0 0
Forfeited 0 0
Non-vested, end of quarter 236,679 $ 24.21


	Performance Stock Units(1)	Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year	185,588	$	22.63
Granted	64,258	68.99
Vested	0	0
Forfeited	0	0
Non-vested, end of quarter	249,846	$	34.56

___________________________

(1)The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company's common stock issued may vary depending on the performance multiplier, which ranges from 0 to 2, depending on the level of satisfaction of the performance condition.

Stock Options

The ~~2017~~ LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award.

Stock options are valued using a Black-Scholes Model where (i) expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, (ii) the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and (iii) the Company's expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards.

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There were 0 stock options granted during the ~~nine~~six months ended ~~September~~June 30, ~~2020.~~2021. A summary of the status and activity of stock options for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 is presented below:


	Stock Options	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding, beginning of year	72,368	$	34.36
Granted	0	0
Exercised	(11,952)	34.36
Forfeited	(399)	34.36
Outstanding, end of quarter	60,017	$	34.36	5.5	$	763
Number of options outstanding and exercisable	60,017	$	34.36	5.5	$	763

Stock Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands)
Outstanding, beginning of year 100,714 $ 34.36
Granted 0 0
Exercised 0 0
Forfeited (28,346) 34.36
Outstanding, end of quarter 72,368 $ 34.36 6.6 $ 0
Number of options outstanding and exercisable 72,368 $ 34.36 6.6 $ 0
The aggregate intrinsic value of options exercised during the six months ended June 30, 2021 was $0.1 million.

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NOTE 8 - FAIR VALUE MEASUREMENTS

The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement 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. 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, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

Level 3: Significant inputs to the valuation model are unobservable

Financial and non-financial assets and liabilities are to be 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.

Derivatives

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps, collars, and puts were validated by observable transactions for the same or similar commodity options using the NYMEX futures index and were designated as Level 2 within the valuation hierarchy. The following tables present the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis and their classification within the fair value hierarchy (in thousands):


	As of June 30, 2021
	Level 1		Level 2		Level 3
Derivative assets	$	0	$	0	$	0
Derivative liabilities	$	0	$	92,151	$	0

As of September 30, 2020
Level 1 Level 2 Level 3
Derivative assets $ 0 $ 27,363 $ 0
Derivative liabilities $ 0 $ 8,402 $ 0


		As of December 31, 2019							As of December 31, 2020
		Level 1		Level 2		Level 3			Level 1		Level 2		Level 3
Derivative assets	Derivative assets	$	0	$	3,005	$	0	Derivative assets	$	0	$	7,482	$	0
Derivative liabilities	Derivative liabilities	$	0	$	7,311	$	0	Derivative liabilities	$	0	$	7,732	$	0

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Senior Notes

The Bonanza Creek $100.0 million Senior Notes, issued on April 1, 2021, are recorded at carrying value. There were no debt issuance costs, discounts or premiums associated with the Bonanza Creek Senior Notes. The estimated fair value of the 7.5% Bonanza Creek Senior Notes was $100.7 million as of June 30, 2021. The fair value of the Bonanza Creek Senior Notes is based on quoted market prices, and as such, is designated as Level 1 within the valuation hierarchy.

Proved Oil and Gas Properties

Proved oil and gas property costs are evaluated for impairment on a nonrecurring basis and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash ~~flows.~~flows of the underlying oil and gas reserves. Depending on the availability of data, the Company uses Level 3 inputs and either the income valuation technique, which converts future amounts to a single present value amount to measure the fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from the NYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were 0 proved oil and gas property impairments during the three and ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019.~~2020.

NOTE 9 - ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset, which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties.

The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred.

A roll-forward of the Company's asset retirement obligation is as follows (in thousands):


	Amount
Beginning balance as of December 31, ~~2019~~2020	$	~~27,908~~28,699
Liabilities settled	~~(3,137)~~(2,902)
Additions	8424,633
Accretion expense	~~759~~764

Ending balance as of ~~September~~June 30, ~~2020~~2021	$	~~25,614~~51,194

NOTE 10 - DERIVATIVES

The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps, collars, and puts for oil and natural gas, and 0ne of the derivative instruments qualify as having hedging relationships.

In a typical commodity fixed-price swap agreement, if the agreed upon published third-party index price is lower than the swap strike price, the Company receives the difference between the index price and the agreed upon swap strike price. If the index price is higher than the swap strike price, the Company pays the difference. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap.

A ~~put gives~~basis swap arrangement guarantees a price differential from a specified delivery point to an agreed upon reference point. The Company receives the ~~owner~~difference between the ~~right~~price differential and the stated terms, if the price differential is greater

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than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential.

Certain NYMEX calendar month average (“CMA”) settlement contracts contain a “CMA Roll Adjustment,” the calculation of which includes futures prices for contracts deliverable in, at the time, two forward months. The physical trade month average is compared to ~~sell~~ the ~~underlying commodity~~prompt month futures contracts and weighted to reflect the amount of time during the delivery month that the forward months traded as the prompt month. The weighted adjustment values are added to the basic calendar month average to arrive at ~~a set~~the Roll Adjusted settlement price ~~over~~for the ~~term~~month. “Oil roll swaps” fix the value of the ~~contract.~~roll adjustment. If the ~~index settlement price is higher than~~futures curve becomes more backwardated after entering the ~~put fixed price,~~oil roll swap, we will pay the ~~put will expire worthless.~~difference between the CMA Roll Adjustment and the oil roll swap price. If the ~~settlement price is lower than the put fixed price, the Company~~futures curve becomes more in contango, we will ~~exercise the put and~~ receive the difference between the ~~settlement price~~CMA Roll Adjustment and the ~~put fixed~~oil roll swap price.

A cashless collar arrangement establishes a floor and ceiling price on future oil and gas production. When the settlement price is above the ceiling price, the Company pays the difference between the settlement price and the ceiling price. When the settlement price is below the floor price, the Company receives the difference between the settlement price and floor price. In the event that the settlement price is between the ceiling and the floor, no payment or receipt occurs.

A put gives the owner the right to sell the underlying commodity at a set price over the term of the contract. If the index settlement price is higher than the put fixed price, the put will expire worthless. If the settlement price is lower than the put fixed price, the Company will exercise the put and receive the difference between the settlement price and the put fixed price.

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~~A basis~~As of June 30, 2021, the Company had entered into the following commodity derivative contracts:


	Crude Oil (NYMEX WTI)		Natural Gas (NYMEX Henry Hub)		Natural Gas (CIG Basis)		Natural Gas (CIG)
	Bbls/day	Weighted Avg. Price per Bbl	MMBtu/day	Weighted Avg. Price per MMBtu	MMBtu/day	Weighted Avg. Basis Differential to CIG Price per MMBtu	MMBtu/day	Weighted Avg. Price per MMBtu
3Q21
Cashless Collar	3,000	$30.00/$50.62	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75
Swap	9,500	$54.41	—	—	20,000	$0.43	20,000	$2.12
Oil Roll Swap(1)	4,500	$0.16	—	—	—	—	—	—
4Q21
Cashless Collar	4,000	$30.63/$50.34	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75
Swap	8,000	$54.49	—	—	20,000	$0.43	13,370	$2.13
Oil Roll Swap(1)	4,500	$0.16	—	—	—	—	—	—
1Q22
Cashless Collar	6,500	$35.10/$59.44	—	—	—	—	20,000	$2.15/$2.75
Swap	1,000	$50.15	—	—	—	—	10,000	$2.13
Oil Roll Swap(1)	2,000	$0.22	—	—	—	—	—	—
Swaptions	4,000	$55.06	—	—	—	—	—	—
2Q22
Cashless Collar	5,000	$36.64/$63.52	—	—	—	—	20,000	$2.15/$2.75
Swap	1,000	$50.15	—	—	—	—	10,000	$2.13
Oil Roll Swap(1)	2,000	$0.22	—	—	—	—	—	—
Swaptions	4,000	$55.06	—	—	—	—	—	—
3Q22
Cashless Collar	3,500	$38.76/$66.84	—	—	—	—	—	—
Swap	1,000	$50.15	—	—	—	—	10,000	$2.13
Oil Roll Swap(1)	2,000	$0.22	—	—	—	—	—	—
Swaptions	2,000	$55.13	—	—	—	—	—	—
4Q22
Cashless Collar	3,000	$39.39/$68.86	—	—	—	—	—	—
Swap	1,000	$50.15	—	—	—	—	10,000	$2.13
Oil Roll Swap(1)	2,000	$0.22	—	—	—	—	—	—
Swaptions	2,000	$55.13	—	—	—	—	—	—

(1) The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap arrangement guarantees a price differential from a specified delivery point to an agreed upon reference point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential.contracts.

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As of ~~September 30, 2020 and~~ the filing date of this report, the Company had entered into the following commodity derivative contracts:


		Crude Oil (NYMEX WTI)		Natural Gas (NYMEX Henry Hub)		Natural Gas (CIG Basis)		Natural Gas (CIG)			Crude Oil (NYMEX WTI)		Natural Gas (NYMEX Henry Hub)		Natural Gas (CIG Basis)		Natural Gas (CIG)
		Bbls/day	Weighted Avg. Price per Bbl	MMBtu/day	Weighted Avg. Price per MMBtu	MMBtu/day	Weighted Avg. Basis Differential to CIG Price per MMBtu	MMBtu/day	Weighted Avg. Price per MMBtu		Bbls/day	Weighted Avg. Price per Bbl	MMBtu/day	Weighted Avg. Price per MMBtu	MMBtu/day	Weighted Avg. Basis Differential to CIG Price per MMBtu	MMBtu/day	Weighted Avg. Price per MMBtu
4Q20
Cashless Collar		6,000	$52.67/$58.40	10,000	$2.25/$2.67	—	—	—	—
Swap		3,500	$54.12	10,000	$2.30	30,000	$0.54	—	—
Put		3,000	$32.50
1Q21
Cashless Collar		3,000	$43.67/$53.58	30,000	$2.25/$2.57	—	—	—	—
Swap		5,000	$54.48	—	—	20,000	$0.43	—	—
2Q21
Cashless Collar		2,500	$34.40/$49.82	20,000	$2.25/$2.52	—	—	—	—
Swap		4,000	$54.13	—	—	20,000	$0.43	—	—
3Q21	3Q21									3Q21
Cashless Collar	Cashless Collar	3,000	$30.00/$50.62	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75	Cashless Collar	3,000	$30.00/$50.62	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75
Swap	Swap	2,500	$54.45	—	—	20,000	$0.43	—	—	Swap	9,500	$54.41	—	—	20,000	$0.43	20,000	$2.12
Oil Roll Swaps(1)										Oil Roll Swaps(1)	4,500	$0.16	—	—	—	—	—	—
4Q21	4Q21									4Q21
Cashless Collar	Cashless Collar	4,000	$30.63/$50.34	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75	Cashless Collar	10,500	$48.81/$67.63	20,000	$2.25/$2.52	—	—	20,000	$2.15/$2.75
Swap	Swap	1,000	$55.20	—	—	20,000	$0.43	—	—	Swap	8,000	$54.49	—	—	20,000	$0.43	13,370	$2.13
Oil Roll Swaps(1)										Oil Roll Swaps(1)	4,500	$0.16	—	—	—	—	—	—
1Q22	1Q22									1Q22
Cashless Collar	Cashless Collar	3,000	$30.83/$50.33	—	—	—	—	20,000	$2.15/$2.75	Cashless Collar	6,500	$35.10/$59.44	—	—	—	—	20,000	$2.15/$2.75

Swap										Swap	1,000	$50.15	—	—	—	—	10,000	$2.13
Oil Roll Swaps(1)										Oil Roll Swaps(1)	2,000	$0.22	—	—	—	—	—	—
Swaptions										Swaptions	4,000	$55.06	—	—	—	—	—	—
2Q22	2Q22									2Q22
Cashless Collar	Cashless Collar	1,500	$31.67/$54.79	—	—	—	—	20,000	$2.15/$2.75	Cashless Collar	5,000	$36.64/$63.52	—	—	—	—	20,000	$2.15/$2.75
Swap										Swap	1,000	$50.15	—	—	—	—	10,000	$2.13
Oil Roll Swaps(1)										Oil Roll Swaps(1)	2,000	$0.22	—	—	—	—	—	—
Swaptions										Swaptions	4,000	$55.06	—	—	—	—	—	—
3Q22	3Q22									3Q22
Cashless Collar	Cashless Collar	500	$35.00/$54.75	—	—	—	—	—	—	Cashless Collar	4,200	$40.64/$67.74	20,000	$2.80/$4.20	—	—	—	—
Swap										Swap	1,000	$50.15	—	—	—	—	10,000	$2.13
Oil Roll Swaps(1)										Oil Roll Swaps(1)	2,000	$0.22	—	—	—	—	—	—
Swaptions										Swaptions	2,000	$55.13	—	—	—	—	—	—
4Q22										4Q22
Cashless Collar										Cashless Collar	3,700	$41.40/$69.50	20,000	$2.80/$4.20	—	—	—	—
Swap										Swap	1,000	$50.15	—	—	—	—	10,000	$2.13
Oil Roll Swaps(1)										Oil Roll Swaps(1)	2,000	$0.22	—	—	—	—	—	—
Swaptions										Swaptions	2,000	$55.13	—	—	—	—	—	—

(1) The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

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Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of the dates indicated in the table below (in thousands):


	June 30, 2021		December 31, 2020
Derivative Assets:
Commodity contracts – current	$	0	$	7,482
Commodity contracts – noncurrent	0		0
Derivative Liabilities:
Commodity contracts – current	(80,866)		(6,402)
Commodity contracts – noncurrent	(11,285)		(1,330)
Total derivative assets (liabilities), net	$	(92,151)	$	(250)

September 30, 2020 December 31, 2019
Derivative Assets:
Commodity contracts - current $ 26,062 $ 2,884
Commodity contracts - noncurrent 1,301 121
Derivative Liabilities:
Commodity contracts - current (5,463) (6,390)
Commodity contracts - noncurrent (2,939) (921)
Total derivative assets (liabilities), net $ 18,961 $ (4,306)

The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands):

Three Months Ended September 30, Nine months ended September 30,
2020 2019 2020 2019
Derivative cash settlement gain (loss):
Oil contracts $ 9,165 $ 2,424 $ 42,088 $ 3,518
Gas contracts (538) 949 406 248
Total derivative cash settlement gain(1)
8,627 3,373 42,494 3,766
Change in fair value gain (loss) (19,297) 9,521 22,109 (19,243)
Total derivative gain (loss)(1)
$ (10,670) $ 12,894 $ 64,603 $ (15,477)


	Three Months Ended June 30,				Six months ended June 30,
	2021		2020		2021		2020
Derivative cash settlement gain (loss):
Oil contracts	$	(18,794)	$	22,485	$	(21,616)	$	32,923
Gas contracts	(1,405)		128		(2,374)		944
Total derivative cash settlement gain (loss)(1)	(20,199)		22,613		(23,990)		33,867
Change in fair value gain (loss)	(53,771)		(47,759)		(73,399)		41,406
Total derivative gain (loss)(1)	$	(73,970)	$	(25,146)	$	(97,389)	$	75,273

(1)Total derivative gain (loss) and total derivative cash settlement gain (loss) for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 are reported in the derivative (gain) loss line item and derivative cash ~~settlements~~settlement gain (loss) line item in the accompanying statements of cash flows, within the cash flows from operating activities.

NOTE 11 - EARNINGS PER SHARE

The Company issues RSUs, which represent the right to receive, upon vesting, one share of the Company's common stock. The number of potentially dilutive shares related to RSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that ranges from 0 to 2 times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming that date was the end of such stock options' or warrants' term.

Please refer to Note 7 - Stock-Based Compensation for additional discussion.

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The Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts):

Three Months Ended September 30, Nine Months Ended September 30,
2020 2019 2020 2019
Net income $ 3,251 $ 35,893 $ 42,900 $ 69,922
Basic net income per common share $ 0.16 $ 1.74 $ 2.07 $ 3.39
Diluted net income per common share $ 0.16 $ 1.74 $ 2.06 $ 3.38
Weighted-average shares outstanding - basic 20,832 20,634 20,753 20,603
Add: dilutive effect of contingent stock awards 71 44 73 68
Weighted-average shares outstanding - diluted 20,903 20,678 20,826 20,671


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net income (loss)	$	(25,319)	$	(38,902)	$	(25,438)	$	39,649

Basic net income (loss) per common share	$	(0.83)	$	(1.87)	$	(0.99)	$	1.91
Diluted net income (loss) per common share	$	(0.83)	$	(1.87)	$	(0.99)	$	1.91

Weighted-average shares outstanding - basic	30,655		20,776		25,774		20,713
Add: dilutive effect of contingent stock awards	0		0		0		46
Weighted-average shares outstanding - diluted	30,655		20,776		25,774		20,759

There were ~~549,967~~747,678 and ~~393,783~~715,639 shares that were anti-dilutive for the three months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~2020, respectively, and ~~427,857~~777,564 and ~~155,094 shares~~407,996 that were anti-dilutive for the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020. The Company was in a net loss position for the three months ended June 30, 2021 and 2020 ~~and 2019, respectively.~~as well as the six months ended June 30, 2021, which made all potentially dilutive shares anti-dilutive.

The exercise price of the Company's stock ~~options and~~ warrants were in excess of the Company's stock ~~price;~~price during the three and six months ended June 30, 2020; therefore, they were excluded from the earnings per share calculation. The Company's warrants expired on April 30, 2020.

NOTE 12 - INCOME TAXES

Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the Company's balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes.

The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. In making such determination, the Company considers all available (both positive and ~~negative~~negative) evidence, including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. ~~As a result of~~The Company has cumulative book income for the ~~Company's analysis, it was concluded that as of September 30, 2020~~prior three years and ~~December 31, 2019, a~~is forecasting future book income, which resulted in the full valuation allowance ~~should be established against the Company's deferred tax asset. During the three and nine months ended September 30, 2020, the Company recorded income tax expense and a related deferred tax liability~~being removed as of $4.7 million for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses. During the three and nine months ended September 30, 2019, the Company recorded 0 income tax expense. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized.December 31, 2020.

Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, and other permanent differences. During the three and six months ended June 30, 2021, the Company recorded income tax benefit of $10.4 million compared to 0 income tax benefit during the three and six months ended June 30, 2020.

As of ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company had 0 unrecognized tax benefits. The Company's management does not believe that there are any new items or changes in facts or judgments that would impact the Company's tax position taken thus far in ~~2020.~~2021.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, ~~2019,~~2020, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Executive Summary

We are an independent Denver-based exploration and production company focused on the acquisition, development, and extraction of oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formations in the Denver-Julesburg (“DJ”) Basin. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.

The Company’s primary objective is to maximize shareholder returns through dividends and debt reduction by responsibly developing our oil and gas resources. We seek to balance production and company growth with maintaining a conservative balance sheet. Key aspects of our strategy include well-balanced asset mergers and acquisitions, multi-well pad development across our leasehold, enhanced completions through continuous design evaluation, utilization of scaled infrastructure, continuous safety improvement, strict adherence to health and safety regulations, and environmental stewardship.

Financial and Operating Results

Our financial and operational results include:

•~~General and administrative expense per Boe decreased by 19% during~~Crude oil equivalent sales volumes increased 70% for the ~~nine~~three months ended ~~September~~June 30, ~~2020~~2021 when compared to the same period in ~~2019;~~2020 due to the HighPoint Merger;

•Lease operating expense increased by 15% per Boe ~~decreased by 17%~~ for the ~~nine~~three months ended ~~September~~June 30, ~~2020~~2021 when compared to the same period in ~~2019;~~2020;

•~~Crude oil equivalent sales volumes increased 10%~~General and administrative expense decreased by 15% per Boe for the ~~nine~~three months ended ~~September~~June 30, ~~2020~~2021 when compared to the same period in ~~2019 despite the significant curtailment of our drilling and completion program in response to the drop in commodity prices;~~2020;

•Borrowings under our Credit Facility were reduced by ~~$60.0~~$56.0 million to ~~$20.0~~$99.0 million during the ~~nine~~three months ended ~~September~~June 30, ~~2020~~2021 from the ~~$80.0~~$155.0 million ~~outstanding~~borrowed at ~~December 31, 2019;~~the closing of the HighPoint Merger to pay down the HighPoint credit facility;

•Total liquidity of ~~$243.8~~$325.4 million at ~~September~~June 30, ~~2020,~~2021, consisting of cash on hand plus funds available under our Credit Facility. Please refer to Liquidity and Capital Resources below for additional discussion;

•Cash dividend of $10.8 million, or $0.35 per share, declared and paid during the three months ended June 30, 2021;

•Cash flows provided by operating activities for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 were ~~$111.4~~$79.6 million, as compared to cash flows provided by operating activities of ~~$163.0~~$68.2 million during the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. Please refer to Liquidity and Capital Resources below for additional discussion; and

•Capital expenditures, inclusive of accruals, of ~~$64.6~~$73.6 million during the ~~nine~~six months ended ~~September~~June 30, ~~2020.~~2021.

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Rocky Mountain Infrastructure

The Company's gathering, treating, and production facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, provide many operational benefits to the Company and provide cost economies of a centralized system. The RMI facilities reduce gathering system pressures at the wellhead, thereby improving hydrocarbon recovery. Additionally, with eleven interconnects to four different natural gas processors, RMI helps ensure that the Company's production is not constrained by any single midstream service provider. Furthermore, in 2019, the Company installed a new oil gathering line to Riverside Terminal (on the Grand Mesa Pipeline), which resulted in a corresponding $1.25 to $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. Additionally, the Company commenced construction of an additional oil interconnect in late June 2021, thus providing additional outlets to provide flow assurance and minimize differentials. The total value of reduced oil differentials during the six months ended June 30, 2021 and 2020 was approximately $2.1 million and $2.9 million, respectively. Finally, the RMI system reduces facility site footprints, leading to more cost-efficient operations and reduced emissions and surface disturbance. The net book value of the Company's RMI assets was ~~$153.8~~$196.1 million as of ~~September~~June 30, ~~2020.~~2021.

~~Table of~~ ~~Contents~~

Current Events and Outlook ~~for 2020~~

The worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19, and various governmental actions taken to mitigate the impact of COVID-19, ~~have~~ resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production further increased the excess supply of oil and natural ~~gas. Due to~~gas throughout 2020. However, during the ~~decline~~first quarter of 2021, expectations surrounding the demand for oil and natural gas stimulated a rise in ~~crude~~ oil ~~prices~~ and ~~ongoing uncertainty regarding the oil supply-demand macro environment as a result of these events, we have suspended all drilling and significantly reduced completion and infrastructure activities.~~natural gas prices.

The COVID-19 outbreak and its development into a pandemic in March 2020 ~~have~~ also required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers, and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to our operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected), and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Centers for Disease Control and Prevention. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of a COVID-19 outbreak.

The Company's ~~initial 2020~~stand-alone first quarter 2021 capital budget of ~~$215.0~~$35 million to ~~$235.0~~$40 million ~~assumed~~and combined second through fourth quarter 2021 capital budget (reflecting the ~~continuation~~closing of the HighPoint Merger on April 1, 2021) of $115 million to $130 million includes completing 45 gross (39.9 net) drilled, uncompleted wells, and picking up a ~~one-rig operated program~~drilling rig in the ~~Company’s legacy acreage and the startup~~fourth quarter of ~~a one-rig non-operated program~~2021, with completions of those newly drilled wells to begin in the Company’s French Lake area in late 2020. However, due to the unprecedented drop in commodity prices that commenced in early March 2020, the Company updated its 2020 operating plan to reflect an anticipated 2020 capital budget of $80.0 million to $100.0 million. The Company’s reduced planned development activity included limited drilling and completion activity that concluded in March 2020, with a small amount of additional completion work done in July 2020. We now estimate our capital budget will be between $60.0 million and $70.0 million as our non-operated capital estimate has been reduced, and we continue to receive cost concessions from capital service providers.

~~Should commodity prices recover, and the economic returns justify resuming limited development activity, we will do so.~~2022. Actual capital expenditures could vary significantly based on, among other things, ~~changes in the operator’s development pace in French Lake,~~ market conditions, commodity prices, drilling and completion costs, and well results.

On April 1, 2021, we completed the previously announced acquisition of HighPoint. While we have already achieved significant synergies across several areas of the Company, there is an expected delay in realizing certain synergies and benefits due to the time and effort required to renegotiate and wait out certain contracts and integrate the formerly stand-alone companies. Consequently, the financial and operating results of the combined companies for the three and ~~changes~~six months ended June 30, 2021 reflect a slightly higher cost metric that we anticipate will decline during the latter half of 2021. Additionally, while the significant curtailment of the respective drilling and completion programs during 2020, in ~~the borrowing base under our Credit Facility.~~

~~In further~~ response to the drop in commodity prices, ~~our named executive officers and independent directors voluntarily reduced their compensation. Effective~~resulted in ~~early April 2020, our Chief Executive Officer’s salary was reduced by 12.5%,~~an overall decline in combined companies' sales volumes period over period, we expect sales volumes will recover considerably through 2021 completion activity as well as the ~~other named executive officers’ salaries were each reduced by 10%, and our independent directors’ base annual cash retainers were reduced by 15%. In addition,~~return of a drilling rig in the ~~Company completed a 12% reduction in its workforce during the second~~fourth quarter ~~which helped allow the Company to lower its 2020 recurring cash G&A guidance to a range~~ of ~~$27 million to $29 million, down 13% from $32 million in 2019.~~ 2021.

The Company has ~~also identified,~~successfully integrated the operations, production and ~~is implementing, approximately $8 million in LOE~~accounting databases derived from the HighPoint Merger. We believe that the Company has the appropriate level of skills and ~~RMI operating expense savings compared~~personnel to successfully integrate the ~~Company’s original 2020 plan.~~

XOG and Crestone Peak mergers. The go-forward Company will incorporate the best practices and processes from each organization.

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Results of Operations

The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:

Three Months Ended September 30,
2020 2019 Change Percent Change
Revenues (in thousands):
Crude oil sales(1)
$ 46,808 $ 65,623 $ (18,815) (29) %
Natural gas sales(2)
4,803 5,399 (596) (11) %
Natural gas liquids sales 5,866 2,587 3,279 127 %
Product revenue $ 57,477 $ 73,609 $ (16,132) (22) %
Sales Volumes:
Crude oil (MBbls) 1,284.0 1,277.8 6.2 — %
Natural gas (MMcf) 3,629.3 3,423.3 206.0 6 %
Natural gas liquids (MBbls) 524.9 385.2 139.7 36 %
Crude oil equivalent (MBoe)(3)
2,413.8 2,233.6 180.2 8 %
Average Sales Prices (before derivatives)(4):

Crude oil (per Bbl) $ 36.45 $ 51.36 $ (14.91) (29) %
Natural gas (per Mcf) $ 1.32 $ 1.58 $ (0.26) (16) %
Natural gas liquids (per Bbl) $ 11.18 $ 6.72 $ 4.46 66 %
Crude oil equivalent (per Boe)(3)
$ 23.81 $ 32.96 $ (9.15) (28) %
Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl) $ 43.59 $ 53.25 $ (9.66) (18) %
Natural gas (per Mcf) $ 1.18 $ 1.85 $ (0.67) (36) %
Natural gas liquids (per Bbl) $ 11.18 $ 6.72 $ 4.46 66 %
Crude oil equivalent (per Boe)(3)
$ 27.39 $ 34.47 $ (7.08) (21) %


	Three Months Ended June 30,
	2021		2020		Change		Percent Change
Revenues (in thousands):
Crude oil sales(1)	$	115,923	$	28,559	$	87,364	306	%
Natural gas sales(2)	14,778		3,931		10,847		276	%
Natural gas liquids sales	24,777		2,545		22,232		874	%
Product revenue	$	155,478	$	35,035	$	120,443	344	%

Sales Volumes:
Crude oil (MBbls)	1,905.2		1,274.1		631.1		50	%
Natural gas (MMcf)	6,405.6		3,298.7		3,106.9		94	%
Natural gas liquids (MBbls)	878.6		438.1		440.5		101	%
Crude oil equivalent (MBoe)(3)	3,851.4		2,262.0		1,589.4		70	%

Average Sales Prices (before derivatives):
Crude oil (per Bbl)	$	60.85	$	22.42	$	38.43	171	%
Natural gas (per Mcf)	$	2.31	$	1.19	$	1.12	94	%
Natural gas liquids (per Bbl)	$	28.20	$	5.81	$	22.39	385	%
Crude oil equivalent (per Boe)(3)	$	40.37	$	15.49	$	24.88	161	%

Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)	$	50.98	$	40.06	$	10.92	27	%
Natural gas (per Mcf)	$	2.09	$	1.23	$	0.86	70	%
Natural gas liquids (per Bbl)	$	28.20	$	5.81	$	22.39	385	%
Crude oil equivalent (per Boe)(3)	$	35.12	$	25.49	$	9.63	38	%

_____________________________

(1)Crude oil sales excludes ~~$0.4~~$0.2 million and ~~$0.6~~$0.4 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~2020, respectively.

(2)Natural gas sales excludes ~~$1.0~~$0.4 million and $0.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for ~~each of~~ the three months ended ~~September~~June 30, 2021 and 2020, ~~and 2019.~~respectively.

(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.

(4)Derivatives economically hedge the price we receive for crude oil and natural gas. For the three months ended ~~September~~June 30, 2021, the derivative cash settlement loss for oil and natural gas contracts was $18.8 million and $1.4 million, respectively. For the three months ended June 30, 2020, the derivative cash settlement gain for oil ~~contracts was $9.2 million,~~ and ~~the derivative cash settlement loss for~~ natural gas contracts was ~~$0.5 million. For the three months ended September 30, 2019, the derivative cash settlement gain for oil contracts was $2.4~~$22.5 million and ~~the derivative cash settlement gain for natural gas contracts was $0.9 million.~~$0.1 million, respectively. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.

Product revenues ~~decreased~~increased by ~~22%~~344% to ~~$57.5~~$155.5 million for the three months ended ~~September~~June 30, ~~2020~~2021 compared to ~~$73.6~~$35.0 million for the three months ended ~~September~~June 30, ~~2019.~~2020. The ~~primary driver~~drivers of the ~~decrease~~increase in revenue isare the ~~$9.15~~161%, or $24.88 per Boe, ~~or 28%, decrease~~increase in oil equivalent pricing ~~offset by an 8%~~and the 70% increase in sales volumes. The increase in sales volumes is primarily due to ~~turning 26~~the HighPoint Merger that closed on April 1, 2021. Additionally, we turned 30 gross wells to sales during the twelve-month period ending ~~September~~June 30, ~~2020.~~

2021.

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The following table summarizes our operating expenses for the periods indicated:

Three Months Ended September 30,
2020 2019 Change Percent Change
Expenses (in thousands):
Lease operating expense $ 5,393 $ 6,696 $ (1,303) (19) %
Midstream operating expense 3,970 3,271 699 21 %
Gathering, transportation, and processing 4,778 4,423 355 8 %
Severance and ad valorem taxes (7,063) 6,738 (13,801) (205) %
Exploration 66 33 33 100 %
Depreciation, depletion, and amortization 23,439 19,900 3,539 18 %
Abandonment and impairment of unproved properties 223 879 (656) (75) %
Bad debt expense 102 — 102 100 %
General and administrative expense 8,919 9,920 (1,001) (10) %
Operating Expenses $ 39,827 $ 51,860 $ (12,033) (23) %
Selected Costs ($ per Boe):
Lease operating expense $ 2.23 $ 3.00 $ (0.77) (26) %
Midstream operating expense 1.64 1.46 0.18 12 %
Gathering, transportation, and processing 1.98 1.98 — — %
Severance and ad valorem taxes (2.93) 3.02 (5.95) (197) %
Exploration 0.03 0.01 0.02 200 %
Depreciation, depletion, and amortization 9.71 8.91 0.80 9 %
Abandonment and impairment of unproved properties 0.09 0.39 (0.30) (77) %
Bad debt expense 0.04 — 0.04 100 %
General and administrative expense 3.70 4.44 (0.74) (17) %
Operating Expenses $ 16.49 $ 23.21 $ (6.72) (29) %


	Three Months Ended June 30,
	2021		2020		Change		Percent Change
Expenses (in thousands):
Lease operating expense	$	11,358	$	5,795	$	5,563	96	%
Midstream operating expense	4,246		3,354		892		27	%
Gathering, transportation, and processing	13,721		3,711		10,010		270	%
Severance and ad valorem taxes	9,813		3,478		6,335		182	%
Exploration	3,547		112		3,435		3,067	%
Depreciation, depletion, and amortization	35,006		22,283		12,723		57	%
Abandonment and impairment of unproved properties	2,215		309		1,906		617	%
Unused commitments	4,328		—		4,328		100	%

Merger transaction costs	18,246		21		18,225		86,786	%
General and administrative expense	12,144		8,385		3,759		45	%
Operating Expenses	$	114,624	$	47,448	$	67,176	142	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.95	$	2.56	$	0.39	15	%
Midstream operating expense	1.10		1.48		(0.38)		(26)	%
Gathering, transportation, and processing	3.56		1.64		1.92		117	%
Severance and ad valorem taxes	2.55		1.54		1.01		66	%
Exploration	0.92		0.05		0.87		1,740	%
Depreciation, depletion, and amortization	9.09		9.85		(0.76)		(8)	%
Abandonment and impairment of unproved properties	0.58		0.14		0.44		314	%
Unused commitments	1.12		—		1.12		100	%

Merger transaction costs	4.74		0.01		4.73		100	%
General and administrative expense	3.15		3.71		(0.56)		(15)	%
Operating Expenses	$	29.76	$	20.98	$	8.78	42	%

Lease operating expense. Our lease operating expense ~~decreased $1.3~~increased by $5.6 million, or ~~19%~~96%, to ~~$5.4~~$11.4 million for the three months ended ~~September~~June 30, ~~2020,~~2021 from ~~$6.7~~$5.8 million for the three months ended ~~September~~June 30, ~~2019,~~2020, and ~~decreased~~15% on aan equivalent basis per Boe basis by 26%. The overall decrease was primarily due to reductions in compression costs, pumping and gauging costs, and several other areas implemented by the Company in a concerted effort to reduce costs in response to the decline in commodity pricing.Boe. Lease operating expense ~~per unit decreased on~~increased as a ~~higher percentage basis due~~result of the HighPoint Merger, where there are synergies to ~~oil equivalent sales volumes being 8% higher in~~still be realized within the ~~later period.~~vehicle and compression fleet rentals, contract automation, and water disposal costs.

Midstream operating expense. Our midstream operating expense increased ~~$0.7 million~~ to ~~$4.0~~$4.2 million for the three months ended ~~September~~June 30, ~~2020, from $3.3~~2021 compared to $3.4 million for the three months ended ~~September~~June 30, ~~2019,~~2020, and ~~increased 12%~~decreased 26% on a per Boe basis during the comparable periods. The overall increase ~~was primarily~~is due to the acquisition of midstream assets as part of the HighPoint Merger. Additionally, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, ~~associated with the Company's new~~such as compression, are fixed and ~~expanded oil gathering line connected to the Riverside Terminal that came online during the three months ended September 30, 2019.~~thereby result in a decrease in midstream operating expense per Boe period over period.

Gathering, transportation, and processing. Gathering, transportation, and processing expense increased by ~~$0.4~~$10.0 million to ~~$4.8~~$13.7 million for the three months ended ~~September~~June 30, ~~2020,~~2021, from ~~$4.4~~$3.7 million for the three months ended ~~September~~June 30, ~~2019.~~2020. Natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing ~~expense. Although~~expense, and natural gas and NGLs sales volumes increased ~~18% between~~97% during the comparable ~~periods, a decline in fees on~~periods. Additionally, our value-based percentage of proceeds sales ~~contracts partially offset~~contract is now our largest sales contract post the ~~increase in gathering, transportation, and processing expense.~~HighPoint Merger.

Severance and ad valorem taxes. Our severance and ad valorem taxes ~~decreased~~increased to ~~a credit of $7.1~~$9.8 million for the three months ended ~~September~~June 30, ~~2020,~~2021, from ~~an expense of $6.7~~$3.5 million for the three months ended ~~September~~June 30, ~~2019.~~2020. Severance and ad valorem taxes primarily correlate to ~~revenues. Revenues decreased~~revenues, and revenues increased by ~~22%~~344% during the three months ended ~~September~~June 30, ~~2020~~2021 compared to the three months ended ~~September~~June 30, ~~2019. Additionally, we refined our tax estimate based on current mill levies, taxing districts, and company results based on commodity prices during~~2020. The HighPoint Merger has decreased the ~~third quarter 2020, which resulted in a one-time adjustment of $12.6 million. Excluding this adjustment, our~~Company's overall severance and ad valorem ~~taxes were $5.5 million for the three months ended September 30, 2020.~~tax rates, due to HighPoint having a substantial amount of wells in lower taxing districts.

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Exploration. Our exploration expense increased to $3.5 million for the three months ended June 30, 2021, from $0.1 million for the three months ended June 30, 2020 primarily due to a one-time purchase of seismic and core data.

Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased ~~18%~~57% to ~~$23.4~~$35.0 million for the three months ended ~~September~~June 30, ~~2020,~~2021, from ~~$19.9~~$22.3 million for the three months ended ~~September~~June 30, ~~2019,~~2020, and ~~increased 9%~~decreased 8% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the ~~three months ended September 30, 2020 when compared~~comparable periods is due to ~~the three months ended September 30, 2019 is the result of (i)~~ a ~~$145.0~~$629.2 million increase in the depletable property base ~~and (ii) an increase~~primarily due to the HighPoint Merger. The decrease on a per Boe basis is due to a decrease in the depletion ~~rate driven by the increase in production between the comparable periods.~~rate.

Abandonment and impairment of unproved properties. During the three months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~2020, the Company incurred ~~$0.2~~$2.2 million and ~~$0.9~~$0.3 million, respectively, in abandonment and impairment of unproved properties ~~costs~~primarily due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases.

Unused commitments. During the three months ended June 30, 2021 and 2020, we incurred $4.3 million and zero, respectively, in unused commitments. As part of the HighPoint Merger, we assumed two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.

Merger transaction costs. Our merger transaction costs increased by $18.2 million for the three months ended June 30, 2021 compared to the three months ended June 30, 2020 largely due to the HighPoint Merger and, to a lesser degree, the anticipated XOG and Crestone mergers.

General and administrative. Our general and administrative expense ~~decreased by $1.0 million or 10%~~ for the three months ended ~~September~~June 30, ~~2020,~~2021 increased to $12.1 million compared to ~~the~~$8.4 million for three months ended ~~September~~June 30, ~~2019,~~2020, and decreased by ~~17%~~15% on a per Boe ~~basis between~~basis. The primary drivers of the ~~comparable periods. The decrease in general and administrative expense is primarily due~~increase relate to ~~a decrease~~an increase in salaries, benefits, and stock compensation expense due to ~~our reduced workforce, partially offset by advisor~~the HighPoint Merger. Additionally, certain one-time nonrecurring fees ~~and severance costs totaling $1.0 million.~~were incurred as it relates to the HighPoint Merger as further discussed in Note 3 - Acquisitions & Divestitures of Part I, Item 1 of this report. General and administrative expense per Boe decreased ~~on a higher percentage basis~~ due to ~~oil equivalent~~ sales volumes being 8%70% higher during the three months ended ~~September~~June 30, ~~2020~~2021 as compared to the same period in ~~2019.~~2020.

Derivative gain (loss). Our derivative loss for the three months ended ~~September~~June 30, ~~2020~~2021 was ~~$10.7~~$74.0 million ~~as compared~~is due to asettlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Our derivative ~~gain~~loss of ~~$12.9~~$25.1 million for the three months ended ~~September~~June 30, ~~2019. Our derivative loss~~2020 is due to fair market value adjustments caused by market prices recovering from prior period levels, partially offset by settlement gains caused by market prices being lower than our contracted hedge prices. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.

Interest expense. Our interest expense for the three months ended ~~September~~June 30, 2021 and 2020 ~~and 2019~~ was ~~$0.4~~$3.2 million and ~~$0.3~~$1.0 million, respectively. Average debt outstanding for the three months ended ~~September~~June 30, 2021 and 2020 ~~and 2019~~ was ~~$54.1~~$123.2 million and ~~$84.9~~$63.7 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):

Three Months Ended September 30,
2020 2019
Credit Facility $ 334 $ 921
Commitment fees on available borrowing base under the Credit Facility 264 254
Amortization of deferred financing costs 92 123
Capitalized interest (334) (976)
Total interest expense, net $ 356 $ 322


	Three Months Ended June 30,
	2021		2020
Senior Notes	$	1,875	$	—
Credit Facility	1,160		557
Commitment fees on available borrowing base under the Credit Facility	329		270
Amortization of deferred financing costs	433		557
Capitalized interest	(556)		(400)
Total interest expense, net	$	3,241	$	984

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The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:


		Nine Months Ended September 30,									Six Months Ended June 30,
		2020		2019		Change		Percent Change			2021		2020		Change		Percent Change
Revenues (in thousands):	Revenues (in thousands):									Revenues (in thousands):
Crude oil sales(1)	Crude oil sales(1)	$	125,956	$	200,153	$	(74,197)	(37)	%	Crude oil sales(1)	$	165,723	$	79,148	$	86,575	109	%
Natural gas sales(2)	Natural gas sales(2)	13,696		17,800		(4,104)		(23)	%	Natural gas sales(2)	27,064		8,893		18,171		204	%
Natural gas liquids sales	Natural gas liquids sales	11,652		11,195		457		4	%	Natural gas liquids sales	35,740		5,786		29,954		518	%
Product revenue	Product revenue	$	151,304	$	229,148	$	(77,844)	(34)	%	Product revenue	$	228,527	$	93,827	$	134,700	144	%

Sales Volumes:	Sales Volumes:									Sales Volumes:
Crude oil (MBbls)	Crude oil (MBbls)	3,787.6		3,859.8		(72.2)		(2)	%	Crude oil (MBbls)	2,847.9		2,503.6		344.3		14	%
Natural gas (MMcf)	Natural gas (MMcf)	10,490.6		8,524.7		1,965.9		23	%	Natural gas (MMcf)	9,619.5		6,861.3		2,758.2		40	%
Natural gas liquids (MBbls)	Natural gas liquids (MBbls)	1,399.9		1,042.2		357.7		34	%	Natural gas liquids (MBbls)	1,276.7		875.0		401.7		46	%
Crude oil equivalent (MBoe)(3)	Crude oil equivalent (MBoe)(3)	6,935.9		6,322.8		613.1		10	%	Crude oil equivalent (MBoe)(3)	5,727.9		4,522.1		1,205.8		27	%

Average Sales Prices (before derivatives)(4):
Average Sales Prices (before derivatives):										Average Sales Prices (before derivatives):
Crude oil (per Bbl)	Crude oil (per Bbl)	$	33.25	$	51.86	$	(18.61)	(36)	%	Crude oil (per Bbl)	$	58.19	$	31.61	$	26.58	84	%
Natural gas (per Mcf)	Natural gas (per Mcf)	$	1.31	$	2.09	$	(0.78)	(37)	%	Natural gas (per Mcf)	$	2.81	$	1.30	$	1.51	116	%
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	$	8.32	$	10.74	$	(2.42)	(23)	%	Natural gas liquids (per Bbl)	$	27.99	$	6.61	$	21.38	323	%
Crude oil equivalent (per Boe)(3)	Crude oil equivalent (per Boe)(3)	$	21.81	$	36.24	$	(14.43)	(40)	%	Crude oil equivalent (per Boe)(3)	$	39.90	$	20.75	$	19.15	92	%

Average Sales Prices (after derivatives)(4):	Average Sales Prices (after derivatives)(4):									Average Sales Prices (after derivatives)(4):
Crude oil (per Bbl)	Crude oil (per Bbl)	$	44.37	$	52.77	$	(8.40)	(16)	%	Crude oil (per Bbl)	$	50.60	$	44.76	$	5.84	13	%
Natural gas (per Mcf)	Natural gas (per Mcf)	$	1.34	$	2.12	$	(0.78)	(37)	%	Natural gas (per Mcf)	$	2.57	$	1.43	$	1.14	80	%
Natural gas liquids (per Bbl)	Natural gas liquids (per Bbl)	$	8.32	$	10.74	$	(2.42)	(23)	%	Natural gas liquids (per Bbl)	$	27.99	$	6.61	$	21.38	323	%
Crude oil equivalent (per Boe)(3)	Crude oil equivalent (per Boe)(3)	$	27.94	$	36.84	$	(8.90)	(24)	%	Crude oil equivalent (per Boe)(3)	$	35.71	$	28.24	$	7.47	26	%

_____________________________

(1)Crude oil sales excludes ~~$1.4~~$0.5 million and ~~$1.8~~$1.0 million of oil transportation revenues from third parties, which do not have associated sales volumes, for of the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~2020, respectively.

(2)Natural gas sales excludes ~~$2.8~~$1.2 million and ~~$2.6~~$1.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019,~~2020, respectively.

(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.

(4)Derivatives economically hedge the price we receive for crude oil and natural gas. For the ~~nine~~six months ended ~~September~~June 30, 2021, the derivative cash settlement loss for oil and natural gas contracts was $21.6 million and $2.4 million, respectively. For the six months ended June 30, 2020, the derivative cash settlement gain for oil ~~contracts was $42.1 million,~~ and ~~the derivative cash settlement gain for~~ natural gas contracts was ~~$0.4 million. For the nine months ended September 30, 2019, the derivative cash settlement gain for oil contracts was $3.5~~$32.9 million and ~~the derivative cash settlement gain for natural gas contracts was $0.2 million.~~$0.9 million, respectively. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional disclosures.

Product revenues ~~decreased~~increased by ~~34%~~144% to ~~$151.3~~$228.5 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 compared to ~~$229.1~~$93.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. The primary ~~driver~~drivers of the ~~decrease~~increase in revenue isare the ~~40%~~92%, or ~~$14.43~~$19.15 per Boe, ~~decrease~~increase in oil equivalent pricing ~~offset by an 10%~~and the 27% increase in sales volumes. The increase in sales volumes is due to turning 2630 gross wells to sales during the twelve-month period ending ~~September~~June 30, ~~2020.~~2021 as well as the HighPoint Merger that closed on April 1, 2021.

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The following table summarizes our operating expenses for the periods indicated:

Nine Months Ended September 30,
2020 2019 Change Percent Change
Expenses (in thousands):
Lease operating expense $ 16,887 $ 18,512 $ (1,625) (9) %
Midstream operating expense 11,338 8,301 3,037 37 %
Gathering, transportation, and processing 11,970 12,776 (806) (6) %
Severance and ad valorem taxes 1,588 18,697 (17,109) (92) %
Exploration 551 538 13 2 %
Depreciation, depletion, and amortization 67,306 54,557 12,749 23 %
Abandonment and impairment of unproved properties 30,589 2,636 27,953 1,060 %
Bad debt expense 678 — 678 100 %
General and administrative expense 26,754 30,001 (3,247) (11) %
Operating Expenses $ 167,661 $ 146,018 $ 21,643 15 %
Selected Costs ($ per Boe):
Lease operating expense $ 2.43 $ 2.93 $ (0.50) (17) %
Midstream operating expense 1.63 1.31 0.32 24 %
Gathering, transportation, and processing 1.73 2.02 (0.29) (14) %
Severance and ad valorem taxes 0.23 2.96 (2.73) (92) %
Exploration 0.08 0.09 (0.01) (11) %
Depreciation, depletion, and amortization 9.70 8.63 1.07 12 %
Abandonment and impairment of unproved properties 4.41 0.42 3.99 950 %
Bad debt expense 0.10 — 0.10 100 %
General and administrative expense 3.86 4.74 (0.88) (19) %
Operating Expenses $ 24.17 $ 23.10 $ 1.07 5 %


	Six Months Ended June 30,
	2021		2020		Change		Percent Change
Expenses (in thousands):
Lease operating expense	$	17,089	$	11,494	$	5,595	49	%
Midstream operating expense	8,151		7,368		783		11	%
Gathering, transportation, and processing	18,688		7,192		11,496		160	%
Severance and ad valorem taxes	14,417		8,651		5,766		67	%
Exploration	3,643		485		3,158		651	%
Depreciation, depletion, and amortization	53,829		43,867		9,962		23	%
Abandonment and impairment of unproved properties	2,215		30,366		(28,151)		(93)	%
Unused commitments	4,328		—		4,328		100	%
Bad debt expense	—		576		(576)		(100)	%
Merger transaction costs	21,541		21		21,520		102,476	%
General and administrative expense	21,395		17,814		3,581		20	%
Operating Expenses	$	165,296	$	127,834	$	37,462	29	%

Selected Costs ($ per Boe):
Lease operating expense	$	2.98	$	2.54	$	0.44	17	%
Midstream operating expense	1.42		1.63		(0.21)		(13)	%
Gathering, transportation, and processing	3.26		1.59		1.67		105	%
Severance and ad valorem taxes	2.52		1.91		0.61		32	%
Exploration	0.64		0.11		0.53		482	%
Depreciation, depletion, and amortization	9.40		9.70		(0.30)		(3)	%
Abandonment and impairment of unproved properties	0.39		6.72		(6.33)		(94)	%
Unused commitments	0.76		—		0.76		100	%
Bad debt expense	—		0.13		(0.13)		(100)	%
Merger transaction costs	3.76		—		3.76		100	%
General and administrative expense	3.74		3.94		(0.20)		(5)	%
Operating Expenses	$	28.87	$	28.27	$	0.60	2	%

Lease operating expense. Our lease operating expense ~~decreased $1.6 million, or 9%,~~increased 49% to ~~$16.9~~$17.1 million for the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020 ~~from $18.5 million for the nine months ended September 30, 2019,~~ and increased 17% on an equivalent basis per Boe. Aggregate lease operating expense increased as a ~~per Boe basis. The overall decrease was primarily due to lower pumping and gauging costs, compression costs, equipment rentals, and several other areas implemented by~~result of the ~~Company in a concerted effort to reduce costs in response to the decline in commodity pricing, partially offset by an increase in salt water disposal costs.~~HighPoint Merger. Lease operating expense ~~per unit decreased on~~increased as a ~~higher percentage basis due~~result of the HighPoint Merger, where there are synergies to ~~oil equivalent sales volumes being 10% higher in~~still be realized within the ~~later period.~~vehicle and compression fleet rentals, contract automation, and water disposal costs.

Midstream operating expense. Our midstream operating expense ~~increased $3.0 million to $11.3~~remained relatively consistent at $8.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020, from $8.3~~2021 compared to $7.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, and ~~increased 24%~~decreased 13% on a per Boe basis during the comparable periods. The overall increase ~~was primarily~~is due to the acquisition of midstream assets as part of the HighPoint Merger. Additionally, while certain midstream operating expenses correlate to sales volumes, the majority of the costs, ~~associated with the Company's new~~such as compression, are fixed and ~~expanded oil gathering line connected to the Riverside Terminal that came online during the third quarter of 2019.~~result in a decrease in midstream operating expense per Boe period over period.

Gathering, transportation, and processing. Gathering, transportation, and processing expense ~~decreased~~increased by ~~$0.8~~$11.5 million, or 160%, to ~~$12.0~~$18.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, from ~~$12.8~~$7.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019. Natural~~2020. Generally, natural gas and NGLs sales volumes have a direct correlation to gathering, transportation, and processing expense. ~~Although natural~~Natural gas and NGLs sales volumes increased ~~28%~~43% during the ~~nine months ended September 30, 2020 as compared to~~comparable periods. Additionally, our value-based percentage of proceeds sales contract is now our largest sales contract post the ~~nine months ended September 30, 2019, a decline in fees on sales contracts contributed to the overall decrease in gathering, transportation, and processing expense.~~HighPoint Merger.

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Severance and ad valorem taxes. Our severance and ad valorem taxes ~~decreased 92%~~increased 67% to ~~$1.6~~$14.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, from ~~$18.7~~$8.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. Severance and ad valorem taxes primarily correlate to ~~revenues. Revenues decreased~~revenues, and revenues increased by ~~34%~~144% during the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019. Additionally, we refined our tax estimate based on current mill levies, taxing districts, and company results based on commodity prices during~~2020. The HighPoint Merger has decreased the ~~third quarter 2020, which resulted in a one-time adjustment of $12.6 million. Excluding this adjustment, our~~Company's overall severance and ad valorem ~~taxes were $14.2~~tax rates due to HighPoint having a substantial amount of wells in lower taxing districts.

Exploration. Our exploration expense increased to $3.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020.~~

~~Table~~2021, from $0.5 million for the six months ended June 30, 2020 primarily due to a one-time purchase of ~~Contents~~seismic and core data.

Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense increased 23% to ~~$67.3~~$53.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, from ~~$54.6~~$43.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, and ~~increased 12%~~decreased 3% on a per Boe basis during the comparable periods. The increase in depreciation, depletion, and amortization expense during the ~~nine months ended September 30, 2020 when compared~~comparable periods is due to ~~the nine months ended September 30, 2019 is the result of (i)~~ a ~~$145.0~~$629.2 million increase in the depletable property base ~~and (ii) an increase~~primarily due to the HighPoint Merger. The decrease on a per Boe basis is due to a decrease in the depletion ~~rate driven by an 10% increase in production between the comparable periods.~~rate.

Abandonment and impairment of unproved properties. During the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020, the Company incurred ~~$30.6~~$2.2 million and $30.4 million, respectively, in abandonment and impairment of unproved properties ~~costs~~ primarily due to the reassessment of estimated probable and possible reserve locations based primarily upon economic ~~viability. In addition, during the nine months ended September 30, 2019, the Company incurred $2.6 million in abandonment~~viability and ~~impairment of unproved properties costs due to~~ the expiration of non-core leases.

~~Bad debt expense.~~Unused commitments. During the six months ended June 30, 2021 and 2020, we incurred $4.3 million and zero, respectively, in unused commitments. As part of the HighPoint Merger, we assumed two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from properties HighPoint had previously sold. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.

Merger transaction costs. Our ~~bad debt expense~~merger transaction costs increased ~~100% to $0.7~~by $21.5 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019. The increase is~~2020 largely due to the ~~establishment of an allowance against our joint interest receivable, which have greater recoverability risk~~HighPoint Merger and, to a lesser degree, due to the ~~deterioration of commodity prices.~~anticipated XOG and Crestone mergers.

General and administrative. Our general and administrative expense ~~decreased by $3.2 million or 11%~~ for the ~~nine~~six months ended ~~September~~June 30, 2021 increased to $21.4 million, from $17.8 million for the six months ended June 30, 2020, ~~compared to the nine months ended September 30, 2019,~~ and decreased ~~by 19%~~5% on a per Boe basis. The ~~decrease in general and administrative expense between~~primary drivers of the ~~comparable periods is primarily due~~increase relate to ~~a decrease~~an increase in salaries, benefits, and stock compensation expense due to ~~our reduced workforce, partially offset by increased advisor~~the HighPoint Merger. Additionally, certain one-time nonrecurring fees ~~and severance costs totaling $1.8 million.~~were incurred as it relates to the HighPoint Merger as further discussed in Note 3 - Acquisitions & Divestitures of Part I, Item 1 of this report. General and administrative expense per Boe decreased ~~on a higher percentage basis~~ due to ~~oil equivalent~~ sales volumes being ~~10%~~27% higher ~~during~~in the ~~nine months ended September 30, 2020~~later period as ~~compared to~~a result of the ~~same period in 2019.~~HighPoint Merger.

Derivative gain (loss). Our derivative ~~gain~~loss for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 was ~~$64.6~~$97.4 million ~~as compared~~due to asettlements and fair market value adjustments caused by market prices being higher than our contracted hedge prices. Our derivative ~~loss~~gain of ~~$15.5~~$75.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019. Our derivative gain~~2020 is due to settlements and fair market value adjustments caused by market prices being lower than our contracted hedge prices. Please refer to Note 10 - Derivatives of Part I, Item 1 of this report for additional discussion.

Interest expense. Our interest expense for the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020 ~~and 2019~~ was ~~$1.6~~$3.7 million and ~~$1.9~~$1.2 million, respectively. Average debt outstanding for the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020 ~~and 2019~~ was ~~$67.5~~$61.9 million and ~~$71.6~~$74.3 million, respectively. The components of interest expense for the periods presented are as follows (in thousands):


		Nine Months Ended September 30,					Six Months Ended June 30,
		2020		2019			2021		2020
Senior Notes						Senior Notes	$	1,875	$	—
Credit Facility	Credit Facility	$	1,701	$	2,433	Credit Facility	1,160		1,367
Commitment fees on available borrowing base under the Credit Facility	Commitment fees on available borrowing base under the Credit Facility	785		792		Commitment fees on available borrowing base under the Credit Facility	655		521
Amortization of deferred financing costs	Amortization of deferred financing costs	772		371		Amortization of deferred financing costs	526		680
Capitalized interest	Capitalized interest	(1,701)		(1,738)		Capitalized interest	(556)		(1,367)
Total interest expense, net	Total interest expense, net	$	1,557	$	1,858	Total interest expense, net	$	3,660	$	1,201

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Liquidity and Capital Resources

The Company's anticipated sources of liquidity include cash from operating activities, borrowings under the Credit Facility, proceeds from sales of assets, and potential proceeds from capital and/or debt markets. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and other supply chain dynamics, among other factors. To mitigate some of the pricing risk, as of June 30, 2021, we have hedged approximately ~~100%~~12,250 Bbls per day for the remainder of 2021, representing almost 60% of our ~~average 2020 guided~~ oil ~~production hedged as of September~~sales volume during the three months ended June 30, 2020 and as of the filing date of this report. Consequently, the value of our commodity contracts as of September 30, 2020 was a net asset of $19.0 million. Additionally, in light of the recent suspension of drilling activities, we intend to pay down our Credit Facility to an undrawn balance by December 31, 2020 using net cash provided by operating activities.2021.

As of ~~September~~June 30, ~~2020,~~2021, our liquidity was ~~$243.8~~$325.4 million, consisting of ~~$3.8~~$24.4 million of cash on hand and ~~$240.0~~$301.0 million of available borrowing capacity on the Credit Facility.

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We anticipate and are on track to achieve a capital program of approximately $60.0 million to $70.0 million during 2020, which will allow us to maintain our reserve base while maintaining approximately flat production.

Our weighted-average interest rate on borrowings from the Credit Facility was ~~2.41%~~3.6% for the three months ended ~~September~~June 30, ~~2020.~~2021. As of ~~September~~June 30, ~~2020~~2021 and the date of this filing, we had ~~$20.0~~$99.0 million and ~~$10.0~~$85.0 million, respectively, outstanding on our Credit Facility.

On April 1, 2021, in conjunction with the HighPoint Merger, the Company, together with certain of its subsidiaries, entered into the Second Amendment to the Credit Facility. Please refer to Note 3 - Acquisitions and Divestitures under Part I, Item 1 for additional information.

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

Nine Months Ended September 30,
2020 2019
Net cash provided by operating activities $ 111,444 $ 163,008
Net cash used in investing activities (57,509) (196,226)
Net cash provided by (used in) financing activities (61,158) 28,674
Cash, cash equivalents, and restricted cash 3,872 8,458
Acquisition of oil and gas properties (853) (12,968)
Exploration and development of oil and gas properties (56,216) (184,119)


	Six Months Ended June 30,
	2021		2020
Net cash provided by operating activities	$	79,559	$	68,229
Net cash used in investing activities	(8,029)		(52,019)
Net cash used in financing activities	(71,870)		(23,067)
Cash, cash equivalents, and restricted cash	24,505		4,238
Acquisition of oil and gas properties	(549)		(549)
Exploration and development of oil and gas properties	(57,269)		(51,054)

Cash flows provided by operating activities

Our cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 include cash receipts and disbursements attributable to our normal operating cycle. See Results of Operations above for more information on the factors driving these changes.

Cash flows used in investing activities

Expenditures for development of oil and natural gas properties are the primary use of our capital resources. The Company spent ~~$56.2~~$57.3 million and ~~$184.1~~$51.1 million on the exploration and development of oil and gas properties during the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020, ~~and 2019,~~ respectively. ~~The decrease in capital expenditures between~~Partially offsetting these cash outflows for the periods is primarily due to reduced drilling and completion activity in response to the unprecedented drop in commodity prices between the comparable periods. The Company also spent $12.1 million less on acquisitions of oil and gas properties during the ninesix months ended ~~September~~June 30, ~~2020 when compared to~~2021 is the ~~same period in 2019.~~$49.8 million of cash acquired through the HPR Merger.

Cash flows provided by financing activities

Net cash used in financing activities for the ~~nine~~six months ended ~~September~~June 30, 2021 and 2020 was ~~$61.2~~$71.9 million ~~compared to cash provided by financing activities for the nine months ended September 30, 2019 of $28.7 million.~~and $23.1 million, respectively. The change was primarily due to a ~~$90~~$33.0 million increase in net payments on our Credit Facility between the comparable ~~periods.~~periods as well as the $10.8 million dividend that was declared and paid in June 2021.

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Non-GAAP Financial Measures

Adjusted EBITDAX represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we present because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, and acquisitions and to service debt. We are also subject to financial covenants under our Credit Facility based on adjusted EBITDAX ratios as further described Note 5 - Long-Term Debt in Part I, Item I of this document. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all, items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.

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The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX (in thousands):


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Net income		$	3,251	$	35,893	$	42,900	$	69,922
Net income (loss)										Net income (loss)	$	(25,319)	$	(38,902)	$	(25,438)	$	39,649
Exploration	Exploration	66		33		551		538		Exploration	3,547		112		3,643		485
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	23,439		19,900		67,306		54,557		Depreciation, depletion, and amortization	35,006		22,283		53,829		43,867
Amortization of deferred financing costs		—		—		—		248
Abandonment and impairment of unproved properties	Abandonment and impairment of unproved properties	223		879		30,589		2,636		Abandonment and impairment of unproved properties	2,215		309		2,215		30,366
Unused commitments										Unused commitments	4,328		—		4,328		—
Stock-based compensation (1)	Stock-based compensation (1)	1,723		2,041		4,436		5,189		Stock-based compensation (1)	2,195		1,474		3,807		2,713
Severance costs (1)		140		—		1,337		418
Advisor fees (1)		888		—		909		—
Non-recurring general and administrative expense (1)										Non-recurring general and administrative expense (1)	1,294		784		1,294		1,197
Merger transaction costs										Merger transaction costs	18,246		21		21,541		21
Loss on property transactions, net	Loss on property transactions, net	—		—		1,398		306		Loss on property transactions, net	—		1,398		—		1,398
Interest expense, net	Interest expense, net	356		322		1,557		1,858		Interest expense, net	3,241		984		3,660		1,201
Severance and ad valorem taxes adjustment (2)		(12,586)		—		(12,586)		—

Derivative (gain) loss	Derivative (gain) loss	10,670		(12,894)		(64,603)		15,477		Derivative (gain) loss	73,970		25,146		97,389		(75,273)
Derivative cash settlements		8,627		3,373		42,494		3,766
Income tax expense		4,689		—		4,689		—
Derivative cash settlements gain (loss)										Derivative cash settlements gain (loss)	(20,199)		22,613		(23,990)		33,867
Income tax benefit										Income tax benefit	(10,392)		—		(10,436)		—
Adjusted EBITDAX	Adjusted EBITDAX	$	41,486	$	49,547	$	120,977	$	154,915	Adjusted EBITDAX	$	88,132	$	36,222	$	131,842	$	79,491
_______________________________
_____________________________										_____________________________
(1) Included as a portion of general and administrative expense in the accompanying statements of operations.	(1) Included as a portion of general and administrative expense in the accompanying statements of operations.									(1) Included as a portion of general and administrative expense in the accompanying statements of operations.
(2) Included as a portion of severance and ad valorem taxes in the accompanying statements of operations.	(2) Included as a portion of severance and ad valorem taxes in the accompanying statements of operations.									(2) Included as a portion of severance and ad valorem taxes in the accompanying statements of operations.

New Accounting Pronouncements

Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this report for any recently issued or adopted accounting standards.

Critical Accounting Policies and Estimates

Information regarding our critical accounting policies and estimates is contained in Part II, Item 7 of our ~~2019~~2020 Form 10-K.

~~Off-Balance Sheet Arrangements~~

~~Currently, we do not have any off-balance sheet arrangements that are not disclosed within this report.~~

~~Contractual Obligations~~Material Commitments

There have been no significant changes from our ~~2019~~2020 Form 10-K in our obligations and commitments, other than what is disclosed within Note 34 - Leases and Note 6 - Commitments and Contingenciesunder Part I, Item 1 of this report.

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Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation, or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

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These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements include statements related to, among other things:

•the Company's business strategies;

•reserves estimates;

•estimated sales volumes;

•amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;

•ability to modify future capital expenditures;

•anticipated costs;

•compliance with debt covenants;

•ability to fund and satisfy obligations related to ongoing operations;

•compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;

•adequacy of gathering systems and continuous improvement of such gathering systems;

•impact from the lack of available gathering systems and processing facilities in certain areas;

•impact of any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;

•natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;

•impact of lower commodity prices;

•sufficiency of impairments;

•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;

•our drilling inventory and drilling intentions;

•impact of potentially disruptive technologies;

•our estimated revenue gains and losses;

•the timing and success of specific projects;

•our implementation of standard and long reach laterals;

•our use of multi-well pads to develop the Niobrara and Codell formations;

•intention to continue to optimize enhanced completion techniques and well design changes;

•stated working interest percentages;

•management and technical team;

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•outcomes and effects of litigation, claims, and disputes;

•primary sources of future production growth;

•full delineation of the Niobrara B, C, and Codell benches in our legacy, French Lake, and northern acreage;

•our ability to replace oil and natural gas reserves;

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•our ability to convert ~~PUDs~~proved undeveloped reserves to producing properties within five years of their initial proved booking;

•impact of recently issued accounting pronouncements;

•impact of the loss a single customer or any purchaser of our products;

•timing and ability to meet certain volume commitments related to purchase and transportation agreements;

•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;

•our financial position;

•our cash flow and liquidity;

•the adequacy of our insurance;

•the expected timetable for completing the XOG Merger and the Crestone Peak Merger, the results, effects, benefits and synergies of the mergers, future opportunities for the combined company, other plans and expectations with respect to the mergers, and the anticipated impact of the mergers on the combined company’s results of operations, financial position, growth opportunities and competitive position; and

•other statements concerning our operations, economic performance, and financial condition.

We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.

Factors that could cause actual results to differ materially include, but are not limited to, the following:

•the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 and in Part II, Item 1A of this report;

•further declines or volatility in the prices we receive for our oil, natural gas liquids, and natural gas;

•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

•the effects of disruption of our operations or excess supply of oil and natural gas due to the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;

•the scope, duration and severity of the COVID-19 pandemic, including any recurrence, as well as the timing of the economic recovery following the pandemic;

•ability of our customers to meet their obligations to us;

•our access to capital;

•our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions;

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•the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;

•uncertainties associated with estimates of proved oil and gas reserves;

•the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);

•environmental risks;

•seasonal weather conditions;

•lease stipulations;

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•drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;

•our ability to acquire adequate supplies of water for drilling and completion operations;

•availability of oilfield equipment, services, and personnel;

•exploration and development risks;

•operational interruption of centralized gas and oil processing facilities;

•competition in the oil and natural gas industry;

•management’s ability to execute our plans to meet our goals;

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

•our ability to maintain effective internal controls;

•access to adequate gathering systems and pipeline take-away capacity;

•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;

•costs and other risks associated with perfecting title for mineral rights in some of our properties;

•continued hostilities in the Middle East, South America, and other sustained military campaigns or acts of terrorism or sabotage; and

•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.

All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Oil and Natural Gas Price Risk

Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities.

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Commodity Derivative Contracts

Our primary commodity risk management objective is to protect the Company’s balance sheet via the reduction in cash flow volatility. We enter into derivative contracts for oil, natural gas, and natural gas liquids using NYMEX futures or over-the-counter derivative financial instruments. The types of derivative instruments that we use include swaps, collars, and puts.

Upon settlement of the contract(s), if the relevant market commodity price exceeds our contracted swap price, or the collar’s ceiling strike price, we are required to pay our counterparty the difference for the volume of production associated with the contract. Generally, this payment is made up to 15 business days prior to the receipt of cash payments from our customers. This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned.

While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable commodity price changes.

Presently, our derivative contracts have been executed with ~~seven~~eight counterparties, all of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.

Please refer to the Note 10 - Derivatives in Part I, Item 1 of this report for summary derivative activity tables.

Interest Rates

As of ~~September~~both June 30, ~~2020~~2021 and the filing date of this report, we had ~~$20.0~~$99.0 million and ~~$10.0~~$85.0 million, respectively, outstanding under our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. As of ~~September~~June 30, ~~2020,~~2021, and through the filing date of this report, the Company was in compliance with all financial and non-financial covenants in the Credit Facility.

Counterparty and Customer Credit Risk

In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. ~~Seven~~Eight members of our Credit Facility syndicate are counterparties on our derivative instruments currently in place and currently have investment grade credit ratings.

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.

Marketability of Our Production

The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional trucking, pipeline, and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced through trucking services, pipelines, and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

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A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, weather, or field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

Currently, there are no pipeline systems that service wells in our French Lake area of the Wattenberg Field. If neither we nor a third-party constructs the required pipeline system, we may not be able to fully test or develop our resources in French Lake.

There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2019.~~2020.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of ~~September~~June 30, ~~2020.~~2021. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers and internal audit function, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of ~~September~~June 30, ~~2020,~~2021, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms, and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended ~~September~~June 30, ~~2020~~2021 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

~~From time to time, we are subject to~~Information regarding our legal proceedings and claims that arise in the ordinary course of business. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health, and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there were no probable, material pending or overtly threatened legal actions against us of which we were aware.

~~As described above~~can be found in Note 6 –- Commitments and Contingencies~~, the litigation claims brought against the Company by WildEarth Guardians have been dismissed with prejudice~~ of Part I, Item 1 of this report

~~There have been no other material changes to our legal proceedings from those described in our Annual Report on Form 10-K for the year ended December 31, 2019.~~.

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Item 1A. Risk Factors.

Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, ~~2019,~~2020, together with other information in this report and other reports and materials we file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

~~The extent~~Risks Relating to ~~which~~ the ~~COVID-19 outbreak impacts our business, results of operations,~~XOG Merger and ~~financial condition will depend on future developments, which cannot be predicted.~~the Crestone Peak Merger

The ~~outbreak~~XOG Merger and the Crestone Peak Merger are subject to a number of ~~COVID-19,~~regulatory approvals and conditions to the obligations of the parties, which ~~has been declared~~may delay the XOG Merger, the Crestone Peak Merger or both, result in additional expenditures of money and resources, or reduce the anticipated benefits or result in termination of the XOG Merger Agreement, the Crestone Peak Merger Agreement, or both.

The completion of the XOG Merger and the Crestone Peak Merger are subject to antitrust review in the United States. The waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, expired for the XOG Merger on June 21, 2021 and for the Crestone Peak Merger on July 26, 2021. Nevertheless, the DOJ or the FTC, or any state, could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the completion of the XOG Merger, the Crestone Peak Merger or both. Private parties may also seek to take legal action under the antitrust laws under certain circumstances.

Our obligations and the obligations of XOG and Crestone Peak to consummate the XOG Merger and the Crestone Peak Merger, respectively, are subject to the satisfaction (or waiver by all parties, to the ~~World Health Organization~~extent permissible under applicable laws) of a number of conditions described in the XOG Merger Agreement and the Crestone Peak Merger Agreement, including the approval of the XOG Merger by our and the XOG stockholders and the approval of the Crestone Peak Merger by our stockholders. Many of the conditions to completion of the XOG Merger and the Crestone Peak Merger are not within our control and we cannot predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the outside date, as such term is defined in the XOG and Crestone Peak Merger Agreements, it is possible that the XOG Merger Agreement, the Crestone Peak Merger Agreement or both may be terminated.

Although the parties have agreed to use reasonable best efforts, subject to certain limitations, to complete the XOG Merger and the Crestone Peak Merger as promptly as practicable, these and other conditions may fail to be satisfied. In addition, completion of each merger may take longer, and could cost more, than we expect. The requirements for obtaining the required clearances and approvals could delay the completion of the XOG Merger, the Crestone Peak Merger or both for a pandemic, has spread across the globe and is impacting worldwide economic activity, including the global demand for oil and natural gas. Any pandemic or other public health epidemic, including COVID-19, poses the risk that we or our employees, vendors, suppliers, customers, and other business partners may be prevented from conducting business activities for an indefinitesignificant period of time ~~due~~or prevent them from occurring. Any delay in completing the XOG Merger or the Crestone Peak Merger may adversely affect the cost savings and other benefits that we expect to achieve if the ~~potential spread~~XOG Merger and the Crestone Peak Merger and the integration of businesses are completed within the expected timeframe.

Each of the ~~disease within these groups or due~~XOG Merger Agreement and the Crestone Peak Merger Agreement subject us to restrictions that may be requested or mandated by governmental authorities, including quarantines of certain geographic areas, restrictions on travel, and other restrictions that prohibit employees from going to work. To date, the COVID-19 outbreak has surfaced in all regions around the world and has severely impacted the global economy, disrupted consumer spending and global supply chains, and created significant volatility and disruption of financial markets, all of which are expected to continue.

The COVID-19 pandemic has caused us to modify our business practices (including employee travel, employee work locations, and cancellation of physical participation in meetings, events, and conferences), and we may take further actions as may be required by government authorities or that we determine are in the best interests of our employees, vendors, suppliers, customers, and other business partners. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus or otherwise be satisfactory to government authorities.

The extent to which COVID-19 impacts our business, results of operations, and financial condition will depend on future developments, which are uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, and how quickly and to what extent normal economic and operating conditions can resume. If COVID-19 continues to spread or the response to contain COVID-19 is unsuccessful, we could experience a material adverse effect on our business ~~financial condition,~~activities prior to closing the XOG Merger and ~~results~~the Crestone Peak Merger, respectively.

Each of ~~operations. Even after~~ the ~~coronavirus outbreak has subsided, we may continue~~XOG Merger Agreement and the Crestone Peak Merger Agreement subject us to ~~experience materially adverse impacts to~~restrictions on our business ~~as a result~~activities prior to closing the XOG Merger and the Crestone Peak Merger, respectively. Each of ~~its global economic impact, including any recession that has occurred or may occur~~the XOG Merger Agreement and the Crestone Peak Merger Agreement obligate us to generally conduct our businesses in the ~~future.~~

~~The excess supply of oil~~ordinary course until the closing and ~~natural gas resulting from~~to use our reasonable best efforts to (i) preserve substantially intact our present business organization, goodwill and assets, (ii) keep available the reduced demand caused by the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries has resulted, and may continue to result, in transportation and storage constraints, and reductionsservices of our ~~planned production,~~current officers and ~~may cause shut-in~~employees and (iii) preserve our existing relationships with governmental entities and significant customers, suppliers, licensors, licensees, distributors, lessors and others having significant business dealings with us. These restrictions could prevent us from pursuing certain business opportunities that arise prior to the closing and are outside the ordinary course of ~~our wells, which could adversely affect our business, financial condition, and results of operations.~~

The worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19, and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production, followed by curtailment agreements among OPEC and other countries, including Russia, has increased uncertainty and volatility around global oil supply-demand dynamics and further increased the excess supply of oil and natural gas. To the extent that the outbreak of COVID-19 continues to negatively impact demand, and OPEC members and other oil exporting nations fail to implement production cuts or other actions that are sufficient to support and stabilize commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period. This excess supply has, in turn, resulted, and may continue to result, in transportation and storage capacity constraints in the United States, including in the DJ Basin where we operate, which may continue for a sustained period. For example, the substantial number of outstanding futures contracts, in conjunction with the market’s perception that crude oil storage in Cushing, Oklahoma was inadequate for May 2020 deliveries, caused NYMEX WTI prices to settle at negative $37.63 per Bbl on April 20, 2020, a dynamic that has not previously occurred.business.

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~~If,~~We may not realize anticipated benefits and synergies expected from acquisitions, including the XOG Merger and the Crestone Peak Merger.

We seek to complete acquisitions in order to strengthen our position and to create the ~~future, our ability~~opportunity to ~~sell our production is hindered because~~realize certain benefits, including, among other things, potential cost savings. Achieving the benefits of ~~transportation or storage constraints, we may be required to shut-in or curtail production or flare our natural gas. Further, any prolonged shut-in of our wells may result~~acquisitions depends in ~~decreased~~part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well ~~productivity once we are~~as being able to ~~resume operations,~~realize the anticipated growth opportunities and ~~any cessation of drilling~~synergies from combining the acquired businesses and ~~development of our acreage~~operations. We may fail to realize the anticipated benefits and synergies expected from acquisitions, which could ~~result in the expiration, in whole or in part, of our leases. All of these impacts resulting from the confluence of the COVID-19 pandemic and the price war between Saudi Arabia and Russia may~~ adversely affect our business, financial condition and ~~results of operations.~~operating results.Acquisitions could also result in difficulties in being able to hire, train or retain qualified personnel to manage and operate such properties.

~~Due~~With respect to the ~~commodity price environment, we have postponed a significant portion of our developmental drilling. A sustained period of weakness in oil, natural gas, and NGLs prices,~~XOG Merger and the ~~resultant effects~~Crestone Peak Merger, we believe that the addition of ~~such prices on~~XOG and Crestone Peak will complement our ~~drilling economics~~strategy by providing operational and ~~ability~~financial scale, increasing free cash flow, and enhancing our corporate rate of return. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the merger, and there can be no assurance that we will be able to ~~raise capital, will require us~~successfully integrate XOG's and Crestone Peak’s assets or otherwise realize the expected benefits of the transaction. This growth and the anticipated benefits of the XOG Merger and the Crestone Peak Merger may not be realized fully or at all, or may take longer to ~~reevaluate~~realize than expected. Difficulties in integrating XOG and ~~further postpone or eliminate additional drilling. Such actions would likely~~Crestone Peak may result in the ~~reduction~~combined company performing differently than expected, or in operational challenges or failures to realize anticipated efficiencies. Potential difficulties in realizing the anticipated benefits of the XOG Merger and the Crestone Peak Merger include:

•disruptions of relationships with customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners as a result of uncertainty associated with the XOG Merger and the Crestone Peak Merger;

•difficulties integrating our ~~PUDs~~business with the business of XOG and Crestone Peak in a manner that permits us to achieve the full revenue and cost savings anticipated from the transaction;

•complexities associated with managing a larger and more complex business, including difficulty addressing possible inconsistencies in, standards, controls or operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;

•difficulties realizing anticipated operating synergies;

•difficulties integrating personnel, vendors and business partners;

•loss of key employees of XOG or Crestone Peak who are critical to our future operations due to uncertainty about their roles within our company following the XOG Merger and the Crestone Peak Merger or other concerns regarding the XOG Merger and the Crestone Peak Merger;

•potential unknown liabilities and unforeseen expenses;

•performance shortfalls at one or more of the companies as a result of the diversion of management’s attention to integration efforts; and

•disruption of, or the loss of momentum in, each company’s ongoing business.

We have also incurred, and expect to continue to incur, a number of costs associated with completing the XOG Merger and the Crestone Peak Merger and combining the businesses of XOG, Crestone Peak and Bonanza Creek. The elimination of duplicative costs, as well as the realization of other efficiencies related ~~PV-10~~to the integration of the two companies, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all. Matters relating to the mergers (including integration planning) require substantial commitments of time and ~~a reduction~~resources by our management, which may result in the distraction of management from ongoing business operations and pursuing other opportunities that could have been beneficial to us.

Our future success will depend, in part, on our ability to ~~service~~manage our ~~debt obligations. If we are required~~expanded business by, among other things, integrating the assets, operations and personnel of XOG, Crestone Peak and Bonanza Creek in an efficient and timely manner; consolidating systems and management controls; and successfully integrating relationships with customers, vendors and business partners. Failure to ~~further curtail our drilling program, we~~successfully manage the combined company may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGLs prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.

Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas, and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas, and NGL prices.

As of the filing date of this report, we have approximately 100% of our average 2020 guided oil production hedged, approximately 50% of our average 2021 anticipated oil production hedged, and our hedging for 2022 oil production is even more limited. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices, which would have a material negative impact on our results of operations.

~~We cannot assure you that in connection with the fall 2020 semi-annual borrowing base redetermination, our borrowing base will not be reduced to a lesser amount than what we expect.~~

~~The borrowing base under our Credit Facility is redetermined on a semi-annual basis, as described in~~ ~~Note 5 – Credit Facility~~ in Part I, Item 1 above. The most recent redetermination was concluded on June 18, 2020, resulting in a reduction of the borrowing base from $375.0 million to $260.0 million. The next scheduled redetermination is set to occur in November 2020 and was not completed as of the date of this filing. Approval of the borrowing base is subject to receiving consent from the lenders, and we cannot provide any assurance as to whether the borrowing base will be redetermined at an amount equal to or below its current level. If our borrowing base is redetermined to a substantially lower amount, we may be unable to obtain adequate funding under our Credit Facility, which could adversely affect our development plans as currently anticipated and could have a material adverse effect on our production, revenues, and results of operations.

If commodity prices continue to decrease or remain at current levels such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take additional write-downs of the carrying values of our properties.

Accounting guidance requires that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics, and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Due to the recent depressed commodity prices, this year we recorded a $30.6 million abandonment and impairment of unproved properties. Further impairments, which could have an adverse effect on our business, reputation, financial condition and results of operations, will be required if oil and natural gas prices further decline, unproved property values decrease, estimated proved reserve volumes are revised downward, or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows.operations.

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AsThe XOG Merger and the Crestone Peak Merger will trigger a ~~Colorado-only oil~~limitation on the utilization of our historic U.S. net operating loss carryforwards (“NOLs”), XOG’s NOLs and ~~gas operator,~~Crestone Peak’s NOLs.

Our ability to utilize NOLs (including NOLs of XOG and Crestone Peak) to reduce future taxable income following the XOG Merger and the Crestone Peak Merger depends on many factors, including our future income, which cannot be assured. Section 382 of the Code generally imposes an annual limitation upon the occurrence of an “ownership change” resulting from issuances of a company’s stock or the sale or exchange of such company’s stock by certain stockholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of such company’s stock by such stockholders within a rolling three-year period. The limitation with respect to such loss carryforwards generally would be equal to (i) the fair market value of the company’s equity immediately prior to the ownership change multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax-exempt bonds during the month in which the ownership change occurs. Based on the information currently available, we ~~face disproportionate risk associated~~believe that the transactions in connection with the ~~long-term trend toward increased activism against oil~~XOG Merger and ~~gas exploration and development activities in Colorado.~~

~~Opposition toward oil and gas drilling and development activity has been growing globally. Companies in~~ the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling in the United States, even in jurisdictions that are among the most stringent in their regulation of the industry. Further efforts couldCrestone Peak Merger, if consummated, will result in ~~the following:~~

•~~delay or denial of drilling permits;~~

•~~revocation or modification of drilling permits or other necessary authorizations;~~

•~~shortening of lease terms or reduction in lease size;~~

•~~restrictions on installation or operation of production, gathering, or processing facilities;~~

•~~mandatory~~an ownership change with respect to us, XOG, and ~~lengthy distances between drilling locations and buildings and/or bodies of water or other protected areas;~~

•~~restrictions on the use of certain operating practices, such~~Crestone Peak, which would trigger a limitation (calculated as ~~hydraulic fracturing, or the disposal of related waste materials, such as hydraulic fracturing fluids and produced water;~~

•~~increased severance and/or other taxes;~~

•~~cyber-attacks;~~

•~~legal challenges or lawsuits;~~

•~~negative publicity about us or the oil and gas industry in general;~~

•~~increased costs of operations and development;~~

•~~reduction in demand for our products; and~~

•~~other adverse effects~~described above) on our ability to ~~develop our properties~~utilize any historic NOLs following the XOG Merger and ~~expand production.~~

Specifically in Colorado, anti-development activity has both increased and become more effective in recent years. On April 16, 2019, new legislation became effective in Colorado, which substantially changed the ~~state’s regulation of oil and gas exploration and production activities and applied immediately to all pending permit applications. The new law changed the mission~~Crestone Peak Merger. XOG’s NOLs are already limited under Section 382 of the ~~Colorado Oil & Gas Conservation Commission (the “COGCC”) from “fostering” responsible and balanced development to “regulating” development to protect public health~~Code as a result of an ownership change that occurred in connection with XOG’s Chapter 11 cases.

The market price for our common stock following the XOG Merger and the ~~environment. The required composition~~Crestone Peak Merger may be affected by factors different from those that historically have affected or currently affect our common stock.

Our financial position following the XOG Merger and the Crestone Peak Merger may differ from our financial position before the XOG Merger and the Crestone Peak Merger, and the results of operations of the ~~COGCC was also changed~~combined company may be affected by factors that are different from those currently affecting the results of our operations. Accordingly, the market price and performance of our common stock is likely to ~~remove two seats for oil and gas industry experts and add experts on wildlife/environmental protection and public health. The state’s statutory pooling provisions were changed by~~be different from the ~~new law to require that an applicant own, or obtain~~performance of our common stock in the ~~consent of, more than 45%~~absence of the ~~applicable working~~XOG Merger and the Crestone Peak Merger.

Our stockholders, XOG stockholders and Crestone Peak stockholders, in each case as of immediately prior to the mergers, will have reduced ownership in the combined company.

We anticipate issuing 30,936,254 shares of Common Stock to XOG stockholders pursuant to the XOG Merger Agreement and 22,500,000 shares of Common Stock to Crestone Peak stockholders pursuant to the Crestone Peak Merger Agreement. The issuance of these new shares could have the effect of depressing the market price of our Common Stock, through dilution of earnings per share or ~~mineral interest, whereas previously~~otherwise. Any dilution of, or delay of any accretion to, our earnings per share could cause the ~~consent~~price of ~~only one mineral interest owner was required.~~our Common Stock to decline or increase at a reduced rate.

Among the most significant changes under the legislation was the provision of local government control over facility siting and surface impacts associated with oil and gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements. Further, local governments may now inspect oil and gas operations and impose fines for leaks, spills, and emissions.

The legislation mandates the COGCC rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned, or shut-in, financial assurance, wellbore integrity, and application fees. PendingFollowing the completion of ~~this initial rulemaking,~~ the ~~COGCC~~XOG Merger, assuming the Crestone Peak Merger is not consummated, it is anticipated that persons who were stockholders of Bonanza Creek and XOG immediately prior to the XOG Merger will own approximately 50% and 50% of the combined company, respectively. Following the completion of the Crestone Peak Merger, it is anticipated that persons who were stockholders of Bonanza Creek, XOG and Crestone Peak immediately prior to the Crestone Peak Merger will own approximately 37%, 37% and 26% of the combined company, respectively. As a result, our current stockholders, XOG’s current stockholders and Crestone Peak’s stockholders will have less influence on the policies of the combined company than they currently have on our policies and the polices of Extraction and Crestone Peak, respectively.

The Kimmeridge Fund will become a significant holder of our Common Stock following completion of the XOG Merger.

Upon completion of the XOG Merger, assuming there is no decrease in the Kimmeridge Fund’s holdings of XOG common stock prior to completion of the XOG Merger, the Kimmeridge Fund would be expected to own approximately 19% of our Common Stock, representing approximately 19% of our combined voting power (That percentage would be reduced to approximately 14% if the Crestone Peak Merger closes.). In addition, upon completion of the XOG Merger, Mr. Benjamin Dell, independent chairman of the XOG board and a Managing Director of the Kimmeridge Fund, will serve as chairman of the board of directors of the combined company. As a result, we believe that the Kimmeridge Fund may ~~delay acting on selected permit applications.~~or will have some ability to influence our management and affairs. Further, the existence of a new significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may view as being in their best interests or in our best interests.

In the event that the Kimmeridge Fund becomes and continues to be the owner of a significant amount of our Common Stock, the prospect that it may be able to influence matters requiring stockholder approval may continue. In any of these matters, the interests of the Kimmeridge Fund and of our other stockholders may differ or conflict. Moreover, in the event that the Kimmeridge Fund becomes and continues to be the owner of a significant concentration of our Common Stock, such an ownership stake may also adversely affect the trading price of our Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.

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CPPIB Crestone Peak Resources Canada Inc., a Canadian corporation (the “Crestone Peak Stockholder”) will become a significant holder of our Common Stock following completion of the Crestone Peak Merger.

Upon completion of the Crestone Peak Merger, assuming there is no decrease in the Crestone Peak Stockholder’s holdings of Crestone Peak common stock prior to completion of the Crestone Peak Merger, the Crestone Peak Stockholder would be expected to own approximately 25% of our Common Stock, representing approximately 25% of our combined voting power. As a result, we believe that the Crestone Peak Stockholder may have some ability to influence our management and affairs. Further, the existence of a new significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may view as being in their best interests or in our best interests.

In the event that the Crestone Peak Stockholder becomes and continues to be the owner of a significant amount of our Common Stock, the prospect that it may be able to influence matters requiring stockholder approval may continue. In any of these matters, the interests of the Crestone Peak Stockholder may differ or conflict from those of our other stockholders. Moreover, in the event that the Crestone Peak Stockholder becomes and continues to be the owner of a significant concentration of our Common Stock, such an ownership stake may also adversely affect the trading price of our Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.

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Risks Relating to the HighPoint Merger

We may not achieve the anticipated benefits of the HighPoint Merger.

The success of the HighPoint Merger will depend, in part, on ~~October 17, 2019,~~our ability to realize the ~~Colorado Department~~anticipated benefits and cost savings from combining our and HighPoint’s businesses, and there can be no assurance that we will be able to realize the anticipated benefits of ~~Public Health~~the HighPoint Merger. The combined company may perform differently than expected, face operational challenges, or fail to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:

•complexities associated with managing a larger, more complex, integrated business;

•not realizing anticipated operating synergies;

•potential unknown liabilities and ~~Environment (the “CDPHE”) published a health risk assessment for~~unforeseen expenses associated with the HighPoint Merger; and

•managing expanded environmental and other regulatory compliance obligations related to HighPoint's facilities and operations.

Our results may suffer if we do not effectively manage our expanded operations following the HighPoint Merger.

Following completion of the HighPoint Merger, the size of our business has increased significantly. Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of HighPoint into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with various business partners. Failure to successfully manage the combined company may have an adverse effect on our financial condition, results of operations or cash flows.

Following the HighPoint Merger, we are proportionately more exposed to regulatory and operational risks associated with oil and gas operations in ~~Colorado. The assessment is based on modeling done~~Colorado and other risks associated with ~~certain historic emissions data~~a more geographically-concentrated asset base.

Substantially all of HighPoint’s properties, production and found the possibility of negative short-term health impacts at distances out to 2,000 feet from facilities engaged in pre-production operations (i.e., drilling, completion, and flowback) under worst-case conditions. In responsereserves immediately prior to the ~~assessment,~~HighPoint Merger were located in Colorado. As a result of the ~~COGCC announced~~HighPoint Merger, the amount of our properties, production and reserves that ~~it will more rigorously scrutinize permit applications for wells within 2,000 feet of a building unit. The COGCC also announced that it will collect new data from oil~~are located in Colorado have increased and ~~gas wells, compare the data~~our exposure to the ~~assessment published by~~risk of unfavorable regulatory developments in the ~~CDPHE, and use~~state have therefore increased as well. The increase of our combined production located in the ~~data~~Wattenberg Field following the HighPoint Merger has proportionately increased our exposure to ~~inform the COGCC’s new regulations and rulemakings.~~

The COGCC rulemaking process is ongoing. It appears likely that the COGCC will adopt final rules in November 2020 (effective January 1, 2020) that include an increased required setback of 2,000 feet between an oil and gas location and a residential or high occupancy building unit unless one or more conditions are satisfied to allow for a lesser setback that the COGCC determines is sufficiently protective of public health, safety and welfare, the environment, and wildlife resources. In addition, as part of proposed wildlife protections, the COGCC is contemplating an increased setback from 300 feet, as originally proposed by COGCC staff, to 500 feet between oil and gas locations and/or certain operations thereon and the ordinary high water mark for riparian resources and certain high priority aquatic habitats.

~~Permitting delays that occur while the COGCC rulemaking process proceeds,~~this risk, as well as ~~delays that~~other risks associated with operating in a more concentrated geographic area.

The market price of our common stock will continue to fluctuate, and may ~~result from~~decline if the ~~new COGCC rules and regulations themselves, could substantially curtail~~benefits of the ~~Company’s near-term pace~~HighPoint Merger do not meet the expectations of ~~new oil and gas development. We have already observed a marked decline in~~financial analysts.

The market price of our common stock may fluctuate significantly, including if we do not achieve the ~~pace at which permit applications are being granted, and~~anticipated benefits of the HighPoint Merger as rapidly, or to the extent anticipated by, financial analysts or if ~~this trend continues, it could have a material adverse~~the effect of the HighPoint Merger on our ~~business,~~ financial ~~condition, and~~ results is not consistent with the expectations of ~~operations.~~

Additionally, the new legislation requires the state’s Air Quality Control Commission (the “AQCC”) to undertake rulemaking efforts to minimize methane emissions and emissions of other hydrocarbons, volatile organic compounds, and nitrogen oxides associated with certain oil and gas facilities. The AQCC may also adopt more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, installation of continuous emission monitoring equipment at certain oil and gas facilities, and reduced emissions from pneumatic devices. The legislation also grants the AQCC regulatory authority over a broad range of oil and gas facilities during pre-production activities, drilling, and completion.

~~Rules adopted by the COGCC and AQCC pursuant to the new legislation may significantly increase the Company’s operating costs and have a material adverse effect on our business,~~ financial ~~condition, and results of operations.~~

Additionally, anti-development activists succeeded in adding a measure to the November 6, 2018 ballot in Colorado, which sought to require a minimum 2,500 foot setback from occupied structures and vulnerable areas for all new oil and gas development on non-federal land. While this initiative was ultimately unsuccessful, had it been successful, it may have resulted in dramatically reducing the area of future oil and gas development in Colorado. Similar ballot measures were submitted for the 2020 election by anti-development activist groups. In addition, there have been several citizen/activist lawsuits filed against industry and state and local regulators associated with air quality, siting, environmental justice, and climate change. Such anti-development efforts are likely to continue in the future, which could result in dramatically reducing the area of future oil and gas development in Colorado or outright banning oil and gas development in Colorado. These efforts could have a material adverse effect on our business, financial condition, and results of operations.analysts.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended ~~September~~June 30, ~~2020.~~2021.

Issuer purchases of equity securities. The following table contains information about acquisitions of our equity securities during the three month period ended ~~September~~June 30, ~~2020:~~2021:


				Total Number of Shares	Maximum Number of
	Total Number			Purchased as Part of	Shares that May Be
	of Shares	Average Price		Publicly Announced	Purchased Under Plans
	Purchased(1)	Paid per Share		Plans or Programs	or Programs
April 1, 2021 - April 30, 2021	38,556	$	34.53	—	—
May 1, 2021 - May 31, 2021	22,673	$	38.26	—	—
June 1, 2021 - June 30, 2021	9,101	$	46.87	—	—
Total	70,330	$	36.32	—	—

Total Number of Shares Maximum Number of
Total Number Purchased as Part of Shares that May Be
of Shares Average Price Publicly Announced Purchased Under Plans
Purchased(1)
Paid per Share Plans or Programs or Programs
July 1, 2020 - July 31, 2020 2,810 $ 19.07 — —
August 1, 2020 - August 31, 2020 338 $ 18.19 — —
September 1, 2020 - September 30, 2020 — $ — — —
Total 3,148 $ 18.94 — —
_____________________________

(1)Represents shares that employees surrendered back to us that equaled in value the amount of taxes required for payroll tax withholding obligations upon the vesting of equity awards under the ~~2017~~ LTIP. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.

Our Credit Facility contains ~~restrictions~~restrictive thresholds on the payment of dividends.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

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Item 6. Exhibits.


Exhibit No.						Description of Exhibit

2.1						Agreement and Plan of Merger, dated as of November 9, 2020, by and among Bonanza Creek Energy, Inc., HighPoint Resources Corporation and Boron Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on November 9, 2020).

2.2						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 t o Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on May 10 , 20 21 ).

2.3						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 t o Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 8 , 2021).

2.4						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 Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 8, 2021).

3.1						Third Amended and Restated Certificate of Incorporation of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.1 to Bonanza Creek Energy, Inc.’s Registration Statement on Form 8-A filed on April 28, 2017).

3.2						Fourth Amended and Restated Bylaws of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.2 to Bonanza Creek Energy, Inc.’s Registration Statement on Form 8-A filed on April 28, 2017).

4.1						Indenture, dated as of April 1, 2021, by and among Bonanza Creek Energy, Inc., U.S. Bank National Association, as trustee, and the subsidiary guarantors party thereto (incorporated by reference to Exhibit 4.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 1, 2021).

4.2						First Supplemental Indenture, dated as of April 1, 2021, by and among Bonanza Creek Energy, Inc., U.S. Bank National Association, as trustee, HighPoint Resources Corporation, HighPoint Operating Corporation and Fifth Pocket Productions, LLC (incorporated by reference to Exhibit 4.2 to Bonanza Creek Energy, Inc.'s Current Report on Form 8-K filed on April 1, 2021).

4.3						Confirmation Order, filed March 18, 2021 (incorporated by reference to Exhibit 99.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on March 22, 2021).

10.1						Second Amendment to Credit Agreement, dated as of April 1, 2021, between Bonanza Creek Energy, Inc., JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders (incorporated by reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 1, 2021).

10.2						Registration Rights Agreement, dated April 1, 2021, between Bonanza Creek Energy, Inc., and Franklin Advisers, Inc. (incorporated by reference to Exhibit 10.2 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 1, 2021).

10.3						Support Agreement, dated as of June 6, 2021, by and among Bonanza Creek Energy, Inc., CPPIB Crestone Peak Resources Canada Inc., and CPPIB Crestone Peak Resources America Inc. (incorporated by reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 8, 2021).

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 10.2 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 8, 2021).

10.5 †*						Form of Officer Performance Stock Unit Agreement under the Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan.

10.6†*						Bonanza Creek Energy, Inc. 2021 Long Term Incentive Pla n.

10.7†*						Form of Independent Director Restricted Stock Unit Agreement under the Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan.

31.1*						Certification of the Principal Executive Officer pursuant to Rule 13a-14(a).

31.2*						Certification of the Principal Financial Officer pursuant to Rule 13a-14(a).

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32.1**		Certification of the Principal Executive Officer pursuant to 18.U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

32.2**		Certification of the Principal Financial Officer pursuant to 18.U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase

101.DEF*		XBRL Taxonomy Extension Definition Linkbase

101.LAB*		XBRL Taxonomy Extension Label Linkbase

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase

104		Cover Page Interactive Data File (formatted as Inline XBRL)
__________________________________________
*	Filed with this report

**	Furnished with this report

†	Management Contract or Compensatory Plan or Agreement

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SIGNATURES

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

BONANZA CREEK ENERGY, INC.

Date:

~~November 5, 2020~~August 9, 2021

By:

/s/ Eric T. Greager

Eric T. Greager

President and Chief Executive Officer

(principal executive officer)

By:

/s/ Brant DeMuth

Brant DeMuth

Executive Vice President and Chief Financial Officer

(principal financial officer)

By:

/s/ Sandi K. Garbiso

Sandi K. Garbiso

Vice President and Chief Accounting Officer

(chief accounting officer)

4149


	September 30, 2020		December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$	3,777	$	11,008
Accounts receivable, net:
Oil and gas sales	28,031		43,714
Joint interest and other	20,072		38,136
Prepaid expenses and other	3,562		7,048
Inventory of oilfield equipment	8,336		7,726
Derivative assets (note 10)	26,062		2,884
Total current assets	89,840		110,516
Property and equipment (successful efforts method):
Proved properties	1,052,004		935,025
Less: accumulated depreciation, depletion, and amortization	(192,701)		(126,614)
Total proved properties, net	859,303		808,411
Unproved properties	107,315		143,020
Wells in progress	50,911		98,750
Other property and equipment, net of accumulated depreciation of $3,601 in 2020 and $3,142 in 2019	3,375		3,394
Total property and equipment, net	1,020,904		1,053,575
Long-term derivative assets (note 10)	1,301		121
Right-of-use assets (note 3)	33,812		38,562
Other noncurrent assets	2,918		3,544
Total assets	$	1,148,775	$	1,206,318
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4)	$	35,518	$	57,638
Oil and gas revenue distribution payable	17,918		29,021
Lease liability (note 3)	12,622		11,690
Derivative liability (note 10)	5,463		6,390
Total current liabilities	71,521		104,739
Long-term liabilities:
Credit facility (note 5)	20,000		80,000
Lease liability (note 3)	21,618		27,540
Ad valorem taxes	19,442		28,520
Derivative liability (note 10)	2,939		921
Deferred income taxes (note 12)	4,689		0
Asset retirement obligations for oil and gas properties (note 9)	25,614		27,908
Total liabilities	165,823		269,628
Commitments and contingencies (note 6)
Stockholders’ equity:
Preferred stock, $0.01 par value, 25,000,000 shares authorized, NaN outstanding	0		0
Common stock, $0.01 par value, 225,000,000 shares authorized, 20,834,028 and 20,643,738 issued and outstanding as of September 30, 2020 and December 31, 2019, respectively	4,282		4,284
Additional paid-in capital	705,537		702,173
Retained earnings	273,133		230,233
Total stockholders’ equity	982,952		936,690
Total liabilities and stockholders’ equity	$	1,148,775	$	1,206,318


	As of September 30,
	2020		2019
Cash and cash equivalents	$	3,777	$	8,371
Restricted cash included in other noncurrent assets(1)	95		87
Total cash, cash equivalents, and restricted cash as shown in the statements of cash flows	$	3,872	$	8,458


	Operating Leases		Finance Leases
Remainder of 2020	$	3,511	$	32
2021	13,239		118
2022	10,192		0
2023	6,593		0
2024	2,439		0
Thereafter	108		0
Total lease payments	36,082		150
Less: imputed interest	(1,990)		(2)
Total lease liability	$	34,092	$	148



	As of September 30, 2020		As of December 31, 2019
Accrued drilling and completion costs	$	2,638	$	3,248
Accounts payable trade	3,229		17,117
Accrued general and administrative expense	3,654		5,620
Accrued lease operating expense	2,113		2,187
Accrued interest	6		692
Accrued oil and gas hedging	0		453
Accrued production and ad valorem taxes and other	23,878		28,321
Total accounts payable and accrued expenses	$	35,518	$	57,638


	NGL Crude Commitments(1)
Remainder of 2020	$	3,694
2021	22,403
2022	23,097
2023	7,521
2024	0
2025 and thereafter	0
Total	$	56,715