UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the Quarterly Period Ended ~~September~~June 30, ~~2020~~2021


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

For the transition period from_______________ to _______________

Commission file number 001-38606

Berry Corporation (bry)

(Exact name of registrant as specified in its charter)


Delaware (State of incorporation or organization)						81-5410470 (I.R.S. Employer Identification Number)

16000 Dallas Parkway, Suite 500

Dallas, Texas 75248

(661) 616-3900

(Address of principal executive offices, including zip code

Registrant’s telephone number, including area code)

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


Title of each class Common Stock, par value $0.001 per share			Trading Symbol BRY			Name of each exchange on which registered Nasdaq Global Select Market

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) 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, a smaller reporting company or emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐

Accelerated filer ☐

Non-accelerated filer ☒

Smaller reporting company ☐

Emerging Growth Company ☒

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

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

Shares of common stock outstanding as of ~~October~~July 31, ~~2020 79,929,335~~2021 80,471,022

Table of Contents

The financial information and certain other information presented in this report have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this report. In addition, certain percentages presented in this report reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not sum due to rounding.

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


		September 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
		(in thousands, except share amounts)					(in thousands, except share amounts)
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	47,620	$	0	Cash and cash equivalents	$	74,918	$	80,557
Accounts receivable, net of allowance for doubtful accounts of $2,215 at September 30, 2020 and $1,103 at December 31, 2019		48,798		71,867
Accounts receivable, net of allowance for doubtful accounts of $1,715 at June 30, 2021 and $2,215 at December 31, 2020						Accounts receivable, net of allowance for doubtful accounts of $1,715 at June 30, 2021 and $2,215 at December 31, 2020	63,740		52,027
Derivative instruments	Derivative instruments	57,658		9,166		Derivative instruments	11,515		2,507

Other current assets	Other current assets	20,318		19,399		Other current assets	26,890		19,400
Total current assets	Total current assets	174,394		100,432		Total current assets	177,063		154,491
Noncurrent assets:	Noncurrent assets:					Noncurrent assets:
Oil and natural gas properties	Oil and natural gas properties	1,388,544		1,675,717		Oil and natural gas properties	1,478,622		1,412,566
Accumulated depletion and amortization	Accumulated depletion and amortization	(209,956)		(209,105)		Accumulated depletion and amortization	(294,576)		(235,259)
Total oil and natural gas properties, net	Total oil and natural gas properties, net	1,178,588		1,466,612		Total oil and natural gas properties, net	1,184,046		1,177,307
Other property and equipment	Other property and equipment	111,146		135,117		Other property and equipment	114,558		112,145
Accumulated depreciation	Accumulated depreciation	(28,979)		(25,462)		Accumulated depreciation	(36,187)		(31,368)
Total other property and equipment, net	Total other property and equipment, net	82,167		109,655		Total other property and equipment, net	78,371		80,777
Derivative instruments		2,011		525

Other noncurrent assets	Other noncurrent assets	9,297		12,974		Other noncurrent assets	5,035		7,235
Total assets	Total assets	$	1,446,457	$	1,690,198	Total assets	$	1,444,515	$	1,419,810
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable and accrued expenses	Accounts payable and accrued expenses	$	95,237	$	151,811	Accounts payable and accrued expenses	$	160,586	$	151,985
Derivative instruments	Derivative instruments	337		4,817		Derivative instruments	61,476		23,321

Total current liabilities	Total current liabilities	95,574		156,628		Total current liabilities	222,062		175,306
Noncurrent liabilities:	Noncurrent liabilities:					Noncurrent liabilities:
Long-term debt	Long-term debt	393,219		394,319		Long-term debt	394,009		393,480
Derivative instruments	Derivative instruments	1,179		141		Derivative instruments	4,058		0
Deferred income taxes	Deferred income taxes	9,318		9,057		Deferred income taxes	538		1,011
Asset retirement obligation		136,392		124,019
Asset retirement obligations						Asset retirement obligations	139,181		135,192
Other noncurrent liabilities	Other noncurrent liabilities	36,150		33,586		Other noncurrent liabilities	6,009		785
Commitments and Contingencies - Note 4	Commitments and Contingencies - Note 4					Commitments and Contingencies - Note 4	0		0
Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 85,004,619 and 84,655,222 shares issued; and 79,892,373 and 79,542,976 shares outstanding, at September 30, 2020 and December 31, 2019, respectively)		85		85
Stockholders' Equity:						Stockholders' Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 85,583,268 and 85,041,581 shares issued; and 80,471,022 and 79,929,335 shares outstanding, at June 30, 2021 and December 31, 2020, respectively)						Common stock ($0.001 par value; 750,000,000 shares authorized; 85,583,268 and 85,041,581 shares issued; and 80,471,022 and 79,929,335 shares outstanding, at June 30, 2021 and December 31, 2020, respectively)	86		85
Additional paid-in-capital	Additional paid-in-capital	912,637		901,830		Additional paid-in-capital	914,701		915,877
Treasury stock, at cost, (5,112,246 shares at September 30, 2020 and at December 31, 2019)		(49,995)		(49,995)
Retained earnings (deficit)		(88,102)		120,528
Total equity		774,625		972,448
Total liabilities and equity		$	1,446,457	$	1,690,198
Treasury stock, at cost (5,112,246 shares at June 30, 2021 and December 31, 2020)						Treasury stock, at cost (5,112,246 shares at June 30, 2021 and December 31, 2020)	(49,995)		(49,995)
Retained deficit						Retained deficit	(186,134)		(151,931)
Total stockholders' equity						Total stockholders' equity	678,658		714,036
Total liabilities and stockholders' equity						Total liabilities and stockholders' equity	$	1,444,515	$	1,419,810

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

Table of Contents

BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


		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
		(in thousands, except per share amounts)									(in thousands, except per share amounts)
Revenues and other:	Revenues and other:									Revenues and other:
Oil, natural gas and natural gas liquids sales	Oil, natural gas and natural gas liquids sales	$	92,239	$	141,250	$	284,852	$	409,259	Oil, natural gas and natural gas liquids sales	$	147,775	$	70,515	$	283,040	$	192,613
Electricity sales	Electricity sales	8,744		7,460		19,089		22,553		Electricity sales	6,888		4,884		16,957		10,345
(Losses) gains on oil derivatives		(11,564)		45,509		157,398		7,546
(Losses) gains on oil and gas sales derivatives										(Losses) gains on oil and gas sales derivatives	(55,653)		(42,267)		(109,157)		168,962
Marketing revenues	Marketing revenues	330		413		1,075		1,657		Marketing revenues	121		292		2,355		745
Other revenues	Other revenues	0		40		53		261		Other revenues	118		29		255		53
Total revenues and other	Total revenues and other	89,749		194,672		462,467		441,276		Total revenues and other	99,249		33,453		193,450		372,718
Expenses and other:	Expenses and other:									Expenses and other:
Lease operating expenses	Lease operating expenses	45,243		50,957		136,727		156,765		Lease operating expenses	45,543		40,733		107,827		91,485
Electricity generation expenses	Electricity generation expenses	4,217		3,781		11,186		14,705		Electricity generation expenses	4,712		3,022		12,360		6,968
Transportation expenses	Transportation expenses	1,768		2,067		5,379		5,935		Transportation expenses	1,757		1,789		3,333		3,611
Marketing expenses	Marketing expenses	326		398		1,036		1,670		Marketing expenses	44		280		2,271		710
General and administrative expenses	General and administrative expenses	19,173		16,434		57,287		46,932		General and administrative expenses	16,065		18,777		33,135		38,114
Depreciation, depletion, and amortization	Depreciation, depletion, and amortization	35,905		27,664		108,746		75,904		Depreciation, depletion, and amortization	35,850		37,512		69,690		72,841
Impairment of oil and gas properties	Impairment of oil and gas properties	0		0		289,085		0		Impairment of oil and gas properties	0		0		0		289,085
Taxes, other than income taxes	Taxes, other than income taxes	9,913		9,249		24,714		28,683		Taxes, other than income taxes	11,603		10,449		21,160		14,801

(Gain) losses on natural gas derivatives		(15,784)		3,008		(2,824)		10,342
(Gains) losses on natural gas purchase derivatives										(Gains) losses on natural gas purchase derivatives	(11,639)		925		(39,369)		12,960
Other operating expenses (income)	Other operating expenses (income)	1,648		(550)		2,658		3,814		Other operating expenses (income)	42		(1,192)		841		1,010
Total expenses and other	Total expenses and other	102,409		113,008		633,994		344,750		Total expenses and other	103,977		112,295		211,248		531,585
Other (expenses) income:	Other (expenses) income:									Other (expenses) income:
Interest expense	Interest expense	(8,391)		(8,597)		(25,987)		(26,362)		Interest expense	(8,217)		(8,676)		(16,702)		(17,596)
Other, net	Other, net	(3)		(77)		(15)		79		Other, net	(8)		(6)		(151)		(12)
Total other (expenses) income	Total other (expenses) income	(8,394)		(8,674)		(26,002)		(26,283)		Total other (expenses) income	(8,225)		(8,682)		(16,853)		(17,608)
Reorganization items, net		0		(170)		0		(426)
(Loss) income before income taxes		(21,054)		72,820		(197,529)		69,817

Loss before income taxes										Loss before income taxes	(12,953)		(87,524)		(34,651)		(176,475)
Income tax (benefit) expense	Income tax (benefit) expense	(2,190)		20,171		1,536		19,294		Income tax (benefit) expense	(72)		(22,623)		(448)		3,726
Net (loss) income		$	(18,864)	$	52,649	$	(199,065)	$	50,523
Net loss										Net loss	$	(12,881)	$	(64,901)	$	(34,203)	$	(180,201)

Net (loss) income per share:
Net loss per share:										Net loss per share:
Basic	Basic	$	(0.24)	$	0.65	$	(2.50)	$	0.62	Basic	$	(0.16)	$	(0.81)	$	(0.43)	$	(2.26)
Diluted	Diluted	$	(0.24)	$	0.65	$	(2.50)	$	0.62	Diluted	$	(0.16)	$	(0.81)	$	(0.43)	$	(2.26)

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

Table of Contents

BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)


		Nine-Month Period Ended September 30, 2019											Six-Month Period Ended June 30, 2020
		Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Earnings		Total Equity			Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Deficit		Total Stockholders’ Equity
		(in thousands)											(in thousands)
December 31, 2018		$	82	$	914,540	$	(24,218)	$	116,042	$	1,006,446
December 31, 2019												December 31, 2019	$	85	$	901,830	$	(49,995)	$	120,528	$	972,448

Shares withheld for payment of taxes on equity awards and other	Shares withheld for payment of taxes on equity awards and other	—		(270)		—		—		(270)		Shares withheld for payment of taxes on equity awards and other	—		(794)		—		—		(794)
Stock based compensation	Stock based compensation	—		1,498		—		—		1,498		Stock based compensation	—		3,036		—		—		3,036
Purchases of treasury stock		—		—		(24,375)		—		(24,375)
Purchase of rights to common stock(1)		—		(20,265)		20,265		—		0
Common stock issued to settle unsecured claims		3		(3)		—		—		0

Dividends declared on common stock, $0.12/share	Dividends declared on common stock, $0.12/share	—		—		—		(10,072)		(10,072)		Dividends declared on common stock, $0.12/share	—		—		—		(9,564)		(9,564)
Net loss	Net loss	—		—		—		(34,098)		(34,098)		Net loss	—		—		—		(115,300)		(115,300)
March 31, 2019		85		895,500		(28,328)		71,872		939,129
Shares withheld for payment of taxes on equity awards and other		—		(675)		—		—		(675)
Stock based compensation		—		2,497		—		—		2,497
Purchases of treasury stock		—		—		(10,897)		—		(10,897)

Dividends declared on common stock, $0.12/share		—		—		—		(9,710)		(9,710)
Net income		—		—		—		31,972		31,972
June 30, 2019		85		897,322		(39,225)		94,134		952,316
March 31, 2020												March 31, 2020	85		904,072		(49,995)		(4,336)		849,826
Shares withheld for payment of taxes on equity awards and other	Shares withheld for payment of taxes on equity awards and other	—		(294)		—		—		(294)		Shares withheld for payment of taxes on equity awards and other	—		(140)		—		—		(140)
Stock based compensation	Stock based compensation	—		2,393		—		—		2,393		Stock based compensation	—		4,730		—		—		4,730

Net loss												Net loss	—		—		—		(64,901)		(64,901)
June 30, 2020												June 30, 2020	$	85	$	908,662	$	(49,995)	$	(69,237)	$	789,515

Dividends declared on common stock, $0.12/share		—		—		—		(9,720)		(9,720)
Net income		—		—		—		52,649		52,649
September 30, 2019		$	85	$	899,421	$	(39,225)	$	137,063	$	997,344

~~__________~~

(1) In 2018, we entered into several settlement agreements with general unsecured creditors from our bankruptcy process. We paid approximately $20 million to purchase their claims to our common stock. These claims were settled in February 2019 with 0 shares issued.


	Six-Month Period Ended June 30, 2021
	Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Deficit		Total Stockholders’ Equity
	(in thousands)
December 31, 2020	$	85	$	915,877	$	(49,995)	$	(151,931)	$	714,036

Shares withheld for payment of taxes on equity awards and other	—		(1,442)		—		—		(1,442)
Stock based compensation	—		3,995		—		—		3,995
Issuance of common stock	1		—		—		—		1

Dividends declared on common stock, $0.04/share	—		(3,474)		—		—		(3,474)
Net loss	—		—		—		(21,322)		(21,322)
March 31, 2021	86		914,956		(49,995)		(173,253)		691,794
Shares withheld for payment of taxes on equity awards and other	—		(78)		—		—		(78)
Stock based compensation	—		3,042		—		—		3,042


Dividends declared on common stock, $0.04/share	—		(3,219)		—		—		(3,219)
Net loss	—		—		—		(12,881)		(12,881)
June 30, 2021	$	86	$	914,701	$	(49,995)	$	(186,134)	$	678,658

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

Table of Contents

BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED STATEMENTS OF ~~EQUITY~~CASH FLOWS

(Unaudited)

Nine-Month Period Ended September 30, 2020
Common Stock Additional Paid-in Capital Treasury Stock Retained Earnings (Deficit) Total Equity
(in thousands)
December 31, 2019 $ 85 $ 901,830 $ (49,995) $ 120,528 $ 972,448
Shares withheld for payment of taxes on equity awards and other — (794) — — (794)
Stock based compensation — 3,036 — — 3,036
Dividends declared on common stock, $0.12/share — — — (9,564) (9,564)
Net loss — — — (115,300) (115,300)
March 31, 2020 85 904,072 (49,995) (4,336) 849,826
Shares withheld for payment of taxes on equity awards and other — (140) — — (140)
Stock based compensation — 4,730 — — 4,730
Net loss — — — (64,901) (64,901)
June 30, 2020 85 908,662 (49,995) (69,237) 789,515
Shares withheld for payment of taxes on equity awards and other — (46) — — (46)
Stock based compensation — 4,021 — — 4,021
Net loss — — — (18,864) (18,864)
September 30, 2020 $ 85 $ 912,637 $ (49,995) $ (88,102) $ 774,625


	Six Months Ended June 30,
	2021		2020
	(in thousands)
Cash flows from operating activities:
Net loss	$	(34,203)	$	(180,201)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	69,690		72,841
Amortization of debt issuance costs	2,728		2,681
Impairment of oil and gas properties	0		289,085
Stock-based compensation expense	6,639		7,501
Deferred income taxes	(473)		2,750
(Decrease) increase in allowance for doubtful accounts	(500)		1,200
Other operating expenses	142		317

Derivative activities:
Total losses (gains)	69,788		(156,002)
Cash settlements on derivatives	(36,581)		71,499

Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(11,189)		21,802
(Increase) in other assets	(7,490)		(3,642)
Increase (decrease) in accounts payable and accrued expenses	3,406		(32,102)
(Decrease) in other liabilities	(2,098)		(11,307)
Net cash provided by operating activities	59,859		86,422

Cash flows from investing activities:
Capital expenditures:
Capital expenditures	(67,030)		(56,403)


Changes in capital expenditures accruals	6,934		(7,256)

Acquisition of properties and equipment and other	(825)		(2,076)
Proceeds from sale of property and equipment and other	409		217

Net cash used in investing activities	(60,512)		(65,518)

Cash flows from financing activities:
Borrowings under RBL credit facility	0		222,550
Repayments on RBL credit facility	0		(223,100)

Dividends paid on common stock	(3,466)		(19,420)

Shares withheld for payment of taxes on equity awards and other	(1,520)		(934)










Net cash used in financing activities	(4,986)		(20,904)
Net increase in cash and cash equivalents	(5,639)		0
Cash and cash equivalents:
Beginning	80,557		0
Ending	$	74,918	$	0

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

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~~BERRY CORPORATION (bry)~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

Nine Months Ended
September 30,
2020 2019
(in thousands)
Cash flows from operating activities:
Net (loss) income $ (199,065) $ 50,523
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization 108,746 75,904
Amortization of debt issuance costs 3,990 3,786
Impairment of oil and gas properties 289,085 0
Stock-based compensation expense 11,397 6,277
Deferred income taxes (702) 19,294
Increase in allowance for doubtful accounts 1,112 427
Other operating expenses 2,145 4,744
Derivative activities:
Total (gains) losses (160,222) 2,796
Cash settlements on derivatives 106,975 26,731
Changes in assets and liabilities:
Decrease (increase) in accounts receivable 21,985 (6,690)
Increase in other assets (919) (2,073)
Decrease in accounts payable and accrued expenses (29,882) (12,344)
Decrease in other liabilities (10,226) (5,108)
Net cash provided by operating activities 144,419 164,267
Cash flows from investing activities:
Capital expenditures:
Development of oil and natural gas properties (58,370) (157,281)
Purchases of other property and equipment (3,951) (12,394)
Changes in capital investment accruals (10,347) (4,613)
Acquisition of properties and equipment and other (2,104) (2,819)
Proceeds from sale of property and equipment and other 250 969
Net cash used in investing activities (74,522) (176,138)
Cash flows from financing activities:
Borrowings under RBL credit facility 228,900 252,182
Repayments on RBL credit facility (230,750) (242,182)
Dividends paid on common stock (19,447) (29,431)
Purchase of treasury stock 0 (36,139)
Shares withheld for payment of taxes on equity awards and other (980) (1,239)
Net cash used in financing activities (22,277) (56,809)
Net increase (decrease) in cash and cash equivalents 47,620 (68,680)
Cash and cash equivalents:
Beginning 0 68,680
Ending $ 47,620 $ 0

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

~~Table of Contents~~

BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Basis of Presentation

“Berry Corp.” refers to Berry Corporation (bry), a Delaware corporation, which is the sole member of Berry Petroleum Company, LLC ("(“Berry ~~LLC"~~LLC”).

As the context may require, the “Company”, “we”, “our” or similar words refer to (i) Berry Corp. and Berry LLC, its consolidated subsidiary, as a whole or (ii) either Berry Corp. or Berry LLC.

Nature of Business

Berry Corp. is an independent oil and natural gas company that was incorporated under Delaware law in February 2017 and its common stock began trading on NASDAQ under the symbol ~~"bry"~~“bry” in July 2018. Berry Corp. operates through its wholly-owned subsidiary, Berry LLC. Our properties are located onshore in the United States (the “U.S.”), in California ~~(in~~(primarily in the San Joaquin ~~and Ventura basins)~~basin), Utah (in the Uinta basin), and Colorado (in the Piceance basin).

Principles of Consolidation and Reporting

The condensed consolidated financial statements were prepared in conformity with U.S. generally accepted accounting principles (“GAAP”), which requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. In management’s opinion, the accompanying financial statements contain all normal, recurring adjustments that are necessary to fairly present our interim unaudited condensed consolidated financial statements. We eliminated all significant intercompany transactions and balances upon consolidation. For oil and gas exploration and production joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements.

We prepared this report pursuant to the rules and regulations of the U.S. Security and Exchange Commission (“SEC”) applicable to interim financial information, which permit the omission of certain disclosures to the extent they have not changed materially since the latest annual financial statements. We believe our disclosures are adequate to make the disclosed information not misleading. The results reported in these unaudited condensed consolidated financial statements may not accurately forecast results for future periods. This Quarterly Report on Form 10-Q should be read in conjunction with the consolidated financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, ~~2019.~~2020.

Reclassification

We reclassified certain prior year amounts in the cash flow statements to conform to the current year presentation. These reclassifications had no material impact on the financial statements.

~~New~~Recently Adopted Accounting Standards ~~Issued, But Not Yet Adopted~~

In ~~February 2016,~~December 2019, the ~~Financial Accounting Standards Board ("FASB")~~FASB issued rules ~~requiring lessees to recognize assets and liabilities on~~which simplify the ~~balance sheet~~accounting for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. As an emerging growth company, we have elected to delay the adoption ofincome taxes. We adopted these rules ~~until they are applicable to non-SEC issuers. During~~in the ~~second~~first quarter of ~~2020, this adoption date was further delayed by FASB until fiscal years beginning after December 15,~~ 2021 including interim periods within those fiscal years. We are currently identifying our lease population in accordance with the new lease standard. We expect the adoption of these rules to increase other assets and other liabilities on our balance sheet and we are currently evaluating thewhich did not have a material impact on our ~~consolidated results of operations.~~financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

In December 2019, the FASB issued rules which simplify the accounting for income taxes. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers which is for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We are currently evaluating the impact of these rules on our consolidated financial statements.

In March 2020, the FASB issued rules providing optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by the reference rate reform, if certain criteria are met. The optional expedient for contract modifications applies to contract modifications that replace a reference rate affected by the reference rate reform, such as the London Interbank Offered Rate (“LIBOR”). Entities may elect to apply the amendments for contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 through December 31, 2022. We are currently evaluating the impact of these rules on our consolidated financial statements.

Note 2—Debt

The following table summarizes our outstanding debt:


		September 30, 2020		December 31, 2019		Interest Rate	Maturity	Security		June 30, 2021		December 31, 2020		Interest Rate	Maturity	Security
		(in thousands)								(in thousands)
RBL Facility	RBL Facility	$	0	$	1,850	variable rates 4.0% (2020) and 5.5% (2019), respectively	July 29, 2022	Mortgage on 85% of Present Value of proven oil and gas reserves and lien on certain other assets	RBL Facility	$	0	$	0	variable rates 3.0% (2021) and 4.0% (2020), respectively	July 29, 2022	Mortgage on 85% of Present Value of proven oil and gas reserves and lien on certain other assets
2026 Notes	2026 Notes	400,000		400,000		7.0%	February 15, 2026	Unsecured	2026 Notes	400,000		400,000		7.0%	February 15, 2026	Unsecured
Long-Term Debt - Principal Amount	Long-Term Debt - Principal Amount	400,000		401,850					Long-Term Debt - Principal Amount	400,000		400,000
Less: Debt Issuance Costs	Less: Debt Issuance Costs	(6,781)		(7,531)					Less: Debt Issuance Costs	(5,991)		(6,520)
Long-Term Debt, net	Long-Term Debt, net	$	393,219	$	394,319				Long-Term Debt, net	$	394,009	$	393,480

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, debt issuance costs for the RBL Facility (as defined below) reported in “other noncurrent assets” on the balance sheet were approximately $8$5 million and ~~$11~~$7 million net of amortization, respectively. At ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, debt issuance costs, net of amortization, for the unsecured notes due February 2026 (the “2026 Notes”) reported in ~~Long-Term~~“Long-Term Debt, ~~net~~net” on the balance sheet were approximately $7$6 million and $8$7 million, respectively.

For ~~each of~~ the three ~~month periods~~months ended ~~September~~June 30, ~~2020~~2021 and ~~September 30, 2019,~~2020, the amortization expense for ~~both~~ the RBL Facility and 2026 Notes ~~was~~were both approximately $1 million and was included in “interest expense” in the condensed consolidated statements of operations. For each of the ~~nine~~six month periods ended ~~September~~June 30, ~~2020~~2021 and ~~September 30, 2019,~~2020, the amortization expense for both the RBL Facility and 2026 Notes was approximately $4$3 million.

Fair Value

Our debt is recorded at the carrying amount on the balance sheets. The carrying amount of the RBL Facility approximates fair value because the interest rates are variable and reflect market rates. The fair value of the 2026 Notes was approximately ~~$314~~$408 million and ~~$376~~$337 million at ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively.

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~~BERRY CORPORATION (bry)~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~(Unaudited)~~

The RBL Facility

On July 31, 2017, we entered into a credit agreement that provided for a revolving loan with up to $1.5 billion of commitment, subject to a reserve borrowing base (“RBL Facility”). ~~In June 2020, we completed our scheduled semi-annual borrowing base redetermination under our~~The RBL Facility ~~which resulted~~provides a letter of credit subfacility for the issuance of letters of credit in ~~a decrease~~an aggregate amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing ~~base to $200 million from $500 million; decrease to the elected commitments to $200 million from $400 million; limitation on the maximum borrowing~~ availability for revolving loans under the RBL Facility to $150 million until the next semi annual borrowing base redetermination (scheduled to occur in November 2020); the implementation of certain anti-cash hoarding provisions, including the requirement to repay outstanding loans on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $30 million; and further limits dividends and share repurchases. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.dollar for dollar basis. Borrowing base redeterminations generally become effective each May and November, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations. The RBL Facility has an elected commitment feature that allows us to increase commitments to the amount of our borrowing base with lender approval. In April 2021, we completed our scheduled semi-annual borrowing base redetermination under our RBL Facility, which resulted in a reaffirmed borrowing base and the Company's elected commitment at $200 million with no further borrowing restrictions beyond the covenants noted below.

The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights and remedies, including foreclosure on all of the collateral. The RBL Facility contains certain anti-cash hoarding provisions, including the requirement to repay outstanding loans on a weekly basis in the amount of any

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

cash on the balance sheet (subject to certain exceptions) in excess of $30 million; and further limits to dividends and share repurchases. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.

The RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a Leverage Ratio of no more than 4.0 to 1.0 and (ii) a Current Ratio of at least 1.0 to 1.0. The RBL Facility also contains customary restrictions. As of ~~September~~June 30, ~~2020,~~2021, our Leverage Ratio and Current Ratio were ~~1.5~~2.1 to 1.0 and ~~2.7~~2.2 to 1.0, respectively. In addition, the RBL Facility currently provides that to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. We were in compliance with all financial covenants under the RBL Facility as of ~~September~~June 30, ~~2020.~~2021.

The RBL Facility permits us to repurchase equity and indebtedness, among other things, if availability is equal to or greater than 20% of the elected commitments or borrowing base, whichever is in effect, and our pro forma leverage ratio is less than or equal to 2.5 to 1.0.

As of ~~September~~June 30, ~~2020,~~2021, we had 0 borrowings outstanding, $7 million in letters of credit outstanding, and approximately ~~$143~~$193 million of available borrowings capacity under the RBL Facility.

Bond Repurchase Program

In February 2020, our Board of Directors adopted a program to spend up to $75 million for the opportunistic repurchase of our 2026 Notes. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any bonds under this program.

Corporate Organization

Berry Corp., as Berry LLC’s parent company, has no independent assets or operations. Any guarantees of potential future registered debt securities by Berry Corp. or Berry LLC would be full and unconditional. Berry Corp. and Berry LLC currently do not have any other subsidiaries. In addition, there are no significant restrictions upon the ability of Berry LLC to distribute funds to Berry Corp. by distribution or loan other than under the RBL Facility. None of the assets of Berry Corp. or Berry LLC represent restricted net assets.

The RBL Facility permits Berry LLC to make distributions to Berry Corp. so long as both before and after giving pro forma effect to such distribution no default or borrowing base deficiency exists, availability equals or exceeds 20% of the then effective borrowing base, and Berry Corp. demonstrates a pro forma leverage ratio less than or equal to 2.5 to 1.0. The conditions are currently met with significant margin.

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~~BERRY CORPORATION (bry)~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~(Unaudited)~~

Note 3—Derivatives

We utilize derivatives, such as swaps, puts and calls, to hedge a portion of our forecasted oil and gas production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices, which addresses our market risk. We target covering our operating expenses and a majority of our fixed charges, ~~including~~which includes capital ~~for sustained~~needed to sustain production levels, as well as interest and dividends as applicable, with the oil and gas sales hedges for a period of up to two years out. Additionally, we target fixing the price for a large portion of our natural gas purchases used in our steam operations for up to two years. We also, from time to time, have entered into agreements to purchase a portion of the natural gas we require for our operations, which we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions.

For fixed-price oil and gas sales swaps, we are the seller, so we make settlement payments for prices above the indicated weighted-average price per barrel and per ~~MMBtu,~~mmbtu, respectively, and receive settlement payments for prices below the indicated weighted-average price per barrel and per ~~MMBtu,~~mmbtu, respectively.

~~For our purchased oil calls, we would receive settlement payments for prices above the indicated weighted-average price per barrel~~

Table of ~~Brent.~~Contents

BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

For fixed-price gas purchase swaps, we are the buyer so we make settlement payments for prices below the weighted-average price per ~~MMBtu~~mmbtu and receive settlement payments for prices above the weighted-average price per ~~MMBtu.~~mmbtu.

We use oil and gas swaps and puts to protect our sales against decreases in oil and gas prices. We also use swaps to protect our natural gas purchases against increases in prices. We do not enter into derivative contracts for speculative trading purposes and have not accounted for our derivatives as cash-flow or fair-value hedges. The changes in fair value of these instruments are recorded in current earnings. Gains (losses) on oil and gas sales hedges are classified in the revenues and other section of the statement of operations, while natural gas purchase hedges are included in expenses and other section of the statement of operations.

As of ~~September~~June 30, ~~2020,~~2021, we had the following crude oil production and gas ~~purchases~~purchase hedges.

Q4 2020 1H 2021 2H 2021
Fixed Price Oil Swaps (Brent):
  Hedged volume (MBbls) 2,208 3,438 2,084
  Weighted-average price ($/Bbl) $ 59.85 $ 45.82 $ 46.17
Purchased Oil Calls Options (Brent):
Hedged volume (MBbls) 276 0 0
Weighted-average price ($/Bbl) $ 65.00 $ 0 $ 0
Fixed Price Gas Purchase Swaps (Kern, Delivered):
  Hedged volume (MMBtu) 5,060,000 9,045,000 5,535,000
  Weighted-average price ($/MMBtu) $ 2.76 $ 2.71 $ 2.73
Fixed Price Gas Purchase Swaps (SoCal Citygate):
  Hedged volume (MMBtu) 155,000 0 0
  Weighted-average price ($/MMBtu) $ 3.80 $ 0 $ 0


	Q3 2021		Q4 2021		FY 2022




Fixed Price Oil Swaps (Brent):
Hedged volume (mbbls)	1,318		1,318		1,095
Weighted-average price ($/bbl)	$	48.66	$	48.66	$	60.00










Fixed Price Gas Purchase Swaps (Kern, Delivered):
Hedged volume (mmbtu)	4,830,000		2,085,000		0
Weighted-average price ($/mmbtu)	$	2.83	$	2.95	$	0

~~Table~~ These swap positions effectively cancel each other while resulting in a mark-to-market gain of ~~Contents~~

~~BERRY CORPORATION (bry)~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~(Unaudited)~~

$1 million. This gain will be cash settled in 2021 as the positions expire.

Our commodity derivatives are measured at fair value using industry-standard models with various inputs including publicly available underlying commodity prices and forward curves, and all are classified as Level 2 in the required fair value hierarchy for the periods presented. These commodity derivatives are subject to counterparty netting. The following tables present the fair values (gross and net) of our outstanding derivatives as of ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019:~~2020:


		September 30, 2020								June 30, 2021
		Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented on the Balance Sheet			Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
		(in thousands)								(in thousands)
Assets:	Assets:								Assets:
Commodity Contracts	Commodity Contracts	Current assets	$	60,307	$	(2,649)	$	57,658	Commodity Contracts	Current assets	$	20,876	$	(9,361)	$	11,515
Commodity Contracts		Non-current assets	2,703		(693)		2,011

Liabilities:	Liabilities:								Liabilities:
Commodity Contracts	Commodity Contracts	Current liabilities	(2,986)		2,649		(337)		Commodity Contracts	Current liabilities	(70,837)		9,361		(61,476)
Commodity Contracts	Commodity Contracts	Non-current liabilities	(1,871)		693		(1,179)		Commodity Contracts	Non-current liabilities	(4,058)		0		(4,058)
Total derivatives	Total derivatives		$	58,153	$	—	$	58,153	Total derivatives		$	(54,019)	$	—	$	(54,019)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)


		December 31, 2019								December 31, 2020
		Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented on the Balance Sheet			Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
		(in thousands)								(in thousands)
Assets:	Assets:								Assets:
Commodity Contracts	Commodity Contracts	Current assets	$	17,799	$	(8,633)	$	9,166	Commodity Contracts	Current assets	$	15,217	$	(12,710)	$	2,507
Commodity Contracts		Non-current assets	773		(248)		525

Liabilities:	Liabilities:								Liabilities:
Commodity Contracts	Commodity Contracts	Current liabilities	(13,450)		8,633		(4,817)		Commodity Contracts	Current liabilities	(36,031)		12,710		(23,321)
Commodity Contracts		Non-current liabilities	(389)		248		(141)

Total derivatives	Total derivatives		$	4,733	$	—	$	4,733	Total derivatives		$	(20,814)	$	—	$	(20,814)

By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We do not receive collateral from our counterparties.

We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, our RBL Facility prevents us from entering into hedging arrangements that are secured, except with our lenders and their affiliates that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standards & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives which partially mitigates the counterparty nonperformance risk.

Note 4—Lawsuits, Claims, Commitments and Contingencies

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~~BERRY CORPORATION (bry)~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~(Unaudited)~~

other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, fines and penalties, remediation costs, or injunctive or declaratory relief.

We accrue ~~reserves~~ for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded ~~any reserve balances~~a material balance at ~~September~~June 30, ~~2020 and~~2021 or December 31, ~~2019.~~2020. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of ~~reserves accrued~~accruals on our balance sheet would not be material to our consolidated financial position or results of operations.

We, or our subsidiary, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of ~~September~~June 30, ~~2020,~~2021, we are not aware of material indemnity claims pending or threatened against us.

We have certain commitments under contracts, including purchase commitments for goods and services. Prior to our 2017 emergence, Berry entered into a Carry and Earning Agreement with Encana, effective June 7, 2006, in connection with our Piceance assets which, among other things, required us to either build a road or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019, we fulfilled the obligation by delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of such access, which we dispute. We will continue to defend the matter vigorously, however, given the uncertainty of litigation and the ~~preliminary~~ stage of the case, among other things, at this time we cannot estimate the ~~reasonable~~likelihood or an amount of possible loss, ~~if any,~~that may result from this action.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

agreements are for approximately 10,000 mmbtu/d beginning October 2021 through October 2036 and approximately 5,500 mmbtu/d beginning November 2021 through December 2024 for a total commitment of $32 million.

Securities Litigation Matter

On January 21, 2021, motions were filed in the Torres Lawsuit as plaintiffs sought to be appointed lead plaintiff and lead counsel. We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the preliminary stage of the case, and the legal standards that must be met for, among other things, class certification and success on the merits, we cannot reasonably estimate the possible loss or range of loss that may result from this action.

Note 5—Equity

Cash Dividends

Our Board of Directors approved a ~~$0.12~~regular cash dividend of $0.04 per share ~~quarterly~~on our common stock for the first and second quarters of 2021. We paid the first and the second quarter cash dividend in April and July 2021, respectively. The Board of Directors approved a $0.06 per share regular cash dividend on our common stock for the ~~first~~third quarter of ~~2020,~~2021, which weis expected to be paid in ~~April 2020. In April 2020, in connection with the current low oil price environment, we temporarily suspended our quarterly dividend until oil prices recover.~~October 2021.

Stock Repurchase Program

In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at ~~that~~the time, they authorized ~~initial~~ repurchases of up to $50 million under the program. The Company repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million ~~as of December 31,~~in 2018 and 2019. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million of our $100 million repurchase program. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. ~~For the nine months ended September 30, 2020, we did~~We have 0t ~~repurchase~~repurchased any shares under the stock repurchase ~~program.~~program since 2019.

Stock-Based Compensation

In ~~March 2020,~~February 2021, the Company granted awards of ~~1,817,656~~1,832,941 shares of restricted stock units (“RSUs”), which will vest annually in equal amounts over three years and ~~1,278,877~~997,840 performance-based restricted stock units (“PSUs”), which will cliff vest, if at all, at the end of a three year performance ~~period subject to both an absolute~~period. The fair value of these awards was approximately $14 million.

The RSUs awarded in February 2021 are solely time-based awards. Of the PSUs awarded in February 2021, (a) 50% of such will vest, if at all, based on a total stockholder return (“~~Absolute~~ TSR”) performance metric ~~and a relative total stockholder return (“Relative TSR”~~(the “TSR PSUs”), which is defined as the capital gains per share of stock plus dividends paid assuming reinvestment, with TSR

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(Unaudited)

~~performance metric, as further discussed~~measured on an absolute basis and ~~defined below. The fair value~~relative to the TSR of ~~these awards was approximately $32 million.~~

~~The RSUs awarded are solely time-based awards. The PSUs awarded include a market objective measured against both Absolute TSR~~the 39 exploration and ~~Relative TSR to~~production companies in the Vanguard World Fund - Vanguard Energy ETF ~~index (the “Index”~~Index plus the S&P SmallCap 600 Value Index (collectively, the “Peer Group”) during the performance period; and (b) the other 50% of such will vest, if at all, based on the Company's average cash returned on invested capital (“CROIC PSUs”) over the performance ~~period, assuming the reinvestment of dividends.~~period. Depending on the results achieved during the three-year performance period, the actual number of shares that a grant recipient receives at the end of the period may range from 0% to 250% of the TSR PSUs granted and from 0% to 200% of the CROIC PSUs granted.

The fair value of the RSUs and CROIC PSUs was determined using the grant date stock price. The fair value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the ~~Index~~Peer Group over the performance periods. The expected volatility of the Company’s common stock at the date of grant was estimated based on average volatility rates for the Company and selected guideline public companies. The dividend yield assumption was based on the then current annualized declared dividend. The risk-free interest rate assumption was based on observed interest rates consistent with the approximate three-year performance measurement period.

Note 6—Supplemental Disclosures to the Financial Statements

Other current assets reported on the condensed consolidated balance sheets included the following:


		September 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
		(in thousands)					(in thousands)
Prepaid expenses	Prepaid expenses	$	4,526	$	4,577	Prepaid expenses	$	12,544	$	3,592

Materials and supplies	Materials and supplies	11,731		10,544		Materials and supplies	10,847		11,666
Oil inventories	Oil inventories	3,409		3,432		Oil inventories	3,273		3,490
Other	Other	652		846		Other	226		652
Total other current assets	Total other current assets	$	20,318	$	19,399	Total other current assets	$	26,890	$	19,400

Other non-current assets at ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, included approximately $8$5 million and ~~$11~~$7 million of deferred financing costs, net of amortization, respectively.

Accounts payable and accrued expenses on the condensed consolidated balance sheets included the following:

September 30, 2020 December 31, 2019
(in thousands)
Accounts payable-trade $ 6,596 $ 13,986
Accrued expenses 45,841 57,078
Royalties payable 12,282 25,385
Taxes other than income tax liability 12,390 9,150
Accrued interest 3,500 10,500
Dividends payable 5 9,888
Asset retirement obligation - current portion 13,700 25,208
Other 923 616
Total accounts payable and accrued expenses $ 95,237 $ 151,811

We reclassified certain accrued expenses to accounts payable trade accounts for the prior period to conform to the current year presentation. These reclassifications had no impact on the financial statements.


	June 30, 2021		December 31, 2020
	(in thousands)
Accounts payable-trade	$	11,820	$	11,055
Accrued expenses	56,223		43,452
Royalties payable	17,522		15,150
Greenhouse gas liability - current portion	29,060		35,554
Taxes other than income tax liability	11,439		10,118
Accrued interest	10,500		10,783
Dividends payable	3,217		0
Asset retirement obligations - current portion	20,000		25,000
Other	805		873
Total accounts payable and accrued expenses	$	160,586	$	151,985

The increase of $4 million in the long-term portion of the asset retirement ~~obligation~~obligations from ~~$124~~$135 million at December 31, ~~2019~~2020 to ~~$136~~$139 million at ~~September~~June 30, ~~2020~~2021 was due to $7$5 million of accretion, $6$1 million of liabilities incurred and reclassification of $5 million from current to long-term portion due to changes in anticipated spending and regulatory requirements. These increases were partially offset by $7 million of liabilities settled during the period.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

reclassification of $12 million from the current to long-term portion due to changes in anticipated spending and regulatory requirements. These increases were partially offset by $12 million of liabilities settled during the period.

Other non-current liabilities at ~~September~~June 30, ~~2020~~2021 and December 31, ~~2019~~2020 included approximately ~~$35~~$5 million and ~~$33 million of~~0 greenhouse gas liability, respectively.

Supplemental Information on the Statement of Operations

For the three months ended ~~September~~June 30, ~~2020,~~2021, other operating expense ~~was $2 million and~~ mainly consisted of ~~excess abandonment costs~~$2 million of supplemental property tax assessments and ~~oil tank storage fees.~~royalty audit charges, mostly offset by $2 million of employee retention credits. For three months ended ~~September~~June 30, ~~2019~~2020, other operating income was $1 million and mainly consisted of ~~proceeds from the sale of assets,~~sales tax and bankruptcy-related refunds, partially offset by excess abandonment costs ~~in 2019.~~and drilling rig standby charges.

For the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~2019~~2020 other operating expenses were ~~$3 million and $4 million, respectively. These~~$1 million. For the six months ended June 30, 2021, other operating expenses mainly consisted of approximately $3 million of supplemental property tax assessments and royalty audit charges and tank rental costs, partially offset by $2 million of employee retention credits. For the six months ended June 30, 2020, other operating expense mainly consist of excess abandonment costs, ~~oil tank storage fees, and~~ drilling rig standby charges, partially offset by sales tax and ~~other refunds in 2020 and excess abandonment costs in 2019.~~bankruptcy-related refunds.

Supplemental Cash Flow Information

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

Nine Months Ended
September 30,
2020 2019
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties $ 1,013 $ 8,474
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized $ 29,962 $ 30,136
Income taxes $ 222 $ 0




	Six Months Ended June 30,
	2021		2020
	(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties	$	1,437	$	911
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	$	14,925	$	15,527
Income taxes payments	$	0	$	2

Cash and cash equivalents consist primarily of highly liquid investments with original maturities of three months or less and are stated at cost, which approximates fair value. As part of our cash management system, we use a controlled disbursement account to fund cash distribution checks presented for payment by the holder. Checks issued but not yet presented to banks may result in overdraft balances for accounting purposes and have been included in ~~"accounts~~“accounts payable and accrued ~~expenses"~~expenses” in the condensed consolidated balance sheets, amounts are ~~immaterial for these periods.~~approximately $2 million as of June 30, 2021 and December 31, 2020.

Note 7—Earnings Per Share

We calculate basic earnings (loss) per share by dividing net income (loss) by the weighted-average number of common shares outstanding for each period presented. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, are considered common shares outstanding and are included in the computation of net income (loss) per share.

The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the three and ~~nine~~six months ended ~~September~~June 30, 2021 and 2020, 0 incremental RSUs or PSUs were included in the diluted EPS calculation as their effect was anti-dilutive under the “if converted” method. For the three and nine months ended September 30, 2019 we included 69,000 and 145,000 incremental RSUs in the diluted EPS calculation and 0 incremental PSUs were included in the EPS calculation due to their contingent nature.

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)


		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
		(in thousands except per share amounts)									(in thousands except per share amounts)
Basic EPS calculation	Basic EPS calculation									Basic EPS calculation
Net (loss) income		$	(18,864)	$	52,649	$	(199,065)	$	50,523
Net loss										Net loss	$	(12,881)	$	(64,901)	$	(34,203)	$	(180,201)

Weighted-average shares of common stock outstanding	Weighted-average shares of common stock outstanding	79,879		80,982		79,776		81,703		Weighted-average shares of common stock outstanding	80,471		79,795		80,294		79,702
Basic (loss) earnings per share		$	(0.24)	$	0.65	$	(2.50)	$	0.62
Basic loss per share										Basic loss per share	$	(0.16)	$	(0.81)	$	(0.43)	$	(2.26)
Diluted EPS calculation	Diluted EPS calculation									Diluted EPS calculation
Net (loss) income		$	(18,864)	$	52,649	$	(199,065)	$	50,523
Net loss										Net loss	$	(12,881)	$	(64,901)	$	(34,203)	$	(180,201)

Weighted-average shares of common stock outstanding	Weighted-average shares of common stock outstanding	79,879		80,982		79,776		81,703		Weighted-average shares of common stock outstanding	80,471		79,795		80,294		79,702
Dilutive effect of potentially dilutive securities(1)	Dilutive effect of potentially dilutive securities(1)	0		69		0		145		Dilutive effect of potentially dilutive securities(1)	0		0		0		0
Weighted-average common shares outstanding - diluted	Weighted-average common shares outstanding - diluted	79,879		81,051		79,776		81,848		Weighted-average common shares outstanding - diluted	80,471		79,795		80,294		79,702
Diluted (loss) earnings per share		$	(0.24)	$	0.65	$	(2.50)	$	0.62
Diluted loss per share										Diluted loss per share	$	(0.16)	$	(0.81)	$	(0.43)	$	(2.26)

__________

(1) ~~NaN potentially~~We excluded approximately 2.9 million and 0.8 million dilutive securities ~~were included in computing diluted (loss) earnings per share~~from the dilutive weighted-average common shares outstanding for the three ~~and nine~~ months ended ~~September~~June 30, 2021 and 2020, because their effect was anti-dilutive. We excluded approximately 2.6 million and 0.8 million dilutive securities from the dilutive weighted-average common shares outstanding for the six months ended June 30, 2021 and 2020, because their effect ~~of inclusion would have been~~was anti-dilutive.

~~Note 8—Revenue Recognition~~

We account for revenue in accordance with the Accounting Standards Codification 606, Revenue from Contracts with Customers, which we adopted on January 1, 2019, using the modified retrospective method, which was applied to all contracts that were not completed as of that date. Prior period results were not adjusted and continue to be reported under the accounting standards in effect for the prior period. The new standard did not affect the timing of our revenue recognition and did not impact net income; accordingly, we did not record an adjustment to the opening balance of retained earnings.

We adopted the practical expedient related to disclosing the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied at the end of the reporting period. The performance obligations that are unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these are wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation as well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation.

~~We derive substantially all of our revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with the remaining revenue generated from sales of electricity and marketing activities.~~

The following is a description of our principal activities from which we generate revenue. Revenues are recognized when a customer obtains control of promised goods or services, in an amount that reflects the consideration we expect to receive in exchange for those goods or services.

~~Oil, Natural Gas and NGLs~~

We recognize revenue from the sale of our oil, natural gas and NGL production when delivery has occurred and control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our NGL contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the amount that we expect to receive once we are able to adequately estimate the consideration (i.e., when market prices are known). Our contracts with customers typically require payment within 30 days following invoicing.

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~~BERRY CORPORATION (bry)~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~(Unaudited)~~

~~Electricity Sales~~

The electrical output of our cogeneration facilities that is not used in our operations is sold to the California market based on market pricing, which includes capacity payments. The majority of the portion sold from 3 of our cogeneration facilities is sold under long-term contracts to 2 California utility companies, based on market pricing. Revenue is recognized over time when obligations under the terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the electricity. Revenue is measured as the amount of consideration we expect to receive based on average index pricing with payment due the month following delivery. Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on seasonality, which is consistent with how we earn the capacity payment. Capacity payments are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the case of capacity payments. We report electricity revenue as electricity sales on our consolidated statements of operations.

~~Marketing Revenue~~

Marketing revenue primarily includes our activities associated with transporting and marketing third-party volumes. These sales are made under the same agreements with the same purchaser as our natural gas sales discussed above. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Revenues are presented excluding costs incurred prior to transferring control of these volumes to the customer, or the costs to purchase these volumes when we are acting as the principal. The revenues and expenses related to the sale and purchase of third-party volumes are presented separately as marketing revenue and marketing expenses on the condensed consolidated statements of operations.

~~Disaggregated Revenue~~

~~As a result of adoption of this standard, we are now required to disclose the following information regarding revenue from contracts with customers on a disaggregated basis.~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
(in thousands)
Oil sales $ 88,453 $ 136,710 $ 274,275 $ 392,325
Natural gas sales 3,347 4,067 9,549 14,867
Natural gas liquids sales 439 473 1,028 2,067
Electricity sales 8,744 7,460 19,089 22,553
Marketing revenues 330 413 1,075 1,657
Other revenues 0 40 53 261
Revenues from contracts with customers 101,313 149,163 305,069 433,730
(Losses) gains on oil derivatives (11,564) 45,509 157,398 7,546
Total revenues and other $ 89,749 $ 194,672 $ 462,467 $ 441,276

~~Note 9—Oil and Natural Gas Properties~~

We evaluate the impairment of our proved and unproved oil and natural gas properties whenever events or changes in circumstance indicate that a property’s carrying value may not be recoverable. If the carrying amount of the proved properties exceeds the estimated undiscounted future cash flows, we record an impairment charge to reduce the carrying values of proved properties to their estimated fair value. We estimate the fair values of proved properties using valuation techniques that consider the market approach for values from the recent sale of similar properties, if applicable, and the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future

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~~BERRY CORPORATION (bry)~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~(Unaudited)~~

operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount rate. These inputs require significant judgments and estimates by our management at the time of the valuation which can change significantly over time. The underlying commodity prices are embedded in our estimated cash flows and are the product of a process that begins with the relevant forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors our management believes will impact realizable prices. The fair value was estimated using inputs characteristic of a Level 3 fair value measurement.

We evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be recoverable. If exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results.

As of March 31, 2020, we performed impairment tests with respect to our proved and unproved oil and gas properties as a result of significant declines in oil prices during the latter part of the first quarter. These declines were driven by the uncertainty surrounding the outbreak of a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19 (“COVID-19”) and other macroeconomic events such as the geopolitical tensions between the Organization of Petroleum Exporting Countries ("OPEC") and Russia. The COVID-19 pandemic and related economic repercussions, coupled with actions taken by OPEC and other oil producing nations ("OPEC+"), created significant volatility, uncertainty, and turmoil in the oil and gas industry, which have negatively affected and are expected to continue to negatively affect our business. Low oil prices are expected to continue for some period as reflected by futures forward curves for crude.

Consequently, we recorded a non-cash pre-tax asset impairment charge of $289 million during the first quarter of 2020 on properties in Utah and certain California locations. We evaluated our proved properties in accordance with accounting guidance and fair value techniques utilizing the period-end forward price curve, as well as assessing projects we determine we would not pursue in the foreseeable future given the current environment. We believe our current plans and exploration and development efforts will allow us to realize the carrying value of our unproved property balance.

~~We did 0t record an impairment charge for the second or third quarter of 2020, as there were no triggering events.~~

~~Note 10—Income Taxes~~

The COVID-19 pandemic and related economic repercussions, coupled with OPEC+ actions, created significant volatility, uncertainty, and turmoil in the oil and gas industry, which have negatively affected and are expected to continue to negatively affect our business. As a result, after evaluating the positive and negative evidence, we determined that it was more likely than not that a large portion of our tax credits recorded in 2019 and other deferred tax assets would not be realized. Accordingly, we recognized a valuation allowance on our deferred tax assets for the quarter ended March 31, 2020 in the amount of $51 million. As of the quarter ended September 30, 2020, this amount is $56 million. The valuation allowance was the key contributor in the decrease in our effective tax rate from 28% for both the three and nine months ended September 30, 2019 to 10% and (1)% for the three and nine months ended September 30, 2020, respectively.

During the third quarter 2020, the Internal Revenue Service issued final regulations implementing interest expense deduction limitation rules under section 163(j) of the Internal Revenue Code. The final regulations changed certain rules on the computation and limitation of interest expense amounts and are applicable for tax years beginning on or after November 13 2020. Early adoption is permitted for tax years beginning after December 31, 2017. We assessed the impact of these regulations being issued in the third quarter. As a result, we recognized the entirety of its $14 million of uncertain tax benefits that were recorded as of December 31, 2019. The recognition of these uncertain tax benefits did not affect the effective tax rate.

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note ~~11—Acquisition~~8—Revenue Recognition

~~In May 2020, we acquired approximately 740 net acres in the North Midway Sunset Field for approximately $5 million.~~ We ~~paid $2 million at closing~~derive most of our revenue from sales of oil, natural gas and NGLs, with the remaining ~~$3 million was paid~~revenue generated from sales of electricity and marketing activities related to transporting and marketing third-party volumes.

The following ~~our first production from this property, in~~table provides disaggregated revenue for the ~~fourth quarter 2020. This property is adjacent to,~~three and ~~extends, our existing producing area~~six months ended June 30, 2021 and we have identified numerous future drilling locations. We believe additional opportunities exist in other productive reservoirs of this property. We also acquired all existing idle wells on this property, some of which we plan to return to production in the near future as price and strategy dictate. We will plug and abandon the remaining idle wells pursuant to the California Idle Well Management Program. We recorded a $6 million liability for asset retirement obligations of the existing wells on this property.2020:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(in thousands)
Oil sales	$	141,309	$	67,512	$	263,668	$	185,822
Natural gas sales	5,415		2,834		17,492		6,202
Natural gas liquids sales	1,051		169		1,880		589
Electricity sales	6,888		4,884		16,957		10,345
Marketing revenues	121		292		2,355		745
Other revenues	118		29		255		53
Revenues from contracts with customers	154,902		75,720		302,607		203,756
(Losses) gains on oil and gas sales derivatives	(55,653)		(42,267)		(109,157)		168,962
Total revenues and other	$	99,249	$	33,453	$	193,450	$	372,718

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our interim unaudited consolidated financial statements and related notes presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and related notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 (the “Annual Report”) filed with the Securities and Exchange Commission (“SEC”). When we use the terms “we,” “us,” “our,” “Berry,” the “Company” or similar words in this report, we are referring to, as the context may require, (i) Berry Corporation (bry), a Delaware corporation (formerly known as Berry Petroleum Corporation, and also referred to herein as ~~��~~“Berry Corp.”) together with its wholly owned subsidiary, Berry Petroleum, LLC, a Delaware limited liability company (also referred to herein as “Berry LLC”), or (ii) either Berry Corp. or Berry LLC.

Our Company

We are a western United States independent upstream energy company ~~with a focus~~focused on the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in ~~conventional reservoirs.~~California.

In the aggregate, our assets are characterized by high oil content. ~~Most~~The overwhelming majority of our productive assets are located in the oil-rich reservoirs in the San Joaquin basin of California, which has more than 150 years of production history and substantial remaining oil in place. As a result of the substantial data produced over the basin’s long history, its reservoir characteristics are well understood, ~~leading to~~which enables predictable, repeatable, low geological risk and low-cost development opportunities. In California, we focus on conventional, shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional resource plays. We also have assets in the ~~low-cost,~~low-operating cost, oil-rich reservoirs in the Uinta basin of Utah and in the low geologic risk natural gas resource ~~plays~~play in the Piceance basin in Colorado. We believe that the successful execution of our strategy across our low-declining, oil-weighted production base ~~and~~coupled with extensive inventory of identified drilling locations ~~should result in~~with attractive full-cycle economics will support our ~~ability, in appropriate oil price environments,~~objectives to ~~return capital to our stockholders and demonstrate long-term, capital efficient, consistent, and predictable production growth while living within~~generate “Levered Free Cash Flow” (a non-GAAP financial measure discussed under “How We Plan and Evaluate Operations” in this report). to fund our operations, optimize capital efficiency, and return capital to stockholders, while maintaining a low leverage profile and focusing on attractive organic and strategic growth through commodity price cycles.

We have a progressive approach to evolving and growing the business in today's dynamic oil and gas industry. Our strategy includes proactively engaging the many forces driving our industry and impacting our operations, whether positive or negative, to maximize our assets, create value for shareholders, and support environmental goals that align with a more positive future.

~~Business Environment, Market Conditions and Outlook~~

Our operating and financial results, and those of the oil and gas industry as a whole, are heavily influenced by commodity prices. Oil and gas prices and differentials have, and may continue to, fluctuate significantly as a result of numerous market-related variables, including global geopolitical and economic conditions. As discussed below, our 2020 operating and financial results have been adversely impacted by the deterioration and prolonged weakness in commodity prices resulting from the COVID-19 pandemic and certain actions by foreign oil and gas producers. Commodity prices are currently expected to remain depressed for an extended period of time.

The extent to which our full year 2020 operating and financial results, or that of future periods, will be adversely impacted by the ongoing COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted. We are unable to reasonably predict when, or to what extent, commodity prices and the overall markets and global economy will stabilize, and the pace of any subsequent recovery for the oil and gas industry. Further, to what extent these events do ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors that are not within our control and cannot be predicted, including the duration and extent of the pandemic and speculation as to future actions by Saudi Arabia, Russia and other foreign producers. We have taken steps and continue to work to address the evolving challenges and mitigate mounting repercussions from both the COVID-19 pandemic and the industry downturn on our operations, our financial condition and our people. We continue to plan

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for a prolonged downturn well into 2021, in spite of recent slight improvements in oil prices. However, given the tremendous volatility and turmoil, there is no certainty that the measures we take will ultimately be sufficient.

~~The COVID-19 Pandemic and Industry Downturn~~

In December 2019, a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, was reported to have surfaced in China. In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic. The COVID-19 pandemic has caused significant disruption globally since January 2020 and the U.S. economy continues to experience profound effects. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains and created significant volatility and disruption of the financial and commodity markets. The oil and gas industry has been severely impacted by the steep and prolonged deterioration in the price of oil caused by the significant decrease in demand because of the COVID-19 pandemic and corresponding preventative measures taken around the world to mitigate the spread of the virus, compounded by a supply surge from Saudi Arabia and Russia in the first half of 2020.

In March 2020, OPEC+ failed to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia aggressively increased oil production and exports. The convergence of these events - the unprecedented dual impact of a severe global oil demand decline related to the COVID-19 pandemic coupled with a substantial increase in supply - drove oil prices to historically low levels and created significant volatility, uncertainty, and turmoil in the oil and gas industry. As a result, the price of oil was extremely depressed and even reached historic lows during the second quarter 2020, with the price of Brent crude bottoming to just under $20 per Bbl in mid April 2020. These market conditions prompted producers all over the world to shut-in production and delay new oil and gas projects. OPEC+ eventually announced production cuts in April 2020, and then in June 2020 agreed to extend the cuts through the end of July 2020. In August these production cuts were eased slightly and the current output reduction levels are expected to remain through the end of 2020.

Additionally, the effects of demand destruction with a supply surge globally was amplified during the second quarter 2020 as available storage for crude oil and refined products became increasingly limited and there were concerns that available storage could become completely unavailable in 2020 and beyond, depending on the duration and severity of the ongoing pandemic. With the storage and transportation constraints further adding to the pressure on commodities prices, during the second quarter 2020 refiners started to curtail output and producers all over the world - including in the United States - started to shut-in production. Toward the end of the second quarter 2020, oil prices began to recover as the production cuts reduced the supply overhang and global demand began to increase gradually with containment of the COVID-19 outbreak in areas around the globe. The storage concerns were partially relieved as a result. However, this recovery appears fragile and has flattened, with oil price recovery stalling and oil demand remaining below pre-COVID-19 pandemic levels. Demand, and pricing, may again decline due to the ongoing COVID-19 pandemic, particularly if there is a resurgence of the outbreak as some are suggesting is possible, although the extent of the additional impact on our industry and our business cannot be reasonably predicted at this time.

As we focus on managing our business and operations in response to this health and economic crisis, the safety and well-being of our employees and the communities in which we operate has been, and is, our top priority. For the protection of our employees and to help contain the spread of COVID-19, we modified our business practices, including temporary closing of offices not required to maintain critical operations and instead allowing a large portion of our workforce to work from home, and we have implemented recommended practices with respect to social distancing, quarantines, travel bans and other restrictions. Although we managed the transition to remote work arrangements and subsequent office reopening without a loss in business continuity, we incurred additional costs and experienced some inefficiencies; importantly, none of which had an impact on our financial reporting systems, internal control over financial reporting or disclosure controls and procedures. We have not had layoffs or furloughs year-to-date, in part due to the “essential” nature of our business. As discussed above, the situation remains volatile and, if there is a resurgence of the COVID-19 outbreak in our areas of operation, we may be forced to again temporarily close our offices and transition to work from home; although we currently expect our operations would continue as normal and without significant additional impact due to the essential nature of our business. We remain

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committed to being a good corporate citizen by focusing on the well-being of our employees and communities, including maintaining our strong safety and environmental standards and investing in community impact initiatives.

As a result of the industry downturn, commodity price outlook, and increasing uncertainty, on April 1, 2020, we provided updated guidance for the 2020 fiscal year, reflecting a heightened focus on preserving cash and reducing costs, including through reducing planned 2020 capital expenditures and non-employee general and administrative expenses and improving operational efficiencies. We also temporarily suspended our quarterly cash dividend, starting with the second quarter of 2020, and year-to-date we have not repurchased any common stock under our authorized share repurchase program. We enhanced our hedge positions for 2020 and we still have essentially all of our expected oil production hedged in the remainder of 2020 at nearly $60 per barrel. We have hedged the substantial majority of our expected first half of 2021 oil production and have hedged just less than half of expected production for the second half of 2021. Additionally in October 2020, we hedged 12,500 MMBtu/d of our 2021 Rockies gas production at nearly $3.00 per MMBtu. Low oil and gas prices are expected to continue for some period as reflected by the current futures forward curves for Brent crude and Henry Hub gas, and we have secured these hedge positions to protect against the anticipated prolonged weakness in commodity prices. However, ongoing or worsening economic impacts to our industry could adversely impact our financial results through 2021 or beyond.

We experienced a decrease in production for the second and third quarters of 2020, largely due to natural declines as a result of temporarily discontinuing our drilling activity in April and engaging proactive maintenance and well management activities. We restarted our drilling activity in mid-October 2020, which we currently expect to continue through 2021 if our financial position and market conditions continue to support it. As a result, capital spending for the full year 2020 is now expected to be approximately $72 million, excluding capitalized overhead. During the second quarter of 2020, we obtained additional storage capacity to support our planned production for the remainder of the year and into 2021. As market conditions improved, we released a portion of the capacity. We currently believe our storage capacity will be sufficient to support our current planned production and we do not anticipate shutting in production in the near future unless economics dictate. However, the risk remains that storage for oil may be unavailable and our existing capacity may be insufficient to support planned production rates in the event of demand for our oil deteriorating again or a supply surge or both. If we are unable to obtain additional storage capacity if needed, we could be forced to shut-in some or all of our production or delay or temporarily discontinue our drilling plans. This could have a material, adverse effect on our financial condition, liquidity and results of operations. Whether and when we will have to reduce or shut-in production, and the extent and duration to which we may have to do so, cannot be reasonably predicted at this time. The significance of the impact of any production disruptions, including the extent of the adverse impact on our short- and long-term financial condition, liquidity and results of operations, will be dictated by the extent and duration of such disruption, which is unknowable and will, in turn, depend on how long storage remains filled and unavailable to us, which is also unknowable. For a discussion of certain potential risks, costs and other considerations related to shutting-in production, please see Part II, Item 1A. Risk Factors in this report - “The marketability of our production is dependent upon transportation and storage facilities and other facilities, most of which we do not control, and the availability of such transportation and storage capabilities, which have been severely limited by recent market conditions related to the COVID-19 pandemic and the current oversupply of oil and natural gas. If additional facilities do not become available, or, even if such facilities are available, but we are unable to access such facilities on commercially reasonable terms, our operations will likely be interrupted, our production could be curtailed, and our revenues reduced, among other consequences.”

~~Commodity Pricing and Differentials~~

Our revenue, costs, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production, as well as the prices we pay for our natural gas purchases, which are affected by a variety of factors, including those discussed in Part II, Item 1A. “Risk Factors” in this Quarterly Report, as well as in Part I, Item 1A. “Risk Factors” in our Annual Report. Average oil prices were higher for the three months ended September 30, 2020 compared to the three months ended June 30, 2020 but lower than the three months ended September 30, 2019. Brent crude oil contract prices ranged from $45.86 per Bbl to $39.61 per Bbl during the third quarter of 2020. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. During the second quarter of 2020, we experienced an adverse

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widening in the price differential between Brent and California crude due to the lack of local demand and storage capacity. This differential widening improved in the third quarter 2020 as the market storage concerns began to soften. As described above, if economic and health situations from the COVID-19 pandemic cause demand to worsen, and/or if OPEC+ producers take actions that again create a supply surge, and if necessary storage availability is not sufficient, oil prices may again go materially lower and Brent and/or California pricing could potentially even become negative as WTI oil prices did on April 20, 2020. In California, the price we pay for fuel gas purchases is generally based on the Kern, Delivered Index, which was as high as $12.69 per MMBtu and as low as $1.37 per MMBtu during the third quarter of 2020, while we paid an average of $2.84 per MMBtu in this period.

The following table presents the average Brent, WTI, Kern, Delivered, and Henry Hub prices for the three months ended September 30, 2020, June 30, 2020 and September 30, 2019 and for the nine months ended September 30, 2020 and September 30, 2019:

Three Months Ended Nine Months Ended
September 30, 2020 June 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019
Oil (Bbl) – Brent $ 43.34 $ 33.39 $ 62.03 $ 42.53 $ 64.75
Oil (Bbl) – WTI $ 40.87 $ 28.42 $ 56.33 $ 38.55 $ 57.03
Natural gas (MMBtu) – Kern, Delivered $ 2.84 $ 1.45 $ 2.50 $ 2.15 $ 3.19
Natural gas (MMBtu) – Henry Hub $ 2.00 $ 1.70 $ 2.38 $ 1.87 $ 2.62

As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 70% of the state’s demand from OPEC+ countries and other waterborne sources, primarily in the Middle East and South America. Without the higher costs and potential environmental impact associated with importing crude via rail or supertanker, we believe our in-state production and low-cost crude transportation options, coupled with Brent-influenced pricing, in appropriate oil price environments, should continue to allow us to realize positive cash margins in California over the cycle. However, California oil prices are determined ultimately by local supply and demand dynamic. Even as Brent pricing fell, and was weak, due to the effects of demand destruction with a supply surge globally, we also experienced a widening in the price differential between Brent and the California benchmark, caused primarily by the lack of local demand and storage capacity. We planned for significant deterioration of these differentials and refinery utilizations, and our plan for this expected worsening situation did not fully materialize, which enabled us to mitigate the impact. Although market conditions improved and the differential widening softened toward the end of the second quarter 2020, if California pricing weakens, our financial and operating results will be adversely affected. Currently we have storage capacity of 315,000 Bbls through June of 2021 to help mitigate these potential consequences.

Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products which are used as feedstock. In addition, infrastructure constraints magnify pricing volatility.

Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. We purchase substantially more natural gas for our California steamfloods and cogeneration facilities than we produce and sell in Utah and Colorado ("the Rockies"). Additionally, in recent history, the California gas markets have had higher gas prices than the Rockies and the rest of the United States. Consequently, higher gas prices have a negative impact on our operating results. However, we mitigate a portion of this exposure by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. We also strive to minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of such gas purchases. The negative impact of higher gas prices on our California operating expenses is partially offset by higher gas sales for the gas we produce in the Rockies.

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Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses, we also sell electricity produced by three of our cogeneration facilities under long-term contracts with terms ending in July 1, 2021 through December 1, 2026. The most significant input and cost of the cogeneration facilities is natural gas. We generally receive significantly more revenue from these cogeneration facilities in the summer months, June through September, due to negotiated capacity payments we receive.

~~EH&S and Regulatory Matters~~

Like other companies in the oil and gas industry, our operations are subject to complex and stringent federal, state, and local laws and regulations relating to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing, and sale of our products. Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and abandonment requirements for the oil and natural gas industry could have a significant impact on operations. Federal, state, and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

In California, the jurisdiction, duties and enforcement authority of various state agencies have significantly increased with respect to oil and natural gas activities in recent years, and these state agencies, as well as certain cities and counties, have significantly revised their regulations, regulatory interpretations and data collection and reporting requirements. For example:

•In April 2019 new idle well regulations went into effect, which include a comprehensive well testing regime to prevent leaks, a compliance schedule for testing or plugging and abandoning idle wells, the collection of data necessary to prioritize testing and sealing idle wells, requirements for a long-term idle well management plan, an engineering analysis for each well idled 15 years or longer, and requirements for active observation wells. In California, an idle well is one that has not been used for two years or more and has not yet been permanently sealed pursuant to regulations from California Geologic Energy Management Division ("CalGEM"), California's primary regulator of the oil and natural gas industry on private and state lands. We have submitted the required plans to meet our obligations.

•CalGEM’s predecessor also finalized new Underground Injection Control (“UIC”) regulations, effective April 2019, which affect two types of wells: (i) those that inject water or steam for enhanced oil recovery and (ii) those that return the briny groundwater that comes up from oil formations during production. These regulations include stronger testing requirements designed to identify potential leaks, increased data requirements to ensure proposed projects are fully evaluated, continuous well pressure monitoring, requirements to automatically cease injection when there is a risk to safety or the environment, and requirements to disclose chemical additives for injection wells close to water supply wells. Our California development and production activities are subject to these UIC regulations.

•Legislation passed in 2019 took effect January 1, 2020, including AB 1057, which requires state agencies to review emissions from idle and abandoned wells, and valuate plugging and abandonment and restoration costs and associated bonding requirements. This legislation also expanded CalGEM’s duties to include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs.

•Additionally, in November 2019, California's Department of Conservation issued a press release announcing three actions by CalGEM: (1) a moratorium on approval of new high–pressure cyclic steam wells pending a study of the practice to address surface expressions experienced by certain operators; (2) review and updating of regulations regarding public health and safety near oil and natural gas operations pursuant to additional duties assigned to CalGEM by the Legislature in 2019; and (3) a performance audit

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of CalGEM's permitting processes for well stimulation treatment (“WST”) permits and project approval letters (“PALs”) for underground injection by the California Department of Finance and an independent review and approval of the technical content of pending WST and PAL applications by Lawrence Livermore National Laboratory. In January 2020, CalGEM issued a formal notice to operators, including us, that they had issued restrictions imposing a moratorium to prohibit new underground oil-extraction wells from using high-pressure cyclic steaming process. Only our undeveloped thermal diatomite assets are currently impacted by the moratorium. Our 2020 results have not been, and are not expected to be, significantly impacted by the moratorium because our 2020 development and production plans did not require new high-pressure cyclic steam injection and the moratorium does not impact existing production or previously approved permits.

•On September 23, 2020, California’s Governor Gavin Newsom issued Executive Order N-79-20 related to vehicular transportation emissions and fossil fuel production in California. The order establishes a number of new policy goals for the State of California and directs the state legislature and agencies to develop policies or conduct rulemakings in furtherance of these goals. Specifically, the order addresses (1) working to end the issuance of new hydraulic fracturing permits by 2024, (2) development of a plan to transition upstream and downstream oil facilities by July 2021, (3) the need for strict enforcement of bonding requirements and other oil and gas regulations by CalGEM, and (4) development of new, draft public health and safety rules by December 31, 2020. The potential impact on Berry will depend on the nature of any final rules, regulations, policies, or legislation adopted by the state agencies or passed by the state legislature. As such, impacts to Berry cannot be predicted at this time.

•Legislation passed in 2020 will take effect January 1, 2021, although emergency measures take effect immediately upon signature by the Governor. Legislation signed into law in 2020 includes expanded oil spill penalties, new reporting requirements for excavations and subsurface installations, new protections for workers and disclosure requirements related to COVID-19.

Violations and liabilities with respect to any of the applicable laws and regulations, including those related to any environmental incident, could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, an inability to receive permits, operational interruptions or shutdowns and other liabilities. Additionally, the costs of remedying any environmental incident may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects. For additional information, please see Part I, Item 1 “Regulation of Health, Safety and Environmental Matters”, as well as Part I, Item 1.A. “Risk Factors” in our Annual Report.

~~For additional information, please see Part I, Item 1 “Regulation of Health, Safety and Environmental Matters”, as well as Part I, Item 1.A. “Risk Factors” in our Annual Report.~~

~~Seasonality~~

Seasonal weather conditions can impact our drilling and production activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations have been and in the future may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild-fires and rain.

How We Plan and Evaluate Operations

We use “Levered Free Cash Flow” in planning our capital allocation to sustain production levels and fund internal growth opportunities, as well as determine hedging needs. Levered Free Cash Flow is a non-GAAP financial measure that we define as Adjusted EBITDA less capital expenditures, interest expense, and dividends. Adjusted EBITDA is also a non-GAAP financial measure that is discussed and defined below.

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We use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA; (b) operating expenses; (c) environmental, health & safety (“EH&S”) results; (d) general and administrative expenses; and (e) production.

Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of our business. Adjusted EBITDA is a non-GAAP financial measure that we ~~defined~~define as earnings before interest expense; income taxes; depreciation, depletion, and amortization (“DD&A”); derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual ~~out-of-period~~ and infrequent ~~items, including restructuring costs and reorganization~~ items.

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Operating Expenses

Overall, operating expense is used by management as a measure of the efficiency with which operations are ~~performing.~~performed. We define operating expenses as lease operating expenses, electricity generation expenses, transportation expenses, and marketing expenses, offset by the third-party revenues generated by electricity, transportation and marketing activities, as well as the effect of derivative settlements (received or paid) for gas purchases. ~~Marketing revenues represent sales of natural gas purchased from and sold to third parties.~~ Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Taxes other than income taxes are excluded from operating expenses. Marketing revenues represent sales of natural gas purchased from and sold to third parties. The electricity, transportation and marketing activity related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the economics of development projects and the efficiency of our hydrocarbon recovery. Additionally, we strive to minimize the variability of our fuel gas costs for our steam operations with gas hedges.

Environmental, Health & Safety

Like other companies in the oil and gas industry, our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Current and future laws and regulations, as well as legislative and regulatory changes and other government activities, can materially impact our exploration, development, production and abandonment plans, including by restricting the production rate of oil, natural gas and NGLs below the rate that would otherwise be possible. Additionally, the regulatory burden on the industry increases the cost of doing business and consequently effects capital expenditures and earnings.

As part of our commitment to creating long-term stockholder value, we strive to conduct our operations in an ethical, safe and responsible manner, to protect the environment and to take care of our people and the communities in which we live and operate. We also seek proactive and transparent engagement with regulatory agencies, the communities in which we operate and our other stakeholders in order to realize the full potential of our resources in a timely fashion that safeguards people and the environment and complies with existing laws and regulations. We monitor our EH&S performance through various measures, ~~and incentivize~~holding our employees and contractors to ~~perform at~~ high ~~standards,~~standards. Meeting corporate EH&S metrics, including ~~through~~with respect to health and safety and spill prevention, is a part of our ~~annual~~ short-term incentive ~~program.~~program for all employees.

General and Administrative Expenses

We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities and ~~less than~~approximately 10% of such costs are capitalized, which is significantly less than industry norms. Such expenses are a key component of the appropriate level of support our corporate and professional team provides to the development of our assets and our day-to-day operations.

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Production

Oil and gas production is a key driver of our operating performance, an important factor to the success of our business, and used in forecasting future development economics. We measure and closely monitor production on a continuous basis, adjusting our property development efforts in accordance with the results. We track production by commodity type and compare it to prior periods and expected results.

Business Environment, Market Conditions and Outlook

Our operating and financial results, same as those of the oil and gas industry as a whole, are heavily influenced by commodity prices. Oil and gas prices and differentials have, and may continue to, fluctuate significantly as a result of numerous market-related variables, including global geopolitical and economic conditions. Our 2020 operating and financial results were adversely impacted by the deterioration and prolonged weakness in commodity prices that resulted from the COVID-19 pandemic as well as from certain actions by foreign oil and gas producers. Oil prices began to improve toward the end of 2020 and further strengthened in the first half of 2021.

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The extent to which our full year 2021 operating and financial results, or that of future periods, will be adversely impacted by the ongoing COVID-19 pandemic and the actions of foreign oil and gas producers will depend largely on future developments, which are highly uncertain and cannot be accurately predicted. Further, to what extent these events do ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors that are not within our control and cannot be predicted, including the duration and extent of the pandemic and speculation as to future actions by Saudi Arabia, Russia and other foreign producers. We have taken steps and continue to work to address the challenges and mitigate repercussions from both the COVID-19 pandemic and further industry downturns on our operations, our financial condition and our people.

The recovery in the oil and gas industry has improved with increasing oil prices as more states and countries re-open and national and global economies continue to recover. The demand for oil, while improving, could again decline if there is a widespread resurgence of the COVID-19 outbreak, although the extent of the additional impact on our industry and our business cannot be reasonably predicted at this time. In July 2021, OPEC+ reached an agreement to continue gradually increasing oil production through the end of 2022, as global demand grows.

As a result of the 2020 industry downturn, commodity price outlook, and increasing uncertainty, we heightened our focus on driving operational efficiencies and reducing costs. As a result of our ability to accomplish this goal we reinstated a quarterly dividend in the first quarter of 2021, which was increased for the third quarter of 2021.

Commodity Pricing and Differentials

Average oil prices were higher for the three months ended June 30, 2021 compared to the three months ended March 31, 2021 and June 30, 2020. Brent crude oil contract prices ranged between $62.15 per bbl and $76.18 per bbl during the second quarter of 2021. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. As described above, if reactions to the COVID-19 pandemic cause demand to worsen, and/or if OPEC+ producers take actions that again create a supply surge, and if necessary storage availability is not sufficient, oil prices may again go materially lower.

In California, the price we pay for fuel gas purchases is generally based on the Kern, Delivered Index, which was as high as $7.56 per mmbtu and as low as $2.37 per mmbtu during the second quarter of 2021, while we paid an average of $3.31 per mmbtu in this period.

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The following table presents the average Brent, WTI, Kern, Delivered, and Henry Hub prices for the three months ended June 30, 2021, March 31, 2021 and June 30, 2020 and for the six months ended June 30, 2021 and June 30, 2020:



	Three Months Ended						Six Months Ended
	June 30, 2021		March 31, 2021		June 30, 2020		June 30, 2021		June 30, 2020
Oil (bbl) – Brent	$	69.08	$	61.32	$	33.39	$	65.23	$	42.10
Oil (bbl) – WTI	$	66.03	$	57.82	$	28.42	$	61.95	$	37.38
Natural gas (mmbtu) – Kern, Delivered	$	3.23	$	7.99	$	1.45	$	5.60	$	1.73
Natural gas (mmbtu) – Henry Hub	$	2.95	$	3.50	$	1.70	$	3.22	$	1.80

As mentioned above, California oil prices are Brent-influenced as California refiners import approximately 65% to 70% of the state’s demand from OPEC+ countries and other waterborne sources. Without the higher costs and potential environmental impact associated with importing crude via rail or supertanker, we believe our in-state production and low-cost crude transportation options, coupled with Brent-influenced pricing, in appropriate oil price environments, should continue to allow us to realize positive cash margins in California over the cycle.

Utah oil prices have historically traded at a discount to WTI as the local refineries are designed for Utah's unique oil characteristics and the remoteness of the assets makes access to other markets logistically challenging. However, we have high operational control of our existing acreage, which provides significant upside for additional vertical and or horizontal development and recompletions.

Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. We purchase substantially more natural gas for our California steamfloods and cogeneration facilities than we produce and sell in the Rockies. Additionally, in recent history, the California gas markets have generally had higher gas prices than the Rockies and the rest of the United States. Consequently, higher gas prices have a negative impact on our operating results. However, we mitigate a portion of this exposure by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. We also strive to minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of such gas purchases. We recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that will reduce our exposure to fuel gas purchase price fluctuations. Additionally, the negative impact of higher gas prices on our California operating expenses is partially offset by higher gas sales for the gas we produce and sell in the Rockies.

Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses, we also sell electricity produced by three of our cogeneration facilities under short and long-term contracts with terms ending in September 2021 through December 2026. The contract ending in September 2021 represents less than 30% of our electricity sales in the six months ended June 30, 2021. The most significant input and cost of the cogeneration facilities is natural gas. We generally receive significantly more revenue from these cogeneration facilities in the summer months, most notably in June through September, due to negotiated capacity payments we receive.

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EH&S and Regulatory Matters

Like other companies in the oil and gas industry, our operations are subject to complex and stringent federal, state, and local laws and regulations relating to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water use, land use, managing greenhouse gases or other emissions, protection of health, safety and the environment, protection of air quality, and the transportation, marketing, and sale of our products. Congress and federal and state agencies frequently revise the safety and environmental laws and regulations applicable to our operations, and any changes that result in more stringent and costly requirements for the oil and natural gas industry, for example for waste handling, disposal, cleanup and abandonment, could have a significant impact on operating and financial results. In many of these areas, federal, state, and local agencies may assert overlapping authority and regulations. In addition, new laws and regulations could apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors have no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

As part of our commitment to creating long-term stockholder value, we strive to conduct our operations in an ethical, safe and responsible manner, to protect the environment and to take care of our people and the communities in which we live and operate. We also seek proactive and transparent engagement with regulatory agencies, the communities in which we operate, and our other stakeholders in order to help ensure that we can realize the full potential of our resources in a manner that safeguards people and the environment and complies with existing laws and regulations. We monitor our environmental, health and safety, or EH&S, performance through various measures, and we hold our employees and contractors to high standards. Meeting corporate EH&S metrics, including with respect to EH&S incidents and spill prevention, is a part of our short-term incentive program for all employees. In 2020, we achieved a Total Recordable Incident Rate, or TRIR, of 0.5, which we believe, based on available data, is a record company low and is below the United States average for all industries, which is a TRIR of 3.0 based on the most recently available data.

Certain actions of the new U.S. administration could negatively impact the oil and gas industry. Such actions may include, among other things, the increased regulation of greenhouse gas emissions associated with oil and gas operations, the imposition of a new carbon tax on greenhouse gas emissions and replacing tax incentives related to fossil fuel with incentives for clean energy production. Such outcomes could materially and adversely affect our business, results of operations and financial condition.

Additionally, in California, the jurisdiction, duties and enforcement authority of various state agencies have significantly increased with respect to oil and natural gas activities in recent years, and these state agencies, as well as certain cities and counties, have significantly revised their regulations, regulatory interpretations and data collection and reporting requirements. Certain state legislators have recently sought to introduce new legislation to restrict oil and gas activities in California, however, those efforts have not been successful to date. Additionally, California Governor Gavin Newsome has advocated for and directed actions, including through executive orders, to restrict the oil and gas operations and reduce both the supply and demand for oil and gas in the state. Most recently, for example:

•On April 23, 2021, Governor Newsom directed the California Geologic Energy Management Division (“CalGEM”) of the Department of Conservation, California's primary regulator of the oil and natural gas industry on private and state lands, to initiate rulemaking to halt the issuance of new permits for well stimulation treatments by 2024. It remains unclear whether or not CalGEM has existing statutory authority to take such action or whether additional enabling legislation from the California State Legislature is required. The directive also instructed the California Air Resources Board to evaluate regulatory pathways for phasing out oil extraction by 2045 under the state’s climate change scoping plan, which is the state’s comprehensive, programmatic plan to achieve the state’s required reductions in GHG emissions. We cannot predict the ultimate outcome of this evaluation, but authority for any rulemaking to broadly prohibit the extraction of oil would likely require the introduction of new legislation and be subject to significant opposition. As noted above, other proposals to prohibit or restrict certain oil extraction methods have previously been unsuccessful in the California State Legislature.

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•In response to Governor Newsom’s April 23 directive explained above, in May 2021, CalGEM published pre-rulemaking draft regulations prohibiting authorizations for well stimulation treatments after January 1, 2024. Well stimulation treatments covered by the draft rule include hydraulic fracturing, acid fracturing, acid-matrix stimulation, and other well-stimulation treatments that enhance oil and gas production by creating channels in rock formations for hydrocarbons to flow. Separately, in July 2021, CalGEM denied a set of permits for hydraulic fracturing requested by an operator, generally citing the protection of public health and safety and environmental quality. While the operator has indicated it will appeal this decision, we cannot predict the ultimate outcome of any such appeal, and CalGEM could issue similar permit denials in the future for other operators. Given the limited use of hydraulic fracturing in our operations in California currently, we do not expect to be materially impacted by a potential final rule from CalGEM. However, our current operations and future plans may be impacted by pending or threatened legislative, regulatory changes or other government activity impacting the timing of, and conditions imposed on, the required permits and approvals governing our activities.

For additional information, please see Part I, Item 1 “Regulation of Health, Safety and Environmental Matters”, as well as Part I, Item 1.A. “Risk Factors” in our Annual Report.

Seasonality

Seasonal weather conditions can impact our drilling and production activities. These seasonal conditions can occasionally pose challenges in our operations for meeting well-drilling and completion objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, our operations may have been and in the future may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires and rain.

Natural gas prices fluctuate based on seasonal and other market-related impacts. We purchase significantly more gas than we sell to generate steam and electricity in our cogeneration facilities for our producing activities. As a result, our key exposure to gas prices is in our costs. We mitigate a substantial portion of this exposure by selling excess electricity from our cogeneration operations to third parties. The pricing of these electricity sales is closely tied to the purchase price of natural gas. These sales are generally higher in the summer months as they include seasonal capacity amounts. We also hedge a significant portion of the gas we expect to consume and we recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our operations in California.

Capital Expenditures

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, our capital expenditures were approximately $4$43 million and ~~$57~~$67 million, respectively, on an accrual basis ~~excluding~~including capitalized overhead ~~of approximately $1.5 million~~ and ~~$4.5 million, respectively. These amounts also excluded capitalized~~ interest and excluding acquisitions and asset retirement spending. Approximately ~~90%~~78% and 14% of total capital for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 was directed to California oil ~~operations.~~and Utah operations, respectively .

~~Toward~~Our planned 2021 capital expenditure budget is approximately $120 to $130 million. We plan to spend the ~~end~~majority of this amount during the ~~first quarter we reduced~~second and third quarters of 2021. We expect our ~~planned 2020~~ capital expenditures ~~by approximately 50% from our original 2020 guidance~~will result in ~~response to the sudden~~essentially flat year-over year production and significant oil and gas price deterioration caused by the COVID-19 pandemic, coupled with OPEC+ actions, which created significant volatility, uncertainty, and turmoil in the oil and gas industry. Since that time, the 2020 capital expenditures have been focused on continuing our permitting and proactive maintenance activities to support ongoing activity and safe operations.a higher exit rate for 2021 than 2020. We proactively initiated an intense permitting program during the first quarter 2020 to ensure adequate inventory once we restarted our drilling program. With the slight strengthening of oil prices in the third quarter 2020, capital spending for the full year is now expected to be approximately $72 million, which excludes approximately $7 million of capitalized overhead. This includes restarting our drilling program in mid-October 2020, as well as increasing workover and recompletion opportunities during the fourth quarter 2020. The 2020 capital expenditures also includes approximately $25 million for facilities and cogen projects, including long-term maintenance, as well as approximately $4 million for drilling delineation wells which added value by increasing our reserves and drilling inventory for these projects.

We currently ~~expect 2020 production to be flat with the prior year. We also~~ anticipate oil production will be approximately ~~88%~~89% of total production in ~~2020,~~2021, compared to ~~87%~~88% in ~~2019.~~2020. Based on current

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commodity prices and our ~~current capital plan~~drilling success rate to date, we expect to be able to fund our ~~remaining 2020~~2021 capital development programs with cash flow from ~~operations. Even in this low price environment we~~operations and, if necessary, current cash on hand, which was generated during 2020 and anticipated for use to supplement our 2021 capital program. We plan to live within Levered Free Cash Flow ~~over 2020 and~~in 2021 ~~in the aggregate,~~ and beyond.

The amount and timing of capital expenditures are within our control and subject to our ~~management’s~~ discretion, and due to the speed with which we are able to drill and complete our wells in California, capital may be adjusted quickly during the year depending on numerous factors, including commodity prices, storage constraints, supply/demand considerations and ~~other factors.~~attractive rates of return. We believe it is important to retain the flexibility to defer planned capital expenditures ~~depending~~and may do so based on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the receipt and timing of required regulatory permits and approvals, the availability of necessary equipment, infrastructure and capital, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners, as well as general market conditions. Any postponement or elimination of our development drilling program could result in a reduction of proved reserves volumes and materially affect our business, financial condition and results of operations. Additionally and not included in the capital expenditures noted above, for the full year ~~2020,~~2021, we plan to spend approximately ~~$16-$20~~$19 million to $23 million on plugging and abandonment activities, including satisfying our annual obligations under the California Idle Well Management Program. ~~This includes the $14 million spent in the first three quarters of 2020.~~

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~~Acquisition~~

In May 2020, we acquired approximately 740 net acres in the North Midway Sunset Field for approximately $5 million. We paid $2 million at closing and the remaining $3 million was paid following our first production from this property, in the fourth quarter 2020. This property is adjacent to, and extends, our existing producing area and we have identified numerous future drilling locations. We believe additional opportunities exist in other productive reservoirs of this property. We also acquired all existing idle wells on this property, some of which we plan to return to production in the near future as price and strategy dictate. We will plug and abandon the remaining idle wells pursuant to the California Idle Well Management Program. We recorded a $6 million liability for asset retirement obligations of the existing wells on this property.

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Summary Byby Area

The following table shows a summary by area of our selected historical financial information and operating data for the periods indicated.


		California (San Joaquin and Ventura basins)									California (San Joaquin and Ventura basins)
		Three Months Ended									Three Months Ended
		September 30, 2020			June 30, 2020			September 30, 2019					June 30, 2021			March 31, 2021			June 30, 2020
($ in thousands, except prices)	($ in thousands, except prices)											($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales	Oil, natural gas and natural gas liquids sales	$	81,592		$	62,943		$	124,540			Oil, natural gas and natural gas liquids sales	$	129,128		$	113,177		$	62,943
Operating income (1)	Operating income (1)	$	36,296		$	32,469		$	66,449			Operating income(1)	$	11,413		$	18,965		$	32,469
Depreciation, depletion, and amortization (DD&A)	Depreciation, depletion, and amortization (DD&A)	$	34,779		$	36,518		$	24,360			Depreciation, depletion, and amortization (DD&A)	$	35,174		$	32,896		$	36,518

Average daily production (MBoe/d)		22.2			23.4			23.0
Average daily production (mboe/d)												Average daily production (mboe/d)	21.7			21.9			23.4
Production (oil % of total)	Production (oil % of total)	100		%	100		%	100		%		Production (oil % of total)	100		%	100		%	100		%
Realized sales prices:	Realized sales prices:											Realized sales prices:
Oil (per Bbl)		$	40.02		$	29.53		$	59.00
NGLs (per Bbl)		$	—		$	—		$	—
Gas (per Mcf)		$	—		$	—		$	—
Oil (per bbl)												Oil (per bbl)	$	65.37		$	57.34		$	29.53
NGLs (per bbl)												NGLs (per bbl)	$	—		$	—		$	—
Gas (per mcf)												Gas (per mcf)	$	—		$	—		$	—
Capital expenditures(2)	Capital expenditures(2)	$	4,467		$	15,916		$	59,076			Capital expenditures(2)	$	31,303		$	22,760		$	16,446


		Utah (Uinta basin)									Colorado (Piceance basin)										Utah (Uinta basin)									Colorado (Piceance basin)
		Three Months Ended									Three Months Ended										Three Months Ended									Three Months Ended
		September 30, 2020			June 30, 2020			September 30, 2019			September 30, 2020			June 30, 2020			September 30, 2019				June 30, 2021			March 31, 2021			June 30, 2020			June 30, 2021			March 31, 2021			June 30, 2020
($ in thousands, except prices)	($ in thousands, except prices)																			($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales	Oil, natural gas and natural gas liquids sales	$	9,311		$	6,439		$	14,946		$	1,336		$	1,132		$	1,758		Oil, natural gas and natural gas liquids sales	$	16,199		$	15,889		$	6,439		$	2,438		$	6,194		$	1,132
Operating income (loss)(1)	Operating income (loss)(1)	$	1,093		$	(584)		$	1,376		$	(235)		$	6		$	(123)		Operating income (loss)(1)	$	6,736		$	7,433		$	(584)		$	1,121		$	5,039		$	6
Depreciation, depletion, and amortization (DD&A)	Depreciation, depletion, and amortization (DD&A)	$	915		$	905		$	3,039		$	165		$	43		$	264		Depreciation, depletion, and amortization (DD&A)	$	630		$	554		$	905		$	38		$	38		$	43

Average daily production (MBoe/d)		4.1			4.4			5.1			1.3			1.3			1.5
Average daily production (mboe/d)																				Average daily production (mboe/d)	4.4			4.0			4.4			1.2			1.2			1.3
Production (oil % of total)	Production (oil % of total)	47		%	49		%	52		%	2		%	2		%	2		%	Production (oil % of total)	52		%	49		%	49		%	2		%	2		%	2		%
Realized sales prices:	Realized sales prices:																			Realized sales prices:
Oil (per Bbl)		$	38.40		$	23.11		$	48.74		$	33.60		$	20.67		$	56.18
NGLs (per Bbl)		$	13.25		$	5.82		$	12.10		$	—		$	—		$	—
Gas (per Mcf)		$	2.05		$	1.68		$	2.21		$	1.80		$	1.53		$	1.99
Oil (per bbl)																				Oil (per bbl)	$	58.55		$	52.08		$	23.11		$	56.05		$	25.80		$	20.67
NGLs (per bbl)																				NGLs (per bbl)	$	29.61		$	26.81		$	5.82		$	—		$	—		$	—
Gas (per mcf)																				Gas (per mcf)	$	3.30		$	6.65		$	1.68		$	3.53		$	9.83		$	1.53
Capital expenditures(2)	Capital expenditures(2)	$	103		$	82		$	1,851		$	46		$	145		$	213		Capital expenditures(2)	$	9,162		$	392		$	81		$	—		$	1		$	145

__________

(1) Operating income (loss) includes oil, natural gas and NGL sales, and scheduled oil derivative settlements, offset by operating expenses (as defined elsewhere), general and administrative expenses, DD&A, impairment of oil and gas properties, and taxes, other than income taxes.

(2) Excludes corporate capital expenditures.

2722

Table of Contents

Production and Prices

The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.

Three Months Ended
September 30, 2020 June 30, 2020 September 30, 2019
Average daily production:(1)
Oil (MBbl/d) 24.1 25.6 25.7
Natural Gas (MMcf/d) 18.7 19.2 20.9
NGL (MBbl/d) 0.4 0.3 0.4
Total (MBoe/d)(2)
27.6 29.1 29.6
Total Production:
Oil (MBbl) 2,218 2,330 2,360
Natural gas (MMcf) 1,719 1,746 1,920
NGLs (MBbl) 33 29 39
Total (MBoe)(2)
2,537 2,650 2,719
Weighted-average realized sales prices:
Oil without hedges ($/Bbl) $ 39.88 $ 28.98 $ 57.92
Effects of scheduled derivative settlements ($/Bbl) $ 16.28 $ 25.42 $ 7.31
Oil with hedges ($/Bbl) $ 56.16 $ 54.40 $ 65.23
Natural gas ($/Mcf) $ 1.95 $ 1.62 $ 2.12
NGL ($/Bbl) $ 13.25 $ 5.82 $ 12.10
Average Benchmark prices:
Oil (Bbl) – Brent $ 43.34 $ 33.39 $ 62.03
Oil (Bbl) – WTI $ 40.87 $ 28.42 $ 56.33
Natural gas (MMBtu) – Kern, Delivered(3)
$ 2.84 $ 1.45 $ 2.50
Natural gas (MMBtu) – Henry Hub(4)
$ 2.00 $ 1.70 $ 2.38



	Three Months Ended
	June 30, 2021		March 31, 2021		June 30, 2020
Average daily production:(1)
Oil (mbbl/d)	24.0		23.9		25.6
Natural Gas (mmcf/d)	17.5		16.9		19.2
NGL (mbbl/d)	0.4		0.3		0.3
Total (mboe/d)(2)	27.3		27.1		29.1
Total Production:
Oil (mbbl)	2,183		2,151		2,330
Natural gas (mmcf)	1,595		1,517		1,746
NGLs (mbbl)	36		31		29
Total (mboe)(2)	2,485		2,435		2,650
Weighted-average realized sales prices:
Oil without hedges ($/bbl)	$	64.72	$	56.89	$	28.98
Effects of scheduled derivative settlements ($/bbl)	$	(18.33)	$	(12.08)	$	25.42
Oil with hedges ($/bbl)	$	46.39	$	44.81	$	54.40
Natural gas ($/mcf)	$	3.39	$	7.96	$	1.62
NGL ($/bbl)	$	29.61	$	26.81	$	5.82
Average Benchmark prices:
Oil (bbl) – Brent	$	69.08	$	61.32	$	33.39
Oil (bbl) – WTI	$	66.03	$	57.82	$	28.42
Natural gas (mmbtu) – Kern, Delivered(3)	$	3.23	$	7.99	$	1.45
Natural gas (mmbtu) – Henry Hub(4)	$	2.95	$	3.50	$	1.70

__________

(1) Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.

(2) Natural gas volumes have been converted to ~~Boe~~boe based on energy content of six ~~Mcf~~mcf of gas to one ~~Bbl~~bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the three months ended ~~September~~June 30, ~~2020,~~2021, the average prices of Brent oil and Henry Hub natural gas were ~~$43.34~~$69.08 per ~~Bbl~~bbl and ~~$2.00~~$2.95 per ~~MMBtu respectively, resulting in an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent basis.~~mmbtu.

(3) Kern, Delivered Index is the relevant index used for gas purchases in California.

(4) Henry Hub is the relevant index used for gas sales in the Rockies.

2823

Table of Contents

The following table sets forth average daily production by operating area for the periods indicated:


		Three Months Ended				Three Months Ended
		September 30, 2020	June 30, 2020	September 30, 2019		June 30, 2021	March 31, 2021	June 30, 2020
Average daily production (MBoe/d):(1)
Average daily production (mboe/d):(1)					Average daily production (mboe/d):(1)
California	California	22.2	23.4	23.0	California	21.7	21.9	23.4
Utah	Utah	4.1	4.4	5.1	Utah	4.4	4.0	4.4
Colorado	Colorado	1.3	1.3	1.5	Colorado	1.2	1.2	1.3

Total average daily production	Total average daily production	27.6	29.1	29.6	Total average daily production	27.3	27.1	29.1

__________

(1) Production represents volumes sold during the period.

Average daily production ~~decreased 1.5 MBoe/~~increased 0.2 mboe/d, or 5%1%, and Company wide oil production increased 0.1 mboe/d, for the three months ended ~~September~~June 30, ~~2020,~~2021, compared to the three months ended March 31, 2021, largely due to increased development capital in Utah, where we generated a 10% increase in production. Of the 58 wells drilled in the second quarter of 2021, 44 were production wells, eight were injector wells and six were delineation, a slight increase compared to the well count of 50 in the first quarter of 2021. However, 21 of the 58 wells drilled will not come on production until the third quarter of 2021. Development drilling in the second quarter 2021 included eight wells drilled in Utah, which require more capital than our typical California wells, as well as increased California workover, equipping and facilities work.

Our California production of 21.7 mboe/d for the second quarter 2021 decreased 1% from the first quarter 2021. California production has been negatively impacted by a loss of our production from one of Berry's locations where lower water withdrawals by an offset operator along with a reduction in our steam injection volumes triggered a drop in production. The issue has reduced production by approximately 600 bbl/d and this will impact all of 2021. However, the steam is expected to recharge and be back to historical production levels by early next year.

Average daily production decreased 6% for the three months ended June 30, 2021 as compared to the three months ended June 30, 2020 largely due to natural declines as a result of temporarily discontinuing our drilling activity in April 2020. Further, we experienced seasonal disruptions and undertook certain operational improvements that caused temporary reductions in our production. Notably, we performed some plugging and abandonment activity that resulted in temporary shut-in of nearby wells. Additionally, we improved steam management which reduced overall costs but temporarily increased water disposal and well maintenance needs, resulting in a slight decrease in production. Our California production of 22.2 MBoe/d for the third quarter 2020 decreased 5% from the second quarter 2020.

~~Average daily production volumes decreased 7% for the three months ended September 30, 2020 as compared to the three months ended September 30, 2019~~ due to significantly ~~reduced~~lower development capital spending in the ~~second and third~~first quarter of 2021 compared to the first quarter of 2020, as well as lower spending in the full year 2020 compared to the ~~same quarters in~~full year 2019. ~~This year-over-year decrease was also impacted by the same reasons noted above.~~

Table of Contents

The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.

~~Table of Contents~~

Nine Months Ended
September 30, 2020 September 30, 2019
Average daily production:(1)
Oil (MBbl/d) 25.7 24.5
Natural Gas (MMcf/d) 18.8 20.4
NGL (MBbl/d) 0.3 0.4
Total (MBoe/d)(2)
29.1 28.3
Total Production:
Oil (MBbl) 7,033 6,673
Natural gas (MMcf) 5,148 5,565
NGLs (MBbl) 94 116
Total (MBoe)(2)
7,985 7,717
Weighted-average realized sales prices:
Oil without hedges ($/Bbl) $ 39.00 $ 58.79
Effects of scheduled derivative settlements ($/Bbl) $ 16.97 $ 4.30
Oil with hedges ($/Bbl) $ 55.97 $ 63.09
Natural gas ($/Mcf) $ 1.85 $ 2.67
NGL ($/Bbl) $ 10.92 $ 17.74
Average Benchmark prices:
Oil (Bbl) – Brent $ 42.53 $ 64.75
Oil (Bbl) – WTI $ 38.55 $ 57.03
Gas (MMBtu) – Kern, Delivered(3)
$ 2.15 $ 3.19
Natural gas (MMBtu) – Henry Hub(4)
$ 1.87 $ 2.62



	Six Months Ended
	June 30, 2021		June 30, 2020
Average daily production:(1)
Oil (mbbl/d)	23.9		26.5
Natural Gas (mmcf/d)	17.2		18.8
NGL (mbbl/d)	0.4		0.3
Total (mboe/d)(2)	27.2		29.9
Total Production:
Oil (mbbl)	4,334		4,815
Natural gas (mmcf)	3,113		3,430
NGLs (mbbl)	66		61
Total (mboe)(2)	4,919		5,448
Weighted-average realized sales prices:
Oil without hedges ($/bbl)	$	60.83	$	38.59
Effects of scheduled derivative settlements ($/bbl)	$	(15.22)	$	17.30
Oil with hedges ($/bbl)	$	45.61	$	55.89
Natural gas ($/mcf)	$	5.62	$	1.81
NGL ($/bbl)	$	28.30	$	9.66
Average Benchmark prices:
Oil (bbl) – Brent	$	65.23	$	42.10
Oil (bbl) – WTI	$	61.95	$	37.38
Gas (mmbtu) – Kern, Delivered(3)	$	5.60	$	1.73
Natural gas (mmbtu) – Henry Hub(4)	$	3.22	$	1.80

__________

(1) Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.

(2) Natural gas volumes have been converted to ~~Boe~~boe based on energy content of six ~~Mcf~~mcf of gas to one ~~Bbl~~bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, during the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, the average prices of Brent oil and Henry Hub natural gas were ~~$42.53~~$65.23 per ~~Bbl~~bbl and ~~$1.87~~$3.22 per ~~MMBtu respectively, resulting in an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent basis.~~mmbtu respectively.

(3) Kern, Delivered Index is the relevant index used for gas purchases in California.

(4) Henry Hub is the relevant index used for gas sales in the Rockies.

Table of Contents

The following table sets forth average daily production by operating area for the periods indicated:


		Nine Months Ended			Six Months Ended
		September 30, 2020	September 30, 2019		June 30, 2021	June 30, 2020
Average daily production (MBoe/d):(1)
Average daily production (mboe/d):(1)				Average daily production (mboe/d):(1)
California	California	23.5	21.6	California	21.8	24.1
Utah	Utah	4.3	5.2	Utah	4.2	4.5
Colorado	Colorado	1.3	1.5	Colorado	1.2	1.3

Total average daily production	Total average daily production	29.1	28.3	Total average daily production	27.2	29.9

__________

(1) Production represents volumes sold during the period.

~~Table of Contents~~

Average daily production ~~increased 3%~~decreased 9% for the ~~nine~~six months ended ~~September~~June 30, 2021, compared to the six months ended June 30, 2020, largely due to a lack of development in 2020, compared to ~~the nine months ended September 30, 2019, largely due to the impact of our development program in late~~ 2019, and ~~into the first quarter of this year.~~natural decline. Our California production of ~~23.5 MBoe/~~21.8 mboe/d for the ~~nine~~six months ~~September~~ended June 30, ~~2020 increased 9%~~2021 decreased 10% compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019 where the majority of our capital in 2019 and 2020 was spent.~~2020. Of the 23100 California wells drilled in the first half of ~~2020, twelve~~2021, 81 were producing wells, ~~nine~~11 were delineation wells and ~~two~~8 were injector wells. This overall increase was also impacted by the same issues identified above in the third quarter to second quarter 2020 section. The production in Utah and Colorado decreased 16% for the nine months ended September 30, 2020 compared to the same period in 2019, primarily due to a lack of capital expenditures and natural decline.

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Results of Operations

Three Months Ended ~~September~~June 30, ~~2020~~2021 compared to Three Months Ended ~~June 30, 2020.~~March 31, 2021.


		Three Months Ended										Three Months Ended
		September 30, 2020		June 30, 2020		$ Change		% Change		June 30, 2021				March 31, 2021			$ Change			% Change
		(in thousands)										(in thousands)
Revenues and other:	Revenues and other:										Revenues and other:
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	92,239	$	70,515	$	21,724	31	%		Oil, natural gas and NGL sales	$	147,775		$	135,265		$	12,510		9	%
Electricity sales	Electricity sales	8,744		4,884		3,860		79	%		Electricity sales	6,888			10,069			(3,181)			(32)	%
(Losses) gains on oil derivatives		(11,564)		(42,267)		30,703		(73)	%
Losses on oil and gas sales derivatives											Losses on oil and gas sales derivatives	(55,653)			(53,504)			(2,149)			4	%
Marketing and other revenues	Marketing and other revenues	330		321		9		3	%		Marketing and other revenues	239			2,371			(2,132)			(90)	%

Total revenues and other	Total revenues and other	$	89,749	$	33,453	$	56,296	168	%		Total revenues and other	$	99,249		$	94,201		$	5,048		5	%

Revenues and Other

Oil, natural gas and NGL sales increased by ~~$22~~$13 million, or ~~31%~~9%, to approximately ~~$92~~$148 million for the three months ended ~~September~~June 30, ~~2020,~~2021, compared to the three months ended ~~June 30, 2020.~~March 31, 2021. The increase was driven by ~~$24~~$17 million ofand $2 million higher unhedged oil prices and oil sales volumes, respectively, partially offset by $7 million of lower ~~oil volumes.~~unhedged natural gas prices.

In the first quarter of 2021, the United States experienced a sharp, and unusually large increase in natural gas prices caused by an unprecedented February demand spike from Winter Storm Uri that impacted much of the nation. This had a dramatic impact on both our natural gas and electricity sales, driving significant revenue increases in the first quarter. The impact on our fuel gas cost in California was not nearly as pronounced due to our effective hedging program and our proactive reduction in fuel usage during the highly volatile period in February.

Electricity sales represent sales to utilities, and ~~increased $4~~decreased $3 million, or ~~79%~~32%, to approximately $9$7 million for the three months ended ~~September~~June 30, ~~2020~~2021 compared to the three months ended ~~June 30, 2020. The increase primarily reflected higher~~March 31, 2021. Revenue declined from the first quarter when gas prices, which typically drive revenue, were unusually high due to the increased demand from Winter Storm Uri. Gas prices and electricity unit sales ~~prices that resulted from a~~returned to their typical seasonal ~~increase~~levels in ~~capacity payments and higher natural gas prices during the third quarter 2020 compared to~~ the second quarter ~~2020.~~2021.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement ~~gains~~loss for the three months ended ~~September 30, 2020 and~~ June 30, ~~2020 were $36~~2021 was $40 million and ~~$59 million, respectively.~~the loss for the three months ended March 31, 2021 was $26 million. The quarter-over-quarter ~~decrease~~increase in settlement ~~gains~~losses was driven by higher oil prices relative to the derivative fixed ~~contract~~ prices in the ~~third~~second quarter compared to those of the ~~second~~first quarter of ~~2020. Each of these quarters had the same~~2021. The average derivative fixed ~~prices~~price of $45.82 and ~~daily~~ notional ~~volumes. The~~volumes of 19 mbbl/d were unchanged when compared to the first quarter 2021.The mark-to-market non-cash loss of ~~$48~~$16 million for the three months ended ~~September~~June 30, ~~2020~~2021 was due to higher futures prices relative to the derivative fixed prices at ~~September~~June 30, ~~2020~~2021 compared to the non-cash loss of ~~$101~~$28 million for the three months ended March 31, 2021. In the second half of 2021 our daily oil hedged volumes will decrease approximately 25%, and have slightly higher fixed prices than in the first half of 2021.

Marketing and other revenues decreased by $2 million for the three months ended June 30, ~~2020.~~

~~Marketing and other revenues were comparable for~~2021 when compared to the ~~periods presented.~~three months ended March 31, 2021 due to the unusually high unit prices caused by the demand spike from Winter Storm Uri in the first quarter of 2021.

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		Three Months Ended				$ Change		% Change			Three Months Ended				$ Change		% Change
		September 30, 2020		June 30, 2020							June 30, 2021		March 31, 2021
		(in thousands, except expenses per Boe)									(in thousands, except expenses per boe)
Expenses and other:	Expenses and other:									Expenses and other:
Lease operating expenses	Lease operating expenses	$	45,243	$	40,733	$	4,510	11	%	Lease operating expenses	$	45,543	$	62,284	$	(16,741)	(27)	%
Electricity generation expenses	Electricity generation expenses	4,217		3,022		1,195		40	%	Electricity generation expenses	4,712		7,648		(2,936)		(38)	%
Transportation expenses	Transportation expenses	1,768		1,789		(21)		(1)	%	Transportation expenses	1,757		1,576		181		11	%
Marketing expenses	Marketing expenses	326		280		46		16	%	Marketing expenses	44		2,227		(2,183)		(98)	%
General and administrative expenses	General and administrative expenses	19,173		18,777		396		2	%	General and administrative expenses	16,065		17,070		(1,005)		(6)	%
Depreciation, depletion and amortization	Depreciation, depletion and amortization	35,905		37,512		(1,607)		(4)	%	Depreciation, depletion and amortization	35,850		33,840		2,010		6	%

Taxes, other than income taxes	Taxes, other than income taxes	9,913		10,449		(536)		(5)	%	Taxes, other than income taxes	11,603		9,557		2,046		21	%

(Gain) losses on natural gas derivatives		(15,784)		925		(16,709)		n/a
Other operating expenses (income)		1,648		(1,192)		2,840		n/a
Gains on natural gas purchase derivatives										Gains on natural gas purchase derivatives	(11,639)		(27,730)		16,091		(58)	%
Other operating expenses										Other operating expenses	42		799		(757)		(95)	%
Total expenses and other	Total expenses and other	102,409		112,295		(9,886)		(9)	%	Total expenses and other	103,977		107,271		(3,294)		(3)	%
Other (expenses) income:	Other (expenses) income:									Other (expenses) income:
Interest expense	Interest expense	(8,391)		(8,676)		285		(3)	%	Interest expense	(8,217)		(8,485)		268		(3)	%
Other, net	Other, net	(3)		(6)		3		(50)	%	Other, net	(8)		(143)		135		(94)	%

Loss before income taxes	Loss before income taxes	(21,054)		(87,524)		66,470		(76)	%	Loss before income taxes	(12,953)		(21,698)		8,745		(40)	%
Income tax (benefit) expense		(2,190)		(22,623)		20,433		(90)	%
Income tax benefit										Income tax benefit	(72)		(376)		304		(81)	%
Net loss	Net loss	$	(18,864)	$	(64,901)	$	46,037	(71)	%	Net loss	$	(12,881)	$	(21,322)	$	8,441	(40)	%

Expenses per Boe:(1)
Expenses per boe:(1)										Expenses per boe:(1)
Lease operating expenses	Lease operating expenses	$	17.83	$	15.37	$	2.46	16	%	Lease operating expenses	$	18.33	$	25.58	$	(7.25)	(28)	%
Electricity generation expenses	Electricity generation expenses	1.66		1.14		0.52		46	%	Electricity generation expenses	1.90		3.14		(1.24)		(39)	%
Electricity sales(1)	Electricity sales(1)	(3.45)		(1.84)		(1.61)		88	%	Electricity sales(1)	(2.77)		(4.13)		1.36		(33)	%
Transportation expenses	Transportation expenses	0.69		0.67		0.02		3	%	Transportation expenses	0.70		0.65		0.05		8	%
Transportation sales(1)	Transportation sales(1)	—		(0.01)		0.01		(100)	%	Transportation sales(1)	(0.05)		(0.06)		0.01		(17)	%
Marketing expenses	Marketing expenses	0.13		0.11		0.02		18	%	Marketing expenses	0.02		0.92		(0.90)		(98)	%
Marketing revenues(1)	Marketing revenues(1)	(0.13)		(0.11)		(0.02)		18	%	Marketing revenues(1)	(0.05)		(0.92)		0.87		(95)	%
Derivatives settlements paid for gas purchases(1)		0.24		2.78		(2.54)		(91)	%
Derivatives settlements received for gas purchases(1)										Derivatives settlements received for gas purchases(1)	(0.77)		(10.78)		10.01		(93)	%
Total operating expenses	Total operating expenses	$	16.97	$	18.11	$	(1.14)	(6)	%	Total operating expenses	$	17.31	$	14.40	$	2.91	20	%
Total unhedged operating expenses(2)	Total unhedged operating expenses(2)	$	16.73	$	15.33	$	1.40	9	%	Total unhedged operating expenses(2)	$	18.08	$	25.18	$	(7.10)	(28)	%

Total non-energy operating expenses~~(4)~~(3)	Total non-energy operating expenses~~(4)~~(3)	$	13.34	$	12.81	$	0.53	4	%	Total non-energy operating expenses~~(4)~~(3)	$	12.71	$	12.74	$	(0.03)	—	%
Total energy operating expenses~~(5)~~(4)	Total energy operating expenses~~(5)~~(4)	$	3.65	$	5.30	$	(1.65)	(31)	%	Total energy operating expenses~~(5)~~(4)	$	4.60	$	1.66	$	2.94	177	%

General and administrative expenses~~(3)~~(5)	General and administrative expenses~~(3)~~(5)	$	7.56	$	7.09	$	0.47	7	%	General and administrative expenses~~(3)~~(5)	$	6.46	$	7.01	$	(0.55)	(8)	%
Depreciation, depletion and amortization	Depreciation, depletion and amortization	$	14.15	$	14.16	$	(0.01)	—	%	Depreciation, depletion and amortization	$	14.43	$	13.90	$	0.53	4	%
Taxes, other than income taxes	Taxes, other than income taxes	$	3.91	$	3.94	$	(0.03)	(1)	%	Taxes, other than income taxes	$	4.67	$	3.93	$	0.74	19	%

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(1) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses also include the effect of derivative settlements (received or paid) for gas purchases.

(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.

(3) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $2.08 per Boe and $1.77 per Boe for the three months ended September 30, 2020 and June 30, 2020, respectively.

~~(4)~~ Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.

~~(5)~~(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.

(5) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.11 per boe and $1.51 per boe for the three months ended June 30, 2021 and March 31, 2021, respectively.

Expenses and Other

In accordance with GAAP, we report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues. However, these revenues are viewed and used internally in calculating operating expenses, which are used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.

Operating expenses are defined above in “How We Plan and Evaluate Operations”~~. On~~, which include electricity revenues. In the first quarter of 2021 we experienced a ~~hedged basis, operating expenses, decreased 6% or $1.14~~sharp, and unprecedented increase in natural gas prices caused by a demand spike from Winter Storm Uri that impacted much of the nation in February. For about one week in mid-February, daily gas prices exceeded $100 per ~~Boe~~mmbtu and during this time we temporarily modified our operations to ~~$16.97 in~~reduce the ~~third~~amount of fuel gas required to be purchased, thereby avoiding approximately $7 million of additional costs. Compared to the first quarter ~~2020 from $18.11~~2021, our hedges on fuel gas purchases had a smaller effect in the second quarter, ~~2020. The decrease was largely due to~~resulting in higher fuel gas costs, hedged, by $4 million. Combined with the $3 million lower electricity sales, ~~resulting from~~operating expenses were higher ~~seasonal capacity payments. During~~by 20%, or $2.91 per boe and $8 million on an absolute dollar basis in the ~~third~~second quarter ~~2020, we sustained~~2021 compared to the ~~cost savings achieved~~first quarter 2021. Fuel purchases were hedged 85% and 79% in the first ~~half of 2020, as hedged fuel~~quarter and ~~non-fuel costs were essentially flat to the~~ second quarter, 2020. On an unhedged basis, operating expenses increased by 9% or $1.40 per Boe to $16.73 for the third quarter 2020, compared to $15.33 for the second quarter 2020. This increase was driven by higher unhedged fuel costsrespectively. We were, and remain during 2021, largely hedged on our natural gas purchases against increases in ~~comparison to the second quarter 2020.~~purchase prices.

~~Lease~~Unhedged lease operating expenses per ~~Boe increased~~boe decreased to ~~$17.83, for the three months ended September 30, 2020, a 16% or $2.46 per Boe increase compared to $15.37 per Boe~~$18.33, for the three months ended June 30, ~~2020~~2021, a 28% or $7.25 per boe decrease compared to $25.58 per boe for the three months ended March 31, 2021 driven by ~~higher~~$8.43 per boe of lower unhedged fuel costs ~~related to~~for our California steam operations. Unhedged average fuel ~~cost increased $2.31~~purchase price decreased $3.62 per ~~Boe, or 65%~~mmbtu to $3.31 per mmbtu in the ~~third~~second quarter ~~2020 from $3.54 for~~2021 compared to the unusually high prices caused by Winter Storm Uri in the three months ended ~~June 30, 2020. Non-fuel lease~~March 31, 2021. Non-energy operating expense ~~increased $0.15~~decreased $0.03 per ~~Boe due to~~boe as a result of lower ~~sales volumes while spending on an absolute dollar basis was $1 million lower including lower facilities gas compression, oil~~outside services, well maintenance and ~~water processing costs.~~facility costs, partially offset by higher lease overhead and chemicals. Even with rising prices in 2021, we have held non-energy costs down following the cost savings efforts which began in 2020. Lease operating expenses include fuel, maintenance, labor including supervision, vehicles, workover expenses, field office, and tools and supplies. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.

Electricity generation expenses ~~increased~~decreased approximately ~~46%~~39% to ~~$1.66~~$1.90 per ~~Boe for the three months ended September 30, 2020, compared to $1.14 per Boe~~boe for the three months ended June 30, ~~2020~~2021, compared to $3.14 per boe for the three months ended March 31, 2021 due to ~~higher~~lower natural gas costs described ~~above and lower sales volumes.~~above. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.

Gains and losses on natural gas purchase derivatives resulted in a ~~$16~~$12 million gain for the three months ended ~~September~~June 30, ~~2020~~2021 and a ~~loss~~gain of $1$28 million in the three months ended ~~June 30, 2020.~~March 31, 2021. Settlement ~~losses~~gains for each of the three months ended ~~September 30, 2020 and~~ June 30, ~~2020~~2021 and March 31, 2021 were ~~$1 million and $7~~$2 million or ~~$0.24~~$0.77 per boe and ~~$2.78~~$26 million, or $10.78 per ~~Boe,~~boe, respectively, and decreased due to ~~higher~~lower gas ~~prices.~~prices which came off unprecedented highs in the first quarter of 2021 from Winter Storm Uri. The mark-to-market valuation gain for the three months ended ~~September~~June 30, ~~2020~~2021 was ~~$17~~$10 million compared to a $6$2 million gain for the prior quarter. Generally, because we are the fixed price payer on these natural gas swaps, increases in the associated futures prices will result in valuation gains.

~~Transportation expenses were essentially flat at $0.69 per Boe for the three months ended September 30, 2020 compared to $0.67 per Boe for the three months ended June 30, 2020.~~

~~Marketing expenses were comparable for the three months ended September 30, 2020 and June 30, 2020.~~

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Transportation expense increased slightly to $0.70 per boe for the three months ended June 30, 2021 compared to $0.65 per boe for the three months ended March 31, 2021.

Marketing expenses decreased by $0.90 per boe for the three months ended June 30, 2021 when compared to the three months ended March 31, 2021 due to the unprecedented natural gas purchase prices caused by the demand spike from Winter Storm Uri in the first quarter of 2021.

General and administrative expenses ~~increased~~decreased by ~~$0.4~~$1.0 million, or 2%6%, to ~~$19~~$16.1 million for the three months ended ~~September~~June 30, ~~2020,~~2021, compared to the three months ended ~~June 30, 2020.~~March 31, 2021, due to the following matters and those noted in adjusted general and administrative expenses below. For the three months ended ~~September 30, 2020 and~~ June 30, ~~2020,~~2021 and March 31, 2021, general and administrative expenses included non-cash stock compensation costs of approximately ~~$3.8~~$2.8 million and ~~$4.4~~$3.7 million, ~~respectively, and certain~~respectively. We had no non-recurring costs ~~of approximately $1.5 million and $0.3 million, respectively. Non-cash stock compensation expense declined from the second quarter 2020 due to the awards that expired or were forfeited~~ in the ~~third quarter 2020 and had been fully expensed at that time. The third quarter 2020 non-recurring costs mainly consisted~~first half of ~~costs related to the retirement of former Chief Operating Officer ("COO") and hiring of new COO. Less than~~2021. Approximately 10% of our overhead is capitalized and thus excluded from general and administrative expenses.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, ~~were $14~~decreased 1% to $13.3 million for ~~each of~~ the three ~~month periods~~months ended ~~September 30, 2020 and~~ June 30, ~~2020. These cost levels include~~2021 compared to $13.4 million for the three months ended March 31, 2021. On a ~~slight reduction~~per boe basis, adjusted general and administrative expenses decreased to $5.35 per boe from $5.50 per boe in ~~headcount since early 2020, although none~~the first quarter 2021 due to the impact of ~~these reductions are a result of the current economic environment.~~higher production. Please see ~~“-Non-GAAP~~“—Non-GAAP Financial Measures” for a reconciliation of adjusted general and administrative expense to general and administrative expenses, the most directly comparable financial measures calculated and presented in accordance with GAAP.

DD&A ~~decreased~~increased by $2 million or 4%6% to approximately $36 million for the three months ended ~~September~~June 30, ~~2020~~2021 compared to the three months ended ~~June 30, 2020.~~March 31, 2021. This ~~decrease~~increase is ~~attributable~~due to ~~the reduced sales volumes period-over-period.~~increased production and higher depletion rates from our periodic re-evaluation of these estimates.

Taxes, Other Than Income Taxes


		Three Months Ended				$ Change		% Change			Three Months Ended				$ Change		% Change
		September 30, 2020		June 30, 2020							June 30, 2021		March 31, 2021
		(per Boe)									(per boe)
Severance taxes	Severance taxes	$	0.82	$	0.70	$	0.12	17	%	Severance taxes	$	0.97	$	0.99	$	(0.02)	(2)	%
Ad valorem and property taxes	Ad valorem and property taxes	1.60		1.39		0.21		15	%	Ad valorem and property taxes	1.99		2.01		(0.02)		(1)	%
Greenhouse gas allowances	Greenhouse gas allowances	1.49		1.85		(0.36)		(19)	%	Greenhouse gas allowances	1.71		0.93		0.78		84	%

Total taxes other than income taxes	Total taxes other than income taxes	$	3.91	$	3.94	$	(0.03)	(1)	%	Total taxes other than income taxes	$	4.67	$	3.93	$	0.74	19	%

Taxes, other than income taxes, ~~decreased~~increased in the three months ended ~~September~~June 30, ~~2020~~2021 by ~~$0.03~~$0.74 per ~~Boe,~~boe, or 1%19%, to ~~$3.91.~~$4.67. Greenhouse gas ~~("GHG"~~(“GHG”) costs were ~~lower~~higher in the ~~third~~second quarter of ~~2020 as the prices remained relatively flat while the emission volumes declined. During the third quarter 2020, we experienced higher property tax rates, as well as higher severance tax rates~~2021 due to ~~the expiration of certain deductions. These changes were also impacted by the decrease in sales volumes in the third quarter 2020.~~higher mark-to-market valuations.

Other Operating ~~(Income)~~ Expenses

Other operating expenses for the three months ended ~~September~~June 30, ~~2020~~2021 was less than $0.1 million and mainly consisted of $2 million of supplemental property tax assessments and royalty audit charges and $2 million of employee retention credits. Other operating expenses of $1 million for the three months ended March 31, 2021 comprised mainly of ~~excess abandonment costs and excess~~additional storage capacity, obtained in response to global oil storage ~~concerns. Other operating income of $1 million for the three months ended June 30, 2020 included refunds from sales taxes paid in~~concerns, along with prior years ~~and resolved claims from our prior parent company's bankruptcy.~~royalty audit charges.

Interest Expense

Interest expense was relatively flat at $8 million for each of the three months ended ~~September 30, 2020 and~~ June 30, ~~2020.~~

~~Income Tax (Benefit) Expense~~

~~Our effective tax rate was approximately 10%~~2021 and ~~26% for the three months ended September 30, 2020 and June 30, 2020, respectively. The rate in the third quarter 2020 was negatively impacted by adjustments to our~~March 31, 2021.

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Income Tax Benefit

Our effective tax rate was approximately 1% and 2% for the three months ended June 30, 2021 and March 31, 2021, respectively. The rates in each quarter were impacted by the valuation allowance ~~during~~recorded due to the ~~quarter related to current year losses and expected~~estimated future realizability of deferred tax assets.

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


		Three Months Ended September 30,				$ Change		% Change			Three Months Ended June 30,				$ Change		% Change
		2020		2019							2021		2020
		(in thousands)									(in thousands)
Revenues and other:	Revenues and other:									Revenues and other:
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	92,239	$	141,250	$	(49,011)	(35)	%	Oil, natural gas and NGL sales	$	147,775	$	70,515	$	77,260	110	%
Electricity sales	Electricity sales	8,744		7,460		1,284		17	%	Electricity sales	6,888		4,884		2,004		41	%
(Losses) gains on oil derivatives		(11,564)		45,509		(57,073)		n/a
Losses on oil and gas sales derivatives										Losses on oil and gas sales derivatives	(55,653)		(42,267)		(13,386)		32	%
Marketing and other revenues	Marketing and other revenues	330		453		(123)		(27)	%	Marketing and other revenues	239		321		(82)		(26)	%
Total revenues and other	Total revenues and other	$	89,749	$	194,672	$	(104,923)	(54)	%	Total revenues and other	$	99,249	$	33,453	$	65,796	197	%

Revenues and Other

Oil, natural gas and NGL sales ~~decreased~~increased by ~~$49~~$77 million, or ~~35%~~110% to approximately ~~$92~~$148 million for the three months ended ~~September~~June 30, ~~2020~~2021 when compared to the three months ended ~~September~~June 30, ~~2019.~~2020. This variance was driven by ~~$40~~$81 million of ~~lower~~higher unhedged commodity prices, ~~as well as $9 million of~~partially offset by lower volumes.

Electricity sales represent sales to utilities, and increased by ~~$1.3~~$2.0 million, or ~~17%~~41%, to approximately $9$7 million for the three months ended ~~September~~June 30, ~~2020~~2021 when compared to the three months ended ~~September~~June 30, ~~2019.~~2020. The increase was ~~equally split between~~largely due to higher unit sales prices ~~and~~driven by higher ~~sales volumes.~~natural gas prices.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement ~~gains~~loss for the three months ended ~~September~~June 30, 2021 was $40 million compared to the gain for the three months ended June 30, 2020 ~~and September 30, 2019 were $36 million and $17 million, respectively.~~of $59 million. The quarter-over-quarter ~~increase in~~change from settlement gains to losses was driven by higher oil prices in the second quarter 2021 and lower oil prices in the second quarter 2020 relative to our derivative fixed ~~contract prices and more volumes hedged in the third quarter of 2020 compared to the third quarter of 2019.~~prices. The mark-to-market non-cash loss of ~~$48~~$16 million for the three months ended ~~September~~June 30, ~~2020~~2021 was due to higher futures prices relative to our derivative fixed contract prices at ~~September~~June 30, ~~2020.~~2021. The mark-to-market non-cash ~~gain~~loss of ~~$29~~$101 million for the three months ended ~~September~~June 30, ~~2019,~~2020, was ~~primarily~~ due to ~~lower~~higher futures prices relative to ~~our~~the derivative fixed ~~contract~~ prices at ~~September~~June 30, ~~2019.~~2020.

Marketing and other revenues were comparable for the periods presented.

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		Three Months Ended September 30,				$ Change		% Change			Three Months Ended June 30,				$ Change		% Change
		2020		2019							2021		2020
		(in thousands, except expenses per Boe)									(in thousands, except expenses per boe)
Expenses and other:	Expenses and other:									Expenses and other:
Lease operating expenses	Lease operating expenses	$	45,243	$	50,957	$	(5,714)	(11)	%	Lease operating expenses	$	45,543	$	40,733	$	4,810	12	%
Electricity generation expenses	Electricity generation expenses	4,217		3,781		436		12	%	Electricity generation expenses	4,712		3,022		1,690		56	%
Transportation expenses	Transportation expenses	1,768		2,067		(299)		(14)	%	Transportation expenses	1,757		1,789		(32)		(2)	%
Marketing expenses	Marketing expenses	326		398		(72)		(18)	%	Marketing expenses	44		280		(236)		(84)	%
General and administrative expenses	General and administrative expenses	19,173		16,434		2,739		17	%	General and administrative expenses	16,065		18,777		(2,712)		(14)	%
Depreciation, depletion and amortization	Depreciation, depletion and amortization	35,905		27,664		8,241		30	%	Depreciation, depletion and amortization	35,850		37,512		(1,662)		(4)	%

Taxes, other than income taxes	Taxes, other than income taxes	9,913		9,249		664		7	%	Taxes, other than income taxes	11,603		10,449		1,154		11	%

(Gain) losses on natural gas derivatives		(15,784)		3,008		(18,792)		n/a
(Gains) losses on natural gas purchase derivatives										(Gains) losses on natural gas purchase derivatives	(11,639)		925		(12,564)		n/a
Other operating expenses (income)	Other operating expenses (income)	1,648		(550)		2,198		n/a		Other operating expenses (income)	42		(1,192)		1,234		(104)	%
Total expenses and other	Total expenses and other	102,409		113,008		(10,599)		(9)	%	Total expenses and other	103,977		112,295		(8,318)		(7)	%
Other (expenses) income:	Other (expenses) income:									Other (expenses) income:
Interest expense	Interest expense	(8,391)		(8,597)		206		(2)	%	Interest expense	(8,217)		(8,676)		459		(5)	%
Other, net	Other, net	(3)		(77)		74		(96)	%	Other, net	(8)		(6)		(2)		33	%
Reorganization items, net		—		(170)		170		(100)	%
(Loss) income before income taxes		(21,054)		72,820		(93,874)		n/a
Income tax (benefit) expense		(2,190)		20,171		(22,361)		n/a
Net (loss) income		$	(18,864)	$	52,649	$	(71,513)	n/a

Loss before income taxes										Loss before income taxes	(12,953)		(87,524)		74,571		(85)	%
Income tax benefit										Income tax benefit	(72)		(22,623)		22,551		(100)	%
Net loss										Net loss	$	(12,881)	$	(64,901)	$	52,020	(80)	%

Expenses per Boe:(1)
Expenses per boe:(1)										Expenses per boe:(1)
Lease operating expenses	Lease operating expenses	$	17.83	$	18.74	$	(0.91)	(5)	%	Lease operating expenses	$	18.33	$	15.37	$	2.96	19	%
Electricity generation expenses	Electricity generation expenses	1.66		1.39		0.27		19	%	Electricity generation expenses	1.90		1.14		0.76		67	%
Electricity sales(1)	Electricity sales(1)	(3.45)		(2.74)		(0.71)		26	%	Electricity sales(1)	(2.77)		(1.84)		(0.93)		51	%
Transportation expenses	Transportation expenses	0.69		0.76		(0.07)		(9)	%	Transportation expenses	0.70		0.67		0.03		4	%
Transportation sales(1)	Transportation sales(1)	—		(0.01)		0.01		(100)	%	Transportation sales(1)	(0.05)		(0.01)		(0.04)		400	%
Marketing expenses	Marketing expenses	0.13		0.15		(0.02)		(13)	%	Marketing expenses	0.02		0.11		(0.09)		(82)	%
Marketing revenues(1)	Marketing revenues(1)	(0.13)		(0.15)		0.02		(13)	%	Marketing revenues(1)	(0.05)		(0.11)		0.06		(55)	%
Derivatives settlements paid for gas purchases(1)		0.24		0.77		(0.53)		(69)	%
Derivatives settlements (received) paid for gas purchases(1)										Derivatives settlements (received) paid for gas purchases(1)	(0.77)		2.78		(3.55)		(128)	%
Total operating expenses	Total operating expenses	$	16.97	$	18.90	$	(1.93)	(10)	%	Total operating expenses	$	17.31	$	18.11	$	(0.80)	(4)	%
Total unhedged operating expenses(2)	Total unhedged operating expenses(2)	$	16.73	$	18.13	$	(1.40)	(8)	%	Total unhedged operating expenses(2)	$	18.08	$	15.33	$	2.75	18	%

Total non-energy operating expenses~~(4)~~(3)	Total non-energy operating expenses~~(4)~~(3)	$	13.34	$	14.09	$	(0.75)	(5)	%	Total non-energy operating expenses~~(4)~~(3)	$	12.71	$	12.81	$	(0.10)	(1)	%
Total energy operating expenses~~(5)~~(4)	Total energy operating expenses~~(5)~~(4)	$	3.65	$	4.81	$	(1.16)	(24)	%	Total energy operating expenses~~(5)~~(4)	$	4.60	$	5.30	$	(0.70)	(13)	%

General and administrative expenses~~(3)~~(5)	General and administrative expenses~~(3)~~(5)	$	7.56	$	6.04	$	1.52	25	%	General and administrative expenses~~(3)~~(5)	$	6.46	$	7.09	$	(0.63)	(9)	%
Depreciation, depletion and amortization	Depreciation, depletion and amortization	$	14.15	$	10.17	$	3.98	39	%	Depreciation, depletion and amortization	$	14.43	$	14.16	$	0.27	2	%
Taxes, other than income taxes	Taxes, other than income taxes	$	3.91	$	3.40	$	0.51	15	%	Taxes, other than income taxes	$	4.67	$	3.94	$	0.73	19	%

__________

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(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.

(3) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $2.08 per Boe and $0.91 per Boe for the three months ended September 30, 2020 and September 30, 2019, respectively.

~~(4)~~ Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.

~~(5)~~(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.

~~Expenses~~(5) Includes non-recurring costs and ~~Other~~

~~Operating expenses, including hedge effects, decreased by 10% or $1.93~~non-cash stock compensation expense, in aggregate, of approximately $1.11 per ~~Boe to $16.97~~boe and $1.77 per Boe for the third quarter 2020 compared to $18.90 per Boe for the third quarter 2019. This decrease included $0.91 per Boe lower lease operating expenses and $0.44 of higher electricity sales margin and $0.53 per Boe of more favorable gas hedge settlements in 2020. Additionally, operating expenses, on an unhedged basis, were 8%, or $1.40 per Boe lowerboe for the three months ended ~~September~~June 30, 2021 and June 30, 2020, respectively.

Expenses and Other

On a hedged basis, operating expenses, decreased by 4% or $0.80 per boe to $17.31 per boe for the second quarter 2021 compared to $18.11 per boe for the ~~three months ended September 30, 2019~~second quarter 2020. The decrease was due to ~~these same non-hedge factors.~~lower energy operating expense of $0.70 per boe and lower non-energy operating expense of $0.10 per boe.

~~As a result of our 2020 cost savings and efficiency initiatives, we experienced a positive and substantial impact on~~Unhedged lease operating expenses ~~in 2020 when compared to 2019. Lease operating expenses~~ were ~~$17.83~~$18.33 per ~~Boe~~boe for the three months ended ~~September~~June 30, ~~2020,~~2021, a 5%19% or ~~$0.91~~$2.96 per ~~Boe reduction~~boe increase compared to ~~$18.74~~$15.37 for the three months ended ~~September~~June 30, ~~2019. Non-fuel lease~~2020 driven by an 87% or $3.78 per boe higher unhedged fuel costs, for our California steam operations. Unhedged average fuel purchase price increased $1.57 to $3.31 per mmbtu in the second quarter 2021 compared to $1.74 per mmbtu in the second quarter 2020. Non-energy operating expense decreases included $0.65 of lower costs related to maintenance, as well as $0.46 in facilities gas compression and oil and water processing costs. On an absolute dollar basis, non-fuel lease operating expenses declined ~~$4 million in the third quarter 2020~~$0.10 per boe compared to the ~~same period last year. Lease operating fuel cost related to our California steam operations were unchanged during the third~~second quarter ~~2020 from the same quarter 2019 due to more efficient steam consumption per Boe, which~~of 2020. These decreases included lower facilities costs and outside services, partially offset by higher ~~natural gas prices. Lease operating expenses include fuel,~~well maintenance ~~labor including supervision, vehicles, workover expenses, field office, tools~~ and ~~supplies. Fuel costs excluded the effects of natural gas derivative settlements discussed below.~~recompletion activities.

Electricity generation expenses increased approximately ~~19%~~67% to ~~$1.66~~$1.90 per ~~Boe~~boe for the three months ended ~~September~~June 30, ~~2020~~2021 from ~~$1.39~~$1.14 per ~~Boe~~boe for the same period in ~~2019 primarily~~2020 due to the previously discussed higher natural gas ~~costs previously mentioned, as well as the impact of lower Boe volumes.~~costs. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements.

Gains and losses on natural gas purchase derivatives for the three months ended ~~September~~June 30, ~~2020~~2021 and ~~September~~June 30, ~~2019~~2020 resulted in a gain of ~~$16~~$12 million and a loss of $3$1 million, respectively. ~~Settlement losses~~Settlements for each of the three months ended ~~September~~June 30, 2021 and 2020, ~~and 2019,~~ were ~~$1 million and~~ $2 million or ~~$0.24 and~~ $0.77 per ~~Boe, respectively,~~boe of gain and ~~decreased due to~~$7 million or $2.78 per boe of loss, driven by higher gas prices ~~during~~in 2021 compared to 2020. The mark-to-market valuation gain for the three months ended ~~September~~June 30, ~~2020~~2021 was ~~$17~~$10 million compared to $1$6 million of ~~loss~~gain for the same period in ~~2019,~~2020, consistent with the changes in futures prices at the end of each period. Because we are the fixed price payer on these natural gas swaps, generally, increases in the associated price index creates valuation gains.

Transportation expenses ~~were down $0.07 per Boe to $0.69~~remained essentially flat for the three months ended ~~September~~June 30, ~~2020 compared to the three months ended September~~2021 and June 30, ~~2019 as a result of lower natural gas sales volumes.~~2020.

Marketing expenses decreased ~~13%~~ to ~~$0.13~~$0.02 per ~~Boe~~boe for the three months ended ~~September~~June 30, ~~2020,~~2021, compared to ~~$0.15~~$0.11 per ~~Boe~~boe for the three months ended ~~September~~June 30, ~~2019~~2020, mostly due to lower gas prices.

General and administrative expenses ~~increased~~decreased $3 million, or ~~17%~~14%, to approximately ~~$19~~$16 million for the three months ended ~~September~~June 30, ~~2020~~2021 compared to the three months ended ~~September~~June 30, ~~2019.~~2020. For the three months

~~Table of Contents~~

ended ~~September~~June 30, 2021 and June 30, 2020, ~~and September 30, 2019,~~ general and administrative expenses included non-cash stock compensation costs of approximately ~~$3.8~~$2.8 million and ~~$2.3~~$4.4 million, respectively, ~~and~~with no non-recurring costs ~~of approximately $1.5~~in 2021 and $0.3 million ~~and $0.2 million, respectively.~~in 2020.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, ~~were $14~~decreased 6% to $13.3 million for ~~each of~~the three months ended June 30, 2021 compared to $14.1 million for the three month periods ended ~~September~~June 30, ~~2020~~2020. The decrease was primarily due to lower professional service expenses and ~~September 30, 2019.~~employee costs.

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DD&A ~~increased $8~~decreased $2 million, or ~~30%~~4%, to approximately $36 million for the three months ended ~~September~~June 30, ~~2020~~2021 compared to the three months ended ~~September~~June 30, ~~2019,~~2020, primarily due to ~~higher depreciation and depletion rates for 2020, partially offset by~~6% lower sales ~~volumes.~~volumes compared to the same period in 2020. On a per ~~Boe~~boe basis, period-over-period DD&A increased ~~$3.98~~$0.27 to ~~$14.15~~$14.43 from ~~$10.17~~$14.16 due to ~~our increasing capital development program throughout 2019 and~~higher depletion rates during the ~~first~~second quarter of ~~2020,~~2021, compared to ~~prior periods.~~the second quarter 2020.

Taxes, Other Than Income Taxes


		Three Months Ended September 30,				$ Change		% Change			Three Months Ended June 30,				$ Change		% Change
		2020		2019							2021		2020
		(per Boe)									(per boe)
Severance taxes	Severance taxes	$	0.82	$	0.67	$	0.15	22	%	Severance taxes	$	0.97	$	0.70	$	0.27	39	%
Ad valorem and property taxes	Ad valorem and property taxes	1.60		1.23		0.37		30	%	Ad valorem and property taxes	1.99		1.39		0.60		43	%
Greenhouse gas allowances	Greenhouse gas allowances	1.49		1.50		(0.01)		(1)	%	Greenhouse gas allowances	1.71		1.85		(0.14)		(8)	%
Total taxes other than income taxes	Total taxes other than income taxes	$	3.91	$	3.40	$	0.51	15	%	Total taxes other than income taxes	$	4.67	$	3.94	$	0.73	19	%

Taxes, other than income taxes increased ~~15%~~19% to ~~$3.91~~$4.67 per ~~Boe~~boe for the three months ended ~~September~~June 30, ~~2020~~2021 compared to ~~$3.40~~$3.94 per ~~Boe~~boe for the three months ended ~~September~~June 30, ~~2019. The increase was largely~~2020. Severance taxes increased from the prior year due to higher Utah revenue. Ad valorem and property ~~tax rates combined with lower sales volumes, as well as~~taxes increased ~~severance tax rates~~ due to higher California tax assessments. Greenhouse gas allowances declined from the ~~expiration~~second quarter of ~~certain deductions~~2020 as a result of opportunistic allowance purchases and an increase in ~~2020.~~state allocated allowances for 2021 which more than offset higher mark-to-market valuations.

Other Operating Expenses (Income) ~~Expenses~~

Other operating ~~expenses~~expense for the three months ended ~~September~~June 30, ~~2020~~2021 was less than $0.1 million and mainly consisted of $2 million ~~comprised mainly~~ of ~~excess abandonment costs~~supplemental property tax assessments and ~~excess storage capacity obtained in response to global oil storage concerns.~~royalty audit charges and $2 million of employee retention credits. Other operating income for the three months ended ~~September~~June 30, ~~2019~~2020 were $1 million and ~~consisted~~comprised mainly of sales tax and bankruptcy-related refunds, partially offset by excess abandonment ~~costs.~~costs and drilling rig standby charges.

Interest Expense

Interest expense was comparable in the three months ended ~~September~~June 30, ~~2020~~2021 and ~~September~~June 30, ~~2019.~~

~~Reorganization items, net~~

~~Reorganization items, net were not material for the three months ended September 30, 2020 and September 30, 2019.~~2020.

Income Tax ~~(Benefit) Expense~~Benefit

Our effective tax rate was ~~10%~~approximately 1% for the three months ended ~~September~~June 30, ~~2020~~2021 compared to ~~the 28%~~26% for the three months ended ~~September~~June 30, ~~2019.~~2020. The rate in the ~~third~~second quarter ~~2020~~2021 was ~~negatively~~ impacted by ~~adjustments to our~~the valuation allowance ~~during~~recorded due to the ~~quarter related to current year losses and expected~~estimated future realizability of deferred tax assets.

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~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021 compared to ~~Nine~~Six Months Ended ~~September~~June 30, ~~2019.~~2020.


		Nine Months Ended September 30,				$ Change		% Change			Six Months Ended June 30,				$ Change		% Change
		2020		2019							2021		2020
		(in thousands)									(in thousands)
Revenues and other:	Revenues and other:									Revenues and other:
Oil, natural gas and NGL sales	Oil, natural gas and NGL sales	$	284,852	$	409,259	$	(124,407)	(30)	%	Oil, natural gas and NGL sales	$	283,040	$	192,613	$	90,427	47	%
Electricity sales	Electricity sales	19,089		22,553		(3,464)		(15)	%	Electricity sales	16,957		10,345		6,612		64	%
Gains on oil derivatives		157,398		7,546		149,852		n/a
(Losses) gains on oil and gas sales derivatives										(Losses) gains on oil and gas sales derivatives	(109,157)		168,962		(278,119)		n/a
Marketing and other revenues	Marketing and other revenues	1,128		1,918		(790)		(41)	%	Marketing and other revenues	2,610		798		1,812		227	%
Total revenues and other	Total revenues and other	$	462,467	$	441,276	$	21,191	5	%	Total revenues and other	$	193,450	$	372,718	$	(179,268)	(48)	%

Revenues and Other

Oil, natural gas and NGL sales ~~decreased~~increased by ~~$124~~$90 million, or ~~30%~~47% to approximately ~~$285~~$283 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 when compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. The ~~decrease~~increase was driven by ~~$139~~$108 million attributable to ~~lower oil~~higher commodity prices, ~~and $4 million attributable to lower gas prices. These decreases were~~ partially offset by ~~approximately $21 million attributable to higher~~lower oil volumes.

Electricity sales which represent sales to utilities ~~decreased $3~~increased $7 million or ~~15%~~64% to ~~$19~~$17 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 when compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. The ~~decrease~~increase was mostly due to ~~lower~~higher unit sales prices that were driven by ~~lower~~higher natural gas prices.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement losses of $66 million and gains of $83 million for the ~~nine~~six months ended ~~September~~June 30, 2021 and June 30, 2020, ~~and September 30, 2019 were $119 million and $29 million,~~ respectively. The ~~increase in~~period over period shift from settlement gains to settlement losses was driven by ~~lower~~higher oil prices relative to the derivative fixed prices ~~and more volumes hedged~~ in the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021, compared to lower oil prices relative to the ~~nine~~derivatives fixed prices in the six months ended ~~September~~June 30, ~~2019.~~2020. The mark-to-market non-cash ~~gain~~loss of ~~$38 million~~ $43 million for the ~~nine~~six months ended ~~September~~June 30, 2021 was due to higher futures prices relative to the derivative fixed prices at June 30, 2021. The gain of $86 million for the six months ended June 30, 2020, was primarily due to lower futures prices relative to the derivative fixed prices at ~~September~~June 30, 2020. ~~The loss of~~ ~~$21~~ ~~million for the nine months ended September 30, 2019, was primarily due to higher futures prices relative to the derivative fixed prices at September 30, 2019.~~

Marketing and other revenues were ~~lower~~higher for the ~~nine~~six months ended ~~September~~June 30, ~~2020,~~2021, compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 due to ~~lower~~higher average gas prices.

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		Nine Months Ended September 30,				$ Change		% Change			Six Months Ended June 30,				$ Change		% Change
		2020		2019							2021		2020
		(in thousands, except expenses per Boe)									(in thousands, except expenses per boe)
Expenses and other:	Expenses and other:									Expenses and other:
Lease operating expenses	Lease operating expenses	$	136,727	$	156,765	$	(20,038)	(13)	%	Lease operating expenses	$	107,827	$	91,485	$	16,342	18	%
Electricity generation expenses	Electricity generation expenses	11,186		14,705		(3,519)		(24)	%	Electricity generation expenses	12,360		6,968		5,392		77	%
Transportation expenses	Transportation expenses	5,379		5,935		(556)		(9)	%	Transportation expenses	3,333		3,611		(278)		(8)	%
Marketing expenses	Marketing expenses	1,036		1,670		(634)		(38)	%	Marketing expenses	2,271		710		1,561		220	%
General and administrative expenses	General and administrative expenses	57,287		46,932		10,355		22	%	General and administrative expenses	33,135		38,114		(4,979)		(13)	%
Depreciation, depletion and amortization	Depreciation, depletion and amortization	108,746		75,904		32,842		43	%	Depreciation, depletion and amortization	69,690		72,841		(3,151)		(4)	%
Impairment of oil and gas properties	Impairment of oil and gas properties	289,085		—		289,085		100	%	Impairment of oil and gas properties	—		289,085		(289,085)		100	%
Taxes, other than income taxes	Taxes, other than income taxes	24,714		28,683		(3,969)		(14)	%	Taxes, other than income taxes	21,160		14,801		6,359		43	%

(Gain) losses on natural gas derivatives		(2,824)		10,342		(13,166)		n/a
(Gains) losses on natural gas purchase derivatives										(Gains) losses on natural gas purchase derivatives	(39,369)		12,960		(52,329)		n/a
Other operating expenses	Other operating expenses	2,658		3,814		(1,156)		(30)	%	Other operating expenses	841		1,010		(169)		(17)	%
Total expenses and other	Total expenses and other	633,994		344,750		289,244		84	%	Total expenses and other	211,248		531,585		(320,337)		(60)	%
Other (expenses) income:	Other (expenses) income:									Other (expenses) income:
Interest expense	Interest expense	(25,987)		(26,362)		375		(1)	%	Interest expense	(16,702)		(17,596)		894		(5)	%
Other, net	Other, net	(15)		79		(94)		n/a		Other, net	(151)		(12)		(139)		1,158	%
Reorganization items, net		—		(426)		426		(100)	%
(Loss) income before income taxes		(197,529)		69,817		(267,346)		n/a
Income tax expense (benefit)		1,536		19,294		(17,758)		(92)	%
Net (loss) income		$	(199,065)	$	50,523	$	(249,588)	n/a

Loss before income taxes										Loss before income taxes	(34,651)		(176,475)		141,824		(80)	%
Income tax (benefit) expense										Income tax (benefit) expense	(448)		3,726		(4,174)		(112)	%
Net loss										Net loss	$	(34,203)	$	(180,201)	$	145,998	(81)	%

Expenses per Boe:(1)
Expenses per boe:(1)										Expenses per boe:(1)
Lease operating expenses	Lease operating expenses	$	17.12	$	20.31	$	(3.19)	(16)	%	Lease operating expenses	$	21.92	$	16.79	$	5.13	31	%
Electricity generation expenses	Electricity generation expenses	1.40		1.91		(0.51)		(27)	%	Electricity generation expenses	2.51		1.28		1.23		96	%
Electricity sales(1)	Electricity sales(1)	(2.39)		(2.92)		0.53		(18)	%	Electricity sales(1)	(3.45)		(1.90)		(1.55)		82	%
Transportation expenses	Transportation expenses	0.67		0.77		(0.10)		(13)	%	Transportation expenses	0.68		0.66		0.02		3	%
Transportation sales(1)	Transportation sales(1)	(0.01)		(0.03)		0.02		(67)	%	Transportation sales(1)	(0.05)		(0.01)		(0.04)		400	%
Marketing expenses	Marketing expenses	0.13		0.22		(0.09)		(41)	%	Marketing expenses	0.46		0.13		0.33		254	%
Marketing revenues(1)	Marketing revenues(1)	(0.12)		(0.21)		0.09		(43)	%	Marketing revenues(1)	(0.48)		(0.13)		(0.35)		269	%
Derivatives settlements paid (received) for gas purchases(1)		1.55		0.25		1.30		n/a
Derivatives settlements (received) paid for gas purchases(1)										Derivatives settlements (received) paid for gas purchases(1)	(5.72)		2.16		(7.88)		n/a
Total operating expenses	Total operating expenses	$	18.35	$	20.28	$	(1.93)	(10)	%	Total operating expenses	$	15.87	$	18.98	$	(3.11)	(16)	%
Total unhedged operating expenses(2)	Total unhedged operating expenses(2)	$	16.80	$	20.03	$	(3.23)	(16)	%	Total unhedged operating expenses(2)	$	21.59	$	16.82	$	4.77	28	%

Total non-energy operating expenses~~(4)~~(3)	Total non-energy operating expenses~~(4)~~(3)	$	13.41	$	14.75	$	(1.34)	(9)	%	Total non-energy operating expenses~~(4)~~(3)	$	12.73	$	13.44	$	(0.71)	(5)	%
Total energy operating expenses~~(5)~~(4)	Total energy operating expenses~~(5)~~(4)	$	4.94	$	5.54	$	(0.60)	(11)	%	Total energy operating expenses~~(5)~~(4)	$	3.14	$	5.54	$	(2.40)	(43)	%

General and administrative expenses~~(3)~~(5)	General and administrative expenses~~(3)~~(5)	$	7.17	$	6.08	$	1.09	18	%	General and administrative expenses~~(3)~~(5)	$	6.74	$	7.00	$	(0.26)	(4)	%
Depreciation, depletion and amortization	Depreciation, depletion and amortization	$	13.62	$	9.84	$	3.78	38	%	Depreciation, depletion and amortization	$	14.17	$	13.37	$	0.80	6	%
Taxes, other than income taxes	Taxes, other than income taxes	$	3.10	$	3.72	$	(0.62)	(17)	%	Taxes, other than income taxes	$	4.30	$	2.72	$	1.58	58	%

__________

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(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.

(3) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.85 per Boe and $1.18 per Boe for the nine months ended September 30, 2020 and September 30, 2019, respectively.

~~(4)~~ Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.

~~(5)~~(4) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.

(5) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.31 per boe and $1.74 per boe for the six months ended June 30, 2021 and June 30, 2020, respectively.

Expenses and Other

Operating expenses, including hedge effects, decreased 10% or $1.93 per Boe to $18.35 for the nine months ended September 30, 2020 from $20.28 per Boe for the nine months ended September 30, 2019 due to $3.19 per Boe lower lease operating expenses, partially offset by $1.30 per Boe of higher gas hedge settlement losses and $0.02 decrease in electricity sales margin. Additionally, operating expenses, on an unhedgedOn a hedged basis, ~~were $16.80 per Boe for the nine months ended September 30, 2020 which was approximately 16% lower than the nine months ended September 30, 2019 due to these same non-hedge factors.~~

~~Lease~~ operating expenses, decreased 16% or $3.11 per boe to ~~$17.12 per Boe~~$15.87 for the ~~nine~~six months ended ~~September~~June 30, ~~2020, a 16% or $3.19~~2021 from $18.98 per ~~Boe reduction compared to $20.31~~boe for the ~~nine~~six months ended ~~September~~June 30, ~~2019. The decrease was driven primarily by lower unhedged fuel prices related to our California steam operations and other cost savings~~. Unhedged fuel cost decreased $2.01 per Boe during the nine months ended September 30, 2020 from $6.81 in the same period of 2019 as natural gas prices declined 30%. Compared to the nine months ended September 30, 2019, the 2020 lease operating non-fuel expenses decreased $1.18, or $6 million2020. Our continuing emphasis on ~~an absolute dollar basis, primarily due to~~ cost savings ~~initiatives~~ and efficiency ~~measures implemented beginning~~initiatives, which began in the second quarter of 2020, demonstrated meaningful results in the first half of 2021 compared to the first half of 2020 as non-energy costs declined 5% or $0.71 per boe to $12.73 per boe.

Unhedged lease operating expenses were $21.92 per boe for the six months ended June 30, 2021, a 31% or $5.13 per boe increase compared to $16.79 for the six months ended June 30, 2020 driven by $7.03 per boe higher unhedged fuel costs, for our California steam operations.Unhedged average fuel purchase price doubled to $12.31 per mmbtu in the six months ended June 30, 2021 compared to the six months ended June 30, 2020. ~~These initiatives resulted in~~The key non-energy operating expense decreases included lower ~~maintenance~~facilities costs and outside services, ~~costs of $1.22 per Boe when compared to the nine months ended September 30, 2019. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.~~partially offset by higher well maintenance and recompletion activities.

Electricity generation expenses ~~decreased~~increased approximately ~~27%~~96% to ~~$1.40~~$2.51 per ~~Boe~~boe for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 from ~~$1.91~~$1.28 per ~~Boe~~boe for the same period in ~~2019 primarily driven by lower fuel cost. Decreased fuel~~2020 due to the previously discussed higher natural gas costs. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative ~~settlements discussed elsewhere.~~settlements.

~~Gain or loss~~Gains and losses on natural gas purchase derivatives for the ~~nine~~six months ended ~~September~~June 30, 2021 and June 30, 2020 ~~and September 30, 2019 was~~resulted in a gain of $3$39 million and a loss of ~~$10~~$13 million, respectively. The settlement ~~loss~~gain for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 was ~~$12~~$28 million, or ~~$1.55~~$5.72 per ~~Boe,~~boe, compared to a settlement loss of $2$12 million, or ~~$0.25~~$2.16 per ~~Boe~~boe for same period in ~~2019,~~2020, driven by higher gas prices in 2021 compared to 2020. The mark-to-market valuation gain for the six months ended June 30, 2021 was $12 million compared to $1 million of loss for the same period in 2020, consistent with the changes in ~~futures~~future prices at the end of each period. ~~The mark-to-market~~Because we are the fixed price payer on these natural gas swaps, generally, increases in the associated price index creates valuation ~~gain or loss for each of the periods ended September 30, 2020 and September 30, 2019 was a gain of $15 million and a loss of $8 million respectively.~~gains.

Transportation expenses ~~decreased 13% to $0.67 per Boe~~were comparable for the ~~nine months ended September 30, 2020, compared to $0.77 per Boe for the nine months ended September 30, 2019, mainly due to lower volumes shipped from our Rockies assets.~~periods presented.

Marketing expenses ~~decreased 41%~~increased to $0.46 per boe for the six months ended June 30, 2021, compared to $0.13 per ~~Boe~~boe for the ~~nine~~six months ended ~~September~~June 30, 2020 ~~compared to $0.22 per Boe for the nine months ended September 30, 2019~~largely due to ~~lower gas prices. Marketing expenses in these periods, which exclude~~higher prices from the ~~effects of hedging, represented the cost of~~February natural gas ~~purchased from and sold to third parties.~~

~~Table of Contents~~

demand spike caused by Winter Storm Uri.

General and administrative expenses ~~increased by approximately $10~~decreased $5 million, or ~~22%~~13%, to approximately $33 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. For the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~September~~June 30, ~~2019,~~2020, general and administrative expenses included non-cash stock compensation costs of approximately ~~$11~~$6 million and $6$7 million, respectively, and no non-recurring costs ~~of approximately $4~~during the six months ended June 30, 2021, and $2 million ~~and $3 million, respectively.~~during the same period in 2020.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, ~~were $43~~decreased $2 million, or 7% to $27 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 compared to ~~$38~~$29 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. The year-over-year ~~increases in both general and administrative expenses and adjusted general and administrative expenses were~~decrease was primarily due to ~~increased costs associated with supporting the company's growth, including the expansion~~lower professional service expenses and employee costs.

Table of ~~our corporate affairs department and activities whose purpose is to support our efforts and participation in the regulatory, political and legislative process primarily in California.~~Contents

DD&A ~~increased $33~~decreased $3 million, or ~~43%~~4%, to approximately ~~$109~~$70 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, primarily due to lower sales volumes compared to the ~~increased production and higher depreciation and depletion rates for~~same period in 2020. On a per ~~Boe~~boe basis, period-over-period DD&A increased ~~$3.78~~$0.80 to ~~$13.62~~$14.17 from ~~$9.84~~$13.37 due to ~~our increasing capital development program throughout 2019 and the first quarter of 2020,~~higher depletion rates in 2021, compared to ~~prior periods.~~2020.

Impairment of oil and gas properties

~~As discussed above, we~~We recorded a non-cash pre-tax asset impairment charge of $289 million on properties in Utah and certain California locations for the ~~nine~~six months ended ~~September~~June 30, 2020.

Taxes, Other Than Income Taxes


		Nine Months Ended September 30,				$ Change		% Change			Six Months Ended June 30,				$ Change		% Change
		2020		2019							2021		2020
		(per Boe)									(per boe)
Severance taxes	Severance taxes	$	0.74	$	0.57	$	0.17	30	%	Severance taxes	$	0.98	$	0.71	$	0.27	38	%
Ad valorem and property taxes	Ad valorem and property taxes	1.46		1.31		0.15		11	%	Ad valorem and property taxes	2.00		1.39		0.61		44	%
Greenhouse gas allowances	Greenhouse gas allowances	0.90		1.84		(0.94)		(51)	%	Greenhouse gas allowances	1.32		0.62		0.70		113	%
Total taxes other than income taxes	Total taxes other than income taxes	$	3.10	$	3.72	$	(0.62)	(17)	%	Total taxes other than income taxes	$	4.30	$	2.72	$	1.58	58	%

Taxes, other than income taxes ~~decreased $0.62~~increased $1.58 to ~~$3.10~~$4.30 per ~~Boe~~boe for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 compared to ~~$3.72~~$2.72 per ~~Boe~~boe for the ~~nine~~six months ended ~~September~~June 30, ~~2019.~~2020. The ~~decrease~~increase was largely due to ~~lower~~higher greenhouse gas ~~prices during 2020 including some~~mark-to-market valuations at June 30, 2021 and allowance purchases we made at low prices due to a temporary market dislocation in ~~the first quarter~~ 2020. During ~~2020,~~2021, we experienced higher California property tax rates, as well as higher severance ~~tax rates~~taxes due to ~~the expiration of certain deductions. These changes were also positively impacted by the increase~~increased revenues in ~~sales volumes during the nine months ended September 30, 2020 compared to the same period in 2019.~~Utah.

Other Operating Expenses (Income)

Other operating income and expenses for the ~~nine~~six months ended ~~September~~June 30, 2021 were net expenses of $1 million and mainly consisted of approximately $3 million of supplemental property tax assessments, royalty audit charges and tank rental costs, partially offset by $2 million of employee retention credits. For the six months ended June 30, 2020, ~~were $3 million including~~other operating expense mainly consist of excess abandonment costs, drilling rig standby ~~costs due to deferred drilling activity, and inventory storage costs,~~charges, partially offset by refunds ~~from sales taxes paid~~ in prior years and resolved claims from our prior parent company's bankruptcy. Other operating expenses for the nine months ended September 30, 2019 were $4 million and were mostly comprised of excess abandonment costs.2020.

Interest Expense

Interest expense was comparable in the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 and ~~September~~June 30, ~~2019.~~

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~~Reorganization items, net~~

~~Reorganization items, net were not material for the nine months ended September 30, 2020 and September 30, 2019.~~2020.

Income Tax (Benefit) Expense ~~(Benefit)~~

Our effective tax rate was ~~(1)%~~1% and ~~28%~~(2)% for the ~~nine~~six months ended ~~September~~June 30, 2021 and June 30, 2020, ~~and September 30, 2019,~~ respectively. The ~~rate~~rates in 2021 and 2020 ~~was~~were negatively impacted as we ~~have~~ recorded a valuation ~~allowance~~allowances on a large portion of our tax credits, ~~recorded in 2019~~net operating loss carryforwards and on other deferred tax assets as a result of ~~current year losses and changes during the year related to~~estimated future realizability.

Non-GAAP Financial Measures

Adjusted EBITDA, Levered Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses

Adjusted Net Income (Loss) is not a measure of net income (loss), Levered Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA is not a measure of either, in all cases, as determined by GAAP. Adjusted EBITDA, Levered Free Cash Flow and Adjusted Net Income (Loss) ~~and Levered Free Cash Flow~~ are supplemental non-GAAP financial

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measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual ~~out-of-period~~ and infrequent ~~items, including restructuring costs and reorganization~~ items. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends.

Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. Levered Free Cash Flow is used by management as a primary metric to plan capital allocation to sustain production levels and for internal growth opportunities, as well as hedging needs. It also serves as a measure for assessing our financial performance and our ability to generate excess cash from operations to service debt and pay dividends.

Adjusted Net Income (Loss) excludes the impact of unusual ~~out-of-period~~ and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual ~~out-of-period~~ and infrequent ~~items, including restructuring costs and reorganization~~ items, and the income tax expense or benefit of these adjustments using our effective tax rate.

While Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

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Adjusted General and Administrative Expenses is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and ~~restructuring~~unusual and ~~other non-recurring~~infrequent costs. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period.

We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature. Adjusted General and Administrative Expenses should not be considered as an alternative to, or more meaningful than, general and administrative expenses as determined in accordance with GAAP. Our computations of Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures of other companies.

The following tables present reconciliations of the non-GAAP financial measures Adjusted EBITDA and Levered Free Cash Flow to the GAAP financial measures of net income (loss) and net cash provided or used by operating activities, as applicable, for each of the periods indicated.

Three Months Ended Nine Months Ended
September 30, 2020 June 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net (loss) income $ (18,864) $ (64,901) $ 52,649 $ (199,065) $ 50,523
Add (Subtract):
Interest expense 8,391 8,676 8,597 25,987 26,362
Income tax (benefit) expense (2,190) (22,623) 20,171 1,536 19,294
Depreciation, depletion and amortization 35,905 37,512 27,664 108,746 75,904
Impairment of oil and gas properties — — — 289,085 —
Derivative (gains) losses (4,220) 43,192 (42,501) (160,222) 2,796
Net cash received for scheduled derivative settlements 35,476 51,874 15,153 106,975 26,731
Other operating expense (income) 1,648 (1,192) (550) 2,658 3,814
Stock compensation expense 3,896 4,579 2,360 11,397 6,277
Non-recurring costs 1,473 316 219 3,651 3,061
Reorganization items, net — — 170 — 426
Adjusted EBITDA $ 61,515 $ 57,433 $ 83,931 $ 190,748 $ 215,188

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Three Months Ended Nine Months Ended
September 30, 2020 June 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019
(in thousands)
Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided by (used in) operating activities:
Net cash provided by operating activities $ 57,997 $ 41,939 $ 68,774 $ 144,419 $ 164,267
Add (Subtract):
Cash interest payments 14,435 648 14,864 29,962 30,136
Cash income tax payments 221 — — 222 —
Non-recurring costs 1,473 316 219 3,651 3,061
Other changes in operating assets and liabilities (12,611) 14,530 74 12,494 17,724
Adjusted EBITDA $ 61,515 $ 57,433 $ 83,931 $ 190,748 $ 215,188
Subtract:
Capital expenditures - accrual basis (5,426) (16,528) (63,488) (61,368) (169,217)
Interest expense (8,391) (8,676) (8,597) (25,987) (26,362)
Cash dividends declared — — (9,720) (9,564) (29,502)
Levered Free Cash Flow(1)
$ 47,698 $ 32,229 $ 2,126 $ 93,829 $ (9,893)



	Three Months Ended						Six Months Ended
	June 30, 2021		March 31, 2021		June 30, 2020		June 30, 2021		June 30, 2020
	(in thousands)
Adjusted EBITDA reconciliation to net loss:
Net loss	$	(12,881)	$	(21,322)	$	(64,901)	$	(34,203)	$	(180,201)
Add (Subtract):
Interest expense	8,217		8,485		8,676		16,702		17,596
Income tax (benefit) expense	(72)		(376)		(22,623)		(448)		3,726
Depreciation, depletion and amortization	35,850		33,840		37,512		69,690		72,841
Impairment of oil and gas properties	—		—		—		—		289,085

Losses (gains) on derivatives	44,014		25,774		43,192		69,788		(156,002)
Net cash (paid) received for scheduled derivative settlements	(37,431)		850		51,874		(36,581)		71,499
Other operating expense (income)	42		799		(1,192)		841		1,010
Stock compensation expense	2,860		3,779		4,579		6,639		7,501
Non-recurring costs	—		—		316		—		2,178

Adjusted EBITDA	$	40,599	$	51,829	$	57,433	$	92,428	$	129,233


	Three Months Ended						Six Months Ended
	June 30, 2021		March 31, 2021		June 30, 2020		June 30, 2021		June 30, 2020
	(in thousands)
Adjusted EBITDA reconciliation to net cash provided by operating activities and Levered Free Cash Flow calculation:
Net cash provided by operating activities	$	21,429	$	38,430	$	41,939	$	59,859	$	86,422
Add (Subtract):
Cash interest payments	288		14,637		648		14,925		15,527
Cash income tax payments	—		—		—		—		2

Non-recurring costs	—		—		316		—		2,178

Other changes in operating assets and liabilities	18,882		(1,238)		14,530		17,644		25,104

Adjusted EBITDA	$	40,599	$	51,829	$	57,433	$	92,428	$	129,233
Subtract:
Capital expenditures - accrual basis	(43,461)		(23,569)		(16,700)		(67,030)		(56,403)
Interest expense	(8,217)		(8,485)		(8,676)		(16,702)		(17,596)
Cash dividends declared	(3,219)		(3,474)		—		(6,693)		(9,564)
Levered Free Cash Flow(1)	$	(14,298)	$	16,301	$	32,057	$	2,003	$	45,670

__________

(1) Levered Free Cash Flow, as defined by the Company, includes cash paid for scheduled derivative settlements of $37 million for the three months ended June 30, 2021 and cash received for scheduled derivative settlements of ~~$35 million, $52~~$1 million and ~~$15~~$52 million, for the three months ended ~~September 30, 2020,~~March 31, 2021 and June 30, 2020, ~~and September 30, 2019,~~ respectively. Levered Free Cash Flow, as defined by the Company, includes cash paid for scheduled derivative settlements of $37 million for the six months ended June 30, 2021 and cash received for scheduled derivative settlements of ~~$107 million and $27~~$71 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020 and 2019, respectively.~~2020.

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The following table presents a reconciliation of the non-GAAP financial measure Adjusted Net Income (Loss) to the GAAP financial measure of net income (loss).

Three Months Ended Nine Months Ended
September 30, 2020 June 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019
(in thousands)
Adjusted Net Income (Loss) reconciliation to net (loss) income:
Net (loss) income $ (18,864) $ (64,901) $ 52,649 $ (199,065) $ 50,523
Add (Subtract): discrete income tax items (2,394) — — 44,306 —
Add (Subtract):
(Gains) losses on oil and natural gas derivatives (4,220) 43,192 (42,501) (160,222) 2,796
Net cash received for scheduled derivative settlements 35,476 51,874 15,153 106,975 26,731
Other operating expenses (income) 1,648 (1,192) (550) 2,658 3,814
Impairment of oil and gas properties — — — 289,085 —
Non-recurring costs 1,473 316 219 3,651 3,061
Reorganization items, net — — 170 — 426
Total additions, net 34,377 94,190 (27,509) 242,147 36,828
Income tax (expense) benefit of adjustments at effective tax rate(1)
333 (24,680) 7,620 (51,152) (10,164)
Adjusted Net Income $ 13,452 $ 4,609 $ 32,760 $ 36,236 $ 77,187


	Three Months Ended						Six Months Ended
	June 30, 2021		March 31, 2021		June 30, 2020		June 30, 2021		June 30, 2020
	(in thousands)
Adjusted Net (Loss) Income reconciliation to net loss:
Net loss	$	(12,881)	$	(21,322)	$	(64,901)	$	(34,203)	$	(180,201)
Add: discrete income tax items	—		—		—		—		46,700
Add (Subtract):
Losses (gains) on derivatives	44,014		25,774		43,192		69,788		(156,002)
Net cash (paid) received for scheduled derivative settlements	(37,431)		850		51,874		(36,581)		71,499
Other operating expenses (income)	42		799		(1,192)		841		1,010
Impairment of oil and gas properties	—		—		—		—		289,085
Non-recurring costs	—		—		316		—		2,178

Total additions, net	6,625		27,423		94,190		34,048		207,770
Income tax expense of adjustments at effective tax rate(1)	(37)		(474)		(24,680)		(511)		(51,485)
Adjusted Net (Loss) Income	$	(6,293)	$	5,627	$	4,609	$	(666)	$	22,784

Basic EPS on Adjusted Net (Loss) Income	$	(0.08)	$	0.07	$	0.06	$	(0.01)	$	0.29
Diluted EPS on Adjusted Net (Loss) Income	$	(0.08)	$	0.07	$	0.06	$	(0.01)	$	0.28

Weighted average shares of common stock outstanding - basic	80,471		80,115		79,795		80,294		79,702
Weighted average shares of common stock outstanding - diluted	80,471		82,276		80,640		80,294		80,545

__________

(1) Excludes discrete income tax items from the total additions, net line item and the tax effect the discrete income tax items have on the current ~~year effective tax~~ rate.

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The following table presents a reconciliation of the non-GAAP financial measure Adjusted General and Administrative Expenses to the GAAP financial measure of general and administrative expenses for each of the periods indicated.

Three Months Ended Nine Months Ended
September 30, 2020 June 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019
(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
General and administrative expenses $ 19,173 $ 18,777 $ 16,434 $ 57,287 $ 46,932
Subtract:
Non-cash stock compensation expense (G&A portion) (3,812) (4,380) (2,275) (11,111) (6,067)
Non-recurring costs (1,473) (316) (219) (3,651) (3,061)
Adjusted G&A $ 13,888 $ 14,081 $ 13,940 $ 42,525 $ 37,804
Adjusted general and administrative expenses ($/MBoe) $ 5.47 $ 5.31 $ 5.13 $ 5.33 $ 4.90

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	Three Months Ended						Six Months Ended
	June 30, 2021		March 31, 2021		June 30, 2020		June 30, 2021		June 30, 2020
	(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
General and administrative expenses	$	16,065	$	17,070	$	18,777	$	33,135	$	38,114
Subtract:
Non-cash stock compensation expense (G&A portion)	(2,763)		(3,669)		(4,380)		(6,432)		(7,299)
Non-recurring costs	—		—		(316)		—		(2,178)
Adjusted general and administrative expenses	$	13,302	$	13,401	$	14,081	$	26,703	$	28,637

Adjusted general and administrative expenses ($/boe)	$	5.35	$	5.50	$	5.31	$	5.43	$	5.26

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Liquidity and Capital Resources

Currently, we expect to fund our ~~primary sources of liquidity and~~2021 capital ~~resources will be~~expenditures with cash flows from our operations, supplemented if necessary by cash on hand resulting from excess Levered Free Cash Flow generated in 2020 and ~~as needed, borrowings under~~ the ~~RBL Facility, described below.~~first quarter of 2021. As of ~~September~~June 30, ~~2020,~~2021, we had liquidity of ~~$192~~$268 million, consisting of ~~$49~~$75 million cash in the bank and borrowing availability of ~~$143~~$193 million under our RBL ~~Facility. The RBL~~ Facility ~~currently has a $200~~(factoring in $7 million ~~borrowing base with a $200 million elected commitment and borrowing availability~~stand-by letters of ~~$150 million until the next~~credit). In April 2021, we completed our scheduled semi-annual borrowing base redetermination ~~that is scheduled to occur~~under our RBL Facility, which resulted in ~~November 2020, at which time we expect~~a reaffirmed borrowing base and the ~~availability to return to this~~Company's elected commitment ~~amount.~~at $200 million with no further borrowing restrictions beyond the covenants summarized below. The RBL Facility matures July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms. We also have $400 million in aggregate principal amount 7% senior unsecured notes due February 2026 (the “2026 Notes”) outstanding as further discussed below. We currently believe that our liquidity, ~~and~~ capital resources and cash on hand will be sufficient to conduct our business and operations for at least the next 12 months.

We currently expect our operations to continue to generate positive Levered Free Cash Flow ~~in 2020 and~~ for the combined two-year down-cycle that we projected through the end of 2021, ~~even at the currently depressed commodity price levels, given our current hedge positions and~~ based on our current operating ~~plans.~~plans, the current oil price levels and current hedge positions. We ~~currently~~ have ~~essentially all~~approximately 55% of our expected oil production hedged in the ~~fourth quarter~~remainder of ~~2020~~2021 at ~~nearly $60~~approximately $49 per ~~barrel,~~bbl, as well as additional 2021 hedge positions at nearly $46 per barrel for approximately 19,000 Bbls/d in the first half of 2021 and approximately 11,000 Bbls/d in the second half of 2021 at $46 per barrel. As of September 30, 2020, our oil ~~hedge positions had a fair value~~sales hedges of approximately ~~$45 million. However, our business, like other producers, has been and is expected to continue to be negatively affected by the ongoing and evolving volatility, uncertainty, and turmoil~~3,000 bbl/d at $60 per bbl in the oil and gas industry created by the COVID-19 demand destruction and the unknown supply levels caused by OPEC+’s actions, as further discussed under “Business Environment, Market Conditions and Outlook” in this report. Additionally in October 2020, we hedged 12,500 MMBtu/d of our 2021 Rockies gas production at nearly $3.00 per MMBtu.

In terms of immediate risks, if we were forced to shut-in a significant amount of our California production, as well as curtail some of our Utah and Colorado production, this could have a material, adverse effect on our financial and operational results. If we are forced to shut in production, we will incur additional costs to bring those associated wells back online, as well as additional costs and operating expenses while production is shut-in to, among other things, maintain the health of the reservoirs, meet contractual obligations and protect our interests, but without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we also need to shut-in steam injection for the reservoirs rather than incur those costs, the wells may not, initially or at all, come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state, our proved reserve estimates could decrease, which could result in a reduction to our borrowing base under the RBL Facility and our liquidity.

2022. In the longer term, if ~~depressed~~ oil prices were to ~~persist~~significantly decline and remain weak through 2021 and longer, ~~as currently predicted by the forward curve for oil,~~ we may not be able to continue to generate the same level of Levered Free Cash Flow we are currently generating and our liquidity and capital resources may not be sufficient to conduct our business and operations ~~in the longer term~~ until commodity prices recover. ~~In light of continuing uncertainty, negative commodity price outlook, and significant risks mentioned above and further discussed elsewhere in this report (including under~~Please see Part II, Item ~~1.A.~~1A “Risk Factors”~~), we continue to plan~~ for a ~~prolonged downturn and~~discussion of known material risks, many of which are beyond our strategy to survive is focused on preserving cash, reducing costs and maintaining business continuity. We have significantly reduced our initially planned 2020 capital expenditures and non-employee operating and general and administrative expenses and we are focused on achieving additional cost reductions and improving operational efficiencies. We also temporarily suspended our quarterly cash dividend, starting with the second quarter of 2020, and year-to-date we have not repurchased any common stock under our authorized share repurchase program. As mentioned above, we enhanced our hedge positions for 2020, and to a lesser extent for 2021. Depending on the timing and rate of the eventual recovery and our outlook, we may potentially use Levered Free Cash Flow to opportunistically repurchase our bonds to strengthen our balance sheet to withstand an extended low commodity price environment, to explore accretive acquisitionscontrol, that would strengthen our asset base or to fund our 2021 capital expenditures in the event there is a shortfall next year. Although we continue to actively work to mitigate the evolving challenges of this severe industry downturn on our operations, our financial condition and our employees and contractors, there is no certainty that the measures we take will ultimately be sufficient. We are unable to reasonably predict when, or to what extent, commodity prices and the overall markets and global economy will stabilize, and the pace of any subsequent

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~~recovery for the oil and gas industry. Further, to what extent these events do ultimately~~could adversely impact our business, liquidity, financial condition, and results of ~~operations is highly uncertain and dependent on numerous evolving factors that cannot be predicted, including the severity and duration of the COVID-19 pandemic and future actions by OPEC+.~~operations.

The RBL Facility

On July 31, 2017, we entered into a credit agreement ~~providing~~that provided for a revolving loan with up to $1.5 billion of ~~commitments,~~commitment, subject to a reserve borrowing base (“RBL Facility”)~~, which is further discussed in Note 2, Debt, in~~. The RBL Facility provides a letter of credit subfacility for the ~~Notes to the Condensed Consolidated Financial Statements in Part I, Item 1~~issuance of this report. On June 23, 2020, we completed the regular Spring borrowing base redetermination and entered into Limited Waiver and Amendment No. 5 to Credit Agreement (the “Amendment”), with the lenders which, among other changes to the credit agreement described in the Amendment, (1) decreases the borrowing base to $200 million; (2) decreases the elected commitment to $200 million; (3) limits the maximum borrowing availability to $150 million until the next semi-annual borrowing base redetermination which is scheduled to occur in November 2020 at which time we expect the availability to return to this elected commitment amount; (4) implements certain anti-cash hoarding provisions, including the requirement to repay outstanding loans on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $30 million; (5) waives certain events of default arising from the failure to timely deliver certain hedging reports; and (6) further limits dividends and share repurchases. As of September 30, 2020 we had no borrowings outstanding, approximately $7 million in letters of credit ~~outstanding, and approximately $143 million available~~in an aggregate amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing availability for ~~borrowing~~revolving loans under the RBL ~~Facility.~~Facility on a dollar for dollar basis. Borrowing base redeterminations generally become effective each May and November, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations. The RBL Facility has an elected commitment feature that allows us to increase commitments to the amount of our borrowing base with lender approval. In April 2021, we completed our scheduled semi-annual borrowing base redetermination under our RBL Facility, which resulted in a reaffirmed borrowing base and the Company's elected commitment at $200 million with no further borrowing restrictions beyond the covenants noted below.

The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. The RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a Leverage Ratio of no more than 4.0 to 1.0 and (ii) a Current Ratio of at least 1.0 to 1.0. The RBL Facility also contains customary restrictions. As of September 30, 2020, our Leverage Ratio and Current Ratio were 1.5 to 1.0 and 2.7 to 1.0, respectively. In addition, the RBL Facility currently provides that to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights and remedies, including foreclosure on all of the collateral. The RBL Facility contains certain anti-cash hoarding provisions, including the requirement to repay outstanding loans on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $30 million; and further limits to dividends and share repurchases. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.

The RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a Leverage Ratio of no more than 4.0 to 1.0 and (ii) a Current Ratio of at least 1.0 to 1.0. The RBL Facility also contains customary restrictions. As of June 30, 2021, our Leverage Ratio and Current Ratio were 2.1 to 1.0 and 2.2 to 1.0, respectively. In addition, the RBL Facility currently provides that to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. We were in compliance with all financial covenants under the RBL Facility as of ~~September~~June 30, ~~2020.~~2021.

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Hedging

We have protected ~~substantially all~~a significant portion of our anticipated cash flows in ~~2020,~~2021, as well as a ~~significant~~ portion in ~~2021,~~2022, using our commodity hedging program, including ~~through~~ fixed-price derivative contracts. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge gas purchases to protect against price increases. Our generally low-decline production base, coupled with our stable operating cost environment, affords an ability to hedge a material amount of our future expected production. We expect our operations to generate sufficient cash flows at current commodity prices including our ~~2020~~2021 and ~~2021~~2022 hedging positions. For information regarding risks related to our hedging program, see “Item 1A. Risk Factors—Risks Related to Our ~~Business~~Operations and Industry” in our Annual Report.

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As of ~~September~~June 30, ~~2020,~~2021, we had the following crude oil production and gas purchases hedges.

Q4 2020 1H 2021 2H 2021
Fixed Price Oil Swaps (Brent):
  Hedged volume (MBbls) 2,208 3,438 2,084
  Weighted-average price ($/Bbl) $ 59.85 $ 45.82 $ 46.17
Purchased Oil Calls Options (Brent):
Hedged volume (MBbls) 276 — —
Weighted-average price ($/Bbl) $ 65.00 $ — $ —
Fixed Price Gas Purchase Swaps (Kern, Delivered):
  Hedged volume (MMBtu) 5,060,000 9,045,000 5,535,000
  Weighted-average price ($/MMBtu) $ 2.76 $ 2.71 $ 2.73
Fixed Price Gas Purchase Swaps (SoCal Citygate):
  Hedged volume (MMBtu) 155,000 — —
  Weighted-average price ($/MMBtu) $ 3.80 $ — $ —


	Q3 2021		Q4 2021		FY 2022




Fixed Price Oil Swaps (Brent):
Hedged volume (mbbls)	1,318		1,318		1,095
Weighted-average price ($/bbl)	$	48.66	$	48.66	$	60.00










Fixed Price Gas Purchase Swaps (Kern, Delivered):
Hedged volume (mmbtu)	4,830,000		2,085,000		—
Weighted-average price ($/mmbtu)	$	2.83	$	2.95	$	—

~~In October 2020,~~As of June 30, 2021 we ~~added~~also had open swap positions that are excluded from the table above where we are both buyer and seller of equal notional volumes of 12,500 ~~MMBtu/~~mmbtu/d of fixed price gas sales swaps ~~at an average price of $2.96,~~each indexed to Northwest Pipeline Rocky Mountains and CIG, for the period ~~January~~July 1, 2021 through December 31, 2021. These swap positions effectively cancel each other while resulting in a mark-to-market gain of $1 million. This gain will be cash settled in 2021 as the positions expire.

The following table summarizes the historical results of our hedging activities.


		Three Months Ended						Nine Months Ended					Three Months Ended						Six Months Ended
		September 30, 2020		June 30, 2020		September 30, 2019		September 30, 2020		September 30, 2019			June 30, 2021		March 31, 2021		June 30, 2020		June 30, 2021		June 30, 2020
Crude Oil (per Bbl):
Crude Oil (per bbl):												Crude Oil (per bbl):
Realized sales price, before the effects of derivative settlements	Realized sales price, before the effects of derivative settlements	$	39.88	$	28.98	$	57.92	$	39.00	$	58.79	Realized sales price, before the effects of derivative settlements	$	64.72	$	56.89	$	28.98	$	60.83	$	38.59
Effects of derivative settlements	Effects of derivative settlements	$	16.28	$	25.42	$	7.31	$	16.97	$	4.30	Effects of derivative settlements	$	(18.33)	$	(12.08)	$	25.42	$	(15.22)	$	17.30
Oil with hedges ($/Bbl)		$	56.16	$	54.40	$	65.23	$	55.97	$	63.09
Purchased Natural Gas (per MMBtu):
Oil with hedges ($/bbl)												Oil with hedges ($/bbl)	$	46.39	$	44.81	$	54.40	$	45.61	$	55.89
Purchased Natural Gas (per mmbtu):												Purchased Natural Gas (per mmbtu):
Purchase price, before the effects of derivative settlements	Purchase price, before the effects of derivative settlements	$	2.69	$	1.74	$	2.67	$	2.25	$	3.17	Purchase price, before the effects of derivative settlements	$	3.31	$	6.93	$	1.74	$	5.08	$	2.05
Effects of derivative settlements	Effects of derivative settlements	$	0.10	$	1.11	$	0.30	$	0.60	$	0.09	Effects of derivative settlements	$	(0.31)	$	(4.51)	$	1.11	$	(2.36)	$	0.84
Purchased Natural Gas with hedges	Purchased Natural Gas with hedges	$	2.79	$	2.85	$	2.97	$	2.85	$	3.26	Purchased Natural Gas with hedges	$	3.00	$	2.42	$	2.85	$	2.72	$	2.89

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Pipeline Commitments

We recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that will reduce our exposure to fuel gas purchase price fluctuations. These capacity agreements are for approximately 10,000 mmbtu/d beginning October 2021 through October 2036 and approximately 5,500 mmbtu/d beginning November 2021 through December 2024 for a total commitment of $32 million.

Cash Dividends

Our Board of Directors approved ~~$0.12~~a regular cash dividend of $0.04 per share ~~quarterly~~on our common stock for the first and second quarters of 2021. We paid the first and the second quarter cash dividend in April and July 2021, respectively. The Board of Directors approved a $0.06 per share regular cash dividend on our common stock for the ~~first~~third quarter of ~~2020,~~2021, which weis expected to be paid in ~~April 2020. In April 2020, in connection with the current low oil price environment, we temporarily suspended our quarterly dividend until oil prices recover.~~October 2021. As of ~~October~~July 31, ~~2020,~~2021, the Company has paid approximately ~~$65~~$72 million in dividends since the inception of ~~its~~our dividend program following our IPO in the third quarter of 2018. This represents a 65% return of capital from our IPO.

Stock Repurchase Program

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Directors authorized the repurchase of the remaining $50 million of our $100 million repurchase program. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes. ~~The Company~~We have not repurchased ~~a total of 5,057,682~~any shares under the stock repurchase program ~~for approximately $50 million as of December 31,~~since 2019. ~~For the nine months ended September 30, 2020, we did not repurchase any shares under the stock repurchase program.~~

Bond Repurchase Program

Corporate Organization

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Statements of Cash Flows

The following is a comparative cash flow summary:


		Nine Months Ended September 30,						Six Months Ended June 30,
		2020		2019				2021		2020
		(in thousands)				(in thousands)
Net cash:	Net cash:						Net cash:
Provided by operating activities	Provided by operating activities	$	144,419	$	164,267		Provided by operating activities	$	59,859	$	86,422
Used in investing activities	Used in investing activities	(74,522)		(176,138)			Used in investing activities	(60,512)		(65,518)
Used in financing activities	Used in financing activities	(22,277)		(56,809)			Used in financing activities	(4,986)		(20,904)
Net increase (decrease) in cash and cash equivalents	Net increase (decrease) in cash and cash equivalents	$	47,620	$	(68,680)		Net increase (decrease) in cash and cash equivalents	$	(5,639)	$	—

Operating Activities

Cash provided by operating activities decreased for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 by approximately ~~$20~~$27 million when compared to the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, due to ~~decreased sales~~a $149 million change in derivatives settlements which consisted of ~~$129~~$66 million of oil derivatives settlements paid in the six months ended June 30, 2021 and ~~increased general and administrative expenses~~$83 million of ~~$6 million. These decreases were partially offset by increased~~oil derivatives settlements received ~~of $80 million, decreased lease operating expenses~~in the six months ended June 30, 2020 and ~~electricity generation expenses of $24 million, decreased~~an increase in taxes, other than income taxes of $4$6 million. These cash decreases were mostly offset by increased sales of $99 million, a decrease in operating expense of $18 million, a decrease in general and administrative expense of $2 million and working capital changes and other of $7$9 million.

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Investing Activities

The following provides a comparative summary of cash flows from investing activities:

Nine Months Ended
September 30,
2020 2019
(in thousands)
Capital expenditures:(1)
Development of oil and natural gas properties $ (58,370) $ (157,281)
Purchase of other property and equipment (3,951) (12,394)
Changes in capital investment accruals (10,347) (4,613)
Acquisition of properties and equipment and other (2,104) (2,819)
Proceeds from sale of properties and equipment and other 250 969
Cash used in investing activities $ (74,522) $ (176,138)

~~__________~~

~~(1) Based on actual cash payments rather than accruals.~~



	Six Months Ended June 30,
	2021		2020
	(in thousands)
Capital expenditures:
Capital expenditures	$	(67,030)	$	(56,403)

Changes in capital expenditures accruals	6,934		(7,256)

Acquisition of properties and equipment and other	(825)		(2,076)
Proceeds from sale of properties and equipment and other	409		217

Cash used in investing activities	$	(60,512)	$	(65,518)

Cash used in investing activities decreased ~~$102~~$5 million for the ~~nine~~six months ended ~~September~~June 30, ~~2020~~2021 when compared to the same period in ~~2019,~~2020, primarily due to a decrease in cash used for capital ~~spending in accordance with the revised 2020 capital budget.~~spending. In 2021, we have reinstated our development program, albeit at a lower level than we began 2020.

Financing Activities

Cash used by financing activities ~~was approximately $22~~decreased $16 million for the ~~nine~~six months ended ~~September~~June 30, 2020 and decreased by approximately $35 million from the nine months ended September 30, 2019. The decrease is largely due to treasury stock purchases of $36 million in the nine months ended September 30, 2019 and none in the nine months ended September 30, 2020. Additionally, we paid fewer dividends in 2020 by approximately $10 million. Partially offsetting the positive cash impact of these activities, we reduced our net borrowings by approximately $12 million on the RBL Facility in 20202021 when compared to ~~2019.~~the same period in 2020. In 2021, the cash used was primarily for dividends paid of $3 million. In 2020, the cash used was primarily for dividends paid of $19 million.

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Balance Sheet Analysis

The changes in our balance sheet from December 31, ~~2019~~2020 to ~~September~~June 30, ~~2020~~2021 are discussed below.


		September 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
		(in thousands)					(in thousands)
Cash and cash equivalents	Cash and cash equivalents	$	47,620	$	—	Cash and cash equivalents	$	74,918	$	80,557
Accounts receivable, net	Accounts receivable, net	$	48,798	$	71,867	Accounts receivable, net	$	63,740	$	52,027
Derivative instruments assets - current and long-term	Derivative instruments assets - current and long-term	$	59,669	$	9,691	Derivative instruments assets - current and long-term	$	11,515	$	2,507

Other current assets	Other current assets	$	20,318	$	19,399	Other current assets	$	26,890	$	19,400
Property, plant & equipment, net	Property, plant & equipment, net	$	1,260,755	$	1,576,267	Property, plant & equipment, net	$	1,262,417	$	1,258,084
Other non-current assets		$	9,297	$	12,974
Accounts payable and accrued liabilities		$	95,237	$	151,811
Other noncurrent assets						Other noncurrent assets	$	5,035	$	7,235
Accounts payable and accrued expenses						Accounts payable and accrued expenses	$	160,586	$	151,985
Derivative instruments liabilities - current and long-term	Derivative instruments liabilities - current and long-term	$	1,516	$	4,958	Derivative instruments liabilities - current and long-term	$	65,534	$	23,321

Long-term debt	Long-term debt	$	393,219	$	394,319	Long-term debt	$	394,009	$	393,480
Deferred income taxes liability - long-term	Deferred income taxes liability - long-term	$	9,318	$	9,057	Deferred income taxes liability - long-term	$	538	$	1,011
Asset retirement obligation - long-term		$	136,392	$	124,019
Other non-current liabilities		$	36,150	$	33,586
Equity		$	774,625	$	972,448
Asset retirement obligations - long-term						Asset retirement obligations - long-term	$	139,181	$	135,192
Other noncurrent liabilities						Other noncurrent liabilities	$	6,009	$	785
Stockholders’ equity						Stockholders’ equity	$	678,658	$	714,036

See ~~"Liquidity~~“—Liquidity and Capital ~~Resources"~~Resources” for discussions about the changes in cash and cash equivalents.

The ~~$23~~$12 million ~~decrease~~increase in accounts receivable was driven ~~mostly~~ by ~~lower~~$20 million higher sales ~~both price and volume~~ period-over-period, partially offset by ~~higher~~$8 million lower hedge settlements outstanding at each period-end.

The ~~$53~~$33 million increase in net derivative ~~assets and~~ liabilities ~~reflected~~is due to the change from a net ~~appreciation~~liability of $21 million at December 31, 2020 to a net liability of $54 million as of June 30, 2021. Changes to mark-to-market derivative values at the end of each period result from differences in the ~~mark-to-market values of the derivatives, lower~~ forward curve prices relative to the contract fixed ~~price, at the end of each period presented, as well as the change~~prices, changes in positions held ~~at the end of each period~~ and ~~the~~ settlements received and paid throughout the periods.

The ~~$316~~$7 million increase in other current assets was primarily due to $8 million of prepayments for development permits and other prepaid fees, partially offset by a decrease in materials inventory of $1 million.

The $4 million increase in property, plant and equipment was ~~largely~~primarily the result of ~~the $289~~$68 million ~~impairment on our oil and gas properties~~ in ~~the first quarter of 2020, as well as~~capital investments partially offset by depreciation expense of ~~$101 million, partially offset by capital investments of $61 million, $6 million of acquisitions and capitalized interest and $6 million for asset retirement obligations.~~$64 million.

The $4$2 million decrease in other ~~non-current~~noncurrent assets ~~is mainly~~was primarily due to deferred debt issuance cost amortization.

The ~~$57~~$9 million ~~decrease~~increase in accounts payable and accrued ~~liabilities~~expenses included approximately ~~$21~~$14 million of ~~decreased accruals~~increased derivative settlement payables, $6 million increase in capital, a $3 million increase for dividends accrued and ~~spending for various capital and operating costs due to the reduced level of these costs~~a $2 million increase in ~~2020, $13 million fewer~~ royalties accrued due to ~~decreased sales, $12~~increased sales. The increases were partially offset by a $6 million ~~reclassified from~~decrease in the current ~~to long-term~~ portion of the greenhouse gas liability, a $5 million decrease due to a reclass in current asset retirement ~~obligation based on budgeted spending and regulatory requirements, and the $10~~obligations from short term to long term, as well as a $5 million ~~impact~~decrease due to bonus payments, net of ~~dividends accrued at the end of 2019 with no corresponding accrual at September 30, 2020.~~accruals added.

The increase ~~in long-term deferred income taxes liability is due to the income tax expense and change in current portion due during the period.~~

~~The $12~~of $4 million ~~increase~~ in the long-term portion of the asset retirement ~~obligation~~obligations from ~~$124~~$135 million at December 31, ~~2019~~2020 to ~~$136~~$139 million at ~~September~~June 30, ~~2020~~2021 was due to $7$5 million of accretion $6and $1 million of liabilities incurred and ~~$12~~reclassification of $5 million ~~of reclassification~~ from ~~the~~ current to long-term portion due to changes in ~~budgeted~~anticipated spending and regulatory requirements. These increases were partially offset by ~~$12~~$7 million of liabilities settled during the period.

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The $5 million increase in other ~~non-current~~noncurrent liabilities was driven by ~~higher~~additional non-current greenhouse gas liabilities ~~as a result~~in the first quarter of ~~periodic emissions and slight price increases. This liability is due for payment more than one~~2021 compared to year ~~from September 30, 2020.~~end. At year-end 2020 the non-current portion of greenhouse gas liabilities was moved to current.

The $35 million decrease in stockholders’ equity ~~of $198 million~~ was due to the net loss of ~~$199~~$34 million, ~~and $10~~$7 million of common stock dividends ~~declared.~~declared and $1 million of shares withheld for payment of taxes on equity awards. These decreases were partially offset by ~~$11~~$7 million of stock-based ~~incentive~~ equity awards, net of taxes.

Lawsuits, Claims, Commitments, and Contingencies

In the normal course of business, we, or our subsidiary, are the subject of, or party to, pending or threatened legal proceedings, contingencies and commitments involving a variety of matters that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, fines and penalties, remediation costs, or injunctive or declaratory relief.

Securities Litigation Matter

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Contractual Obligations

The following is a summary of our commitments and contractual obligations as of ~~September~~June 30, ~~2020:~~2021:

Payments Due
Total Less Than 1 Year 1-3
Years 3-5
Years Thereafter
(in thousands)
Debt obligations:
RBL Facility $ — $ — $ — $ — $ —
2026 Notes 400,000 — — — 400,000
Interest(1)
150,529 28,000 56,000 56,000 10,529
Other:
Asset retirement obligations(2)
150,092 13,700 — — 136,392
Off-Balance Sheet arrangements:
Processing, transportation and storage contracts(3)
9,822 5,350 4,472 — —
Operating lease obligations 11,552 1,848 3,724 3,100 2,880
Other purchase obligations(4)
35,100 18,000 17,100 — —
Total contractual obligations $ 757,095 $ 66,898 $ 81,296 $ 59,100 $ 549,801


	Payments Due
	Total		Less Than 1 Year		1-3 Years		3-5 Years		Thereafter
	(in thousands)







Off-Balance Sheet arrangements:
Processing and transportation contracts(1)	$	37,280	$	4,954	$	8,423	$	4,317	$	19,586
Operating lease obligations	10,356		2,048		3,491		3,103		1,714
Other purchase obligations(2)	32,100		15,000		17,100		—		—
Total contractual obligations	$	79,736	$	22,002	$	29,014	$	7,420	$	21,300

__________

(1) ~~Represents interest on the 2026 Notes computed at 7.0% through contractual maturity in 2026.~~

(2) Represents the estimated future asset retirement obligations on a discounted basis. We do not show the long-term asset retirement obligations by year as we are not able to precisely predict the timing of these amounts. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to revisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See Note 6 for additional information.

~~(3)~~ Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure transportation of our natural gas production to market, as well as, pipeline ~~processing~~ and ~~storage capacity.~~processing.

~~(4) We have certain commitments under contracts, including~~(2) Amounts include a purchase ~~commitments for goods and services. We previously had an obligation~~commitment of $6 million to ~~a counterparty in connection with our Piceance assets to either~~ build a road, ~~or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019,~~which is classified as current. Additionally, we fulfilled the obligation by delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of such access, which we dispute. We will defend the matter vigorously, however, given the uncertainty of litigation and the preliminary stage of the case, among other things, at this time we cannot estimate the reasonable possible loss, if any, that may result from this action. We currently have a drilling commitment in California, for which we are required to drill 97 wells with an estimated total cost of $29 million by ~~August 2022~~April 2023. As of June 30, 2021 we have drilled 10 wells and ~~40 of those wells~~ are required to ~~be drilled~~drill 30 additional wells estimated at $9 million by ~~July~~the end of December 2021.

Critical Accounting Policies and Estimates

See Note 1, Basis of Presentation, in the Notes to Consolidated Condensed Financial Statements in Part I, Item 1 of this Form ~~10-Q.~~10-Q and Part II, Item 7 “Critical Accounting Policies and Estimates” in the Annual Report on Form 10-K.

Cautionary Note Regarding Forward-Looking Statements

The information included or incorporated by reference in this Quarterly Report includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and objectives for operations, capital for sustained production levels, expected production and costs, reserves, hedging activities, capital expenditures, return of capital, improvement of recovery factors and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal,

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guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect us are discussed below in Part II, Item 1A. “Risk Factors” in this Quarterly Report, as well as in Part I, Item 1A. “Risk Factors” our most recent Annual Report on Form 10-K and other filings with the Securities and Exchange Commission.

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Factors (but not all the factors) that could cause results to differ include among others:

•the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government activities, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;

•the length, scope and severity of the ongoing COVID-19 pandemic, including the effects of related public health concerns and the impact of actions taken by governmental authorities and other third parties in response to the pandemic and its impact on commodity prices, supply and demand considerations, and storage capacity;

•global economic trends, geopolitical risks and general economic and industry conditions, such as those resulting from the COVID-19 pandemic and from the actions of foreign producers, importantly including OPEC+ and changes in OPEC+'s production levels;

•volatility of oil, natural gas and NGL prices, including the sharp decline in crude oil ~~prices that occurred in the first quarter and second quarter of 2020;~~

•the California and global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues, the transition to a low-emission economy and the expected role of different energy sources;

•supply of and demand for oil, natural gas and NGLs;

•disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver our oil and natural gas and other processing and transportation considerations;

•inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures, meet our working capital requirements or fund planned investments;

•price fluctuations and availability of natural gas and electricity and the cost of steam;

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

•the regulatory environment, including availability or timing of, and conditions imposed on, obtaining and/or maintaining permits and approvals, including those necessary for drilling and/or development projects;

•our ability to meet our planned drilling schedule, including due to our ability to obtain permits on a timely basis or at all, and to successfully drill wells that produce oil and natural gas in commercially viable quantities;

•concerns about climate change and other air quality issues;

•uncertainties associated with estimating proved reserves and related future cash flows;

•our ability to replace our reserves through exploration and development activities;

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•drilling and production results, including lower–than–expected production, reserves or resources from development projects or higher–than–expected decline rates;

•our ability to obtain timely and available drilling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating wells;

•changes in tax laws;

•effects of competition;

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•uncertainties and liabilities associated with acquired and divested assets;

•our ability to make acquisitions and successfully integrate any acquired businesses;

•market fluctuations in electricity prices and the cost of steam;

•asset impairments from commodity price declines;

•large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;

•geographical concentration of our operations;

•the creditworthiness and performance of our counterparties with respect to our hedges;

•impact of derivatives legislation affecting our ability to hedge;

•failure of risk management and ineffectiveness of internal controls;

•catastrophic events, including wildfires, earthquakes and pandemics;

•environmental risks and liabilities under federal, state, tribal and local laws and regulations (including remedial actions);

•potential liability resulting from pending or future litigation;

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

•information technology failures or cyber attacks; and

•governmental actions and political conditions, as well as the actions by other third parties that are beyond our control.

Except as required by law, we undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

~~For the three months ended September~~As of June 30, ~~2020,~~2021, there ~~were~~have been no material changes in the information required to be provided under Item 305 of Regulation S-K included under the caption Management’s Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A)- Quantitative and Qualitative Disclosures About Market Risk, in the ~~2019~~2020 Annual Report, except as discussed below.

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Price Risk

Our most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues, certain costs such as fuel gas, and cash flows are likewise affected. Additional non-cash impairment charges for our oil and gas properties may be required if commodity prices experience ~~further~~ significant declines.

We have hedged a large portion of our expected crude oil production and our natural gas purchase requirements to reduce exposure to fluctuations in commodity prices. We use derivatives such as swaps, calls and puts to hedge. We do not enter into derivative contracts for speculative trading purposes and we have not accounted for our

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derivatives as cash-flow or fair-value hedges. We continuously consider the level of our oil production and gas purchases that is appropriate to hedge based on a variety of factors, including, among other things, current and future expected commodity prices, our expected capital and operating costs, our overall risk profile, including leverage, size and scale, as well as any requirements for, or restrictions on, levels of hedging contained in any credit facility or other debt instrument applicable at the time.

We determine the fair value of our oil and gas sales and natural gas purchase derivatives using valuation techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We validate data provided by third parties by understanding the valuation inputs used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. At ~~September~~June 30, ~~2020,~~2021, the fair value of our hedge positions was a net ~~asset~~liability of approximately ~~$58~~$54 million. A 10% increase in the oil and natural gas index prices above the ~~September~~June 30, ~~2020~~2021 prices would result in a ~~decrease in the~~ net ~~asset to~~liability of approximately ~~$42~~$87 million; conversely, a 10% decrease in the oil and natural gas index prices below the ~~September~~June 30, ~~2020~~2021 prices would result in ~~an increase in the~~a net ~~asset to~~liability of approximately ~~$99~~$39 million. For additional information about derivative activity, see Note 3, Derivatives, in the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this report.

Actual gains or losses recognized related to our derivative contracts depend exclusively on the price of the underlying commodities on the specified settlement dates provided by the derivative contracts.

~~Credit Risk~~

~~Our credit risk relates primarily~~ Additionally, we cannot be assured that our counterparties will be able to trade receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. For derivative instruments entered into as part of our hedging program, we are subject to counterparty credit risk to the extent the counterparty is unable to meet its settlement commitments. We actively manage this credit risk by selecting counterparties that we believe to be financially strong and continue to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

~~As of September 30, 2020, the substantial majority of the credit exposure related to~~perform under our derivative ~~financial instruments was with investment grade counterparties. We believe exposure~~contracts. If a counterparty fails to ~~credit-related losses at September 30, 2020 was not material~~perform and ~~actual losses associated with credit risk have not been material for all periods presented.~~

~~Interest Rate Risk~~

~~Our RBL Facility has a variable interest rate on outstanding balances. As of September 30, 2020, we had no borrowings under~~the derivative arrangement is terminated, our RBL Facility and thus the interest rate risk exposure is not material. The 2026 Notes have a fixed interest rate and thus we are not exposed to interest rate risk on these instruments. See Note 2, Debt, in the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this report for additional information regarding interest rates on our outstanding debt.

cash flows could be negatively impacted.

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Item 4. Controls and Procedures

Our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, they each concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2020.~~2021.

There were no changes in the Company’s internal control over financial reporting during the ~~third~~second quarter of ~~2020~~2021 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II – Other Information

Item 1. Legal Proceedings

We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

Securities Litigation Matter

On November, 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class action lawsuit (the “Torres Lawsuit”) in the United States District Court for the Northern District of Texas against Berry Corp. and certain of its current and former directors and officers, including our Board Chair and Chief Executive Officer Trem Smith and Chief Financial Officer and Board member Cary Baetz (collectively, the “Defendants”). The complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933, and Sections 10(b) and 20(a) of the Exchange Act of 1934, on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock pursuant and/or traceable to the Company’s initial public offering (“IPO”); or (ii) Berry Corp.'s securities between July 26, 2018 and November 3, 2020 (the “Class Period”). In particular, the complaint alleges that the Defendants made false and misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined following release of its financial results for the third quarter of 2020 on November 3, 2020. The complaint does not quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these alleged securities violations, as well as attorneys’ fees and costs.

Other Matters.

For additional information regarding legal proceedings, see Note 4 to the condensed consolidated financial statements in Part I of this Form 10-Q and Note 5 to our consolidated financial statements for the year ended December 31, ~~2019~~2020 included in the Annual Report.

Item 1A. Risk Factors

~~In addition~~We are subject to ~~factors noted~~various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading “Item 1A. Risk Factors” in our most recent Annual ~~Report, additional factors that may impact our financial and operational results, include the following:~~

~~Attempts by several states to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels within the state.~~

Recently, California and Colorado, have taken several actions that could adversely impact oil and gas production in those states. On September 23, 2020, Governor Gavin Newsom of California issued an executive order (the "Order") that seeks to reduce both the supply of and demand for fossil fuels in the state. The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: phasing out the sale of emissions-producing vehicles; developing strategies for the closure and repurposing of oil & gas facilities in California; and ending the issuance of new hydraulic fracturing permits in the state by 2024. The Order also directs CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly strengthened regulations, which may include setbacks, to address these concerns by December 31, 2020. Any of these developments may adversely impact both demand for our products or production from our properties.

While the Order does not impose a ban on the issuance of hydraulic fracturing permits, Governor Newsom has announced plans to ask the legislature to pass legislation to this effect. While several California legislators have already indicated that they intend to propose such a ban, the ultimate outcome of any proposed legislation remains uncertain at this time, as past measures to further impose additional stringent requirements upon oil and gas activities in the California legislature were not successful. For example, in both 2019 and 2020, California considered legislation to impose a statewide setback distance between certain oil and natural gas operations and residences, schools, and healthcare facilities. However, in both cases, the proposal failed to receive the approval of the California State Senate.

Separately, in September 2020, the Colorado Oil and Gas Conservation Commission (“COGCC”) announced that it will consider imposing a 2,000-foot setback requirement for drilling and fracking operations statewide, allowing for variances subject to certain conditions. The vote on this rulemaking is expected to take place at the COGCC’s November 6, 2020 meeting. While we cannot predict the final outcome of the COGCC’s actions, any regulation restricting the siting of oil and gas facilities or otherwise imposing more stringent operating controls may adversely impact production from our properties.

The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our operations and financial condition will depend on future developments, which are highly uncertain and cannot be predicted.

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19. This pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. This resulted in a significant reduction in demand for and prices of crude oil, natural gas and NGL, which was compounded by the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire on August 1, 2020.Report.

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In mid-April 2020, members of OPEC+ agreed to certain production cuts; however, these cuts only slightly offset the significant decrease in demand resulting from the COVID-19 pandemic and related economic repercussions. During the second quarter of 2020, the price of Brent crude oil reached historic low of just under $20 per barrel. Although pricing has strengthened slightly, it is still lower than pre-pandemic levels and the current futures forward curve for Brent crude indicates that prices are expected to continue at low levels for an extended time. As of November 1, 2020, the benchmark Brent oil price was $37.46 per barrel as compared to the average benchmark Brent oil price of $63.15 per barrel used to determine our 2019 year end reserves based on SEC pricing.

Additionally, although the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. During the second quarter of 2020, we experienced an adverse widening in the price differential between Brent and California crude due to the lack of local demand and storage capacity. This differential widening improved in the third quarter 2020 as the market storage concerns began to soften, however, if California pricing remains weak, or declines, our financial and operating results will be adversely affected.

If the reduced demand for, and prices of, crude oil and NGLs continue for a prolonged period, our operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to our properties may be materially and adversely affected. At the end of March 2020, the Company reduced its planned capital expenditures by more than 50%, which negatively impacted production during the second and third quarters 2020 and may negatively impact future production levels due to the natural production decline of our assets. This, combined with expected lower commodity prices, could materially adversely affect our cash flows and the quantity and value of estimated proved reserves that may be attributed to our properties. A persistent price decline could adversely affect the economics of our existing wells and planned future wells, result in additional impairment charges to existing properties and cause us to delay or abandon planned drilling operations as uneconomical.

Our operations also may be adversely affected if significant portions of our workforce - and that of our customers and suppliers - are unable to work effectively, including because of illness, quarantines, government actions, or other restrictions in connection with the pandemic. Over the later part of March, we implemented workplace restrictions in response to developing government directives and we are continuing to monitor national, state and local government directives where we have operations and/or offices. For several months, most of our personnel worked remotely and many of our key vendors, service suppliers and partners have been as well. Although we managed the transition to temporary work from home arrangements and subsequent office re-openings without a significant loss in business continuity, we incurred additional costs and experienced some inefficiencies during the second and third quarters 2020 as a result. If the ongoing outbreak were to worsen, and additional restrictions be implemented, we may again have to consider remote work arrangements, and certain operational and other business processes could slow which may result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies, any of which could adversely affect our operating results for as long as the current pandemic persists and potentially for some time after the pandemic subsides.

The extent to which the COVID-19 pandemic adversely affects our business, results of operations, and financial condition will depend on future developments, which are highly uncertain and cannot be predicted, including the scope and duration of the pandemic and actions taken by governmental authorities and other third parties in response to the pandemic.

Our ability to operate profitably and our financial condition are highly dependent on energy prices. The outbreak of COVID-19 followed by certain actions taken by OPEC+ caused crude oil prices to decline significantly beginning in the first quarter of 2020 and prices have remained weak and below pre-pandemic levels. If oil prices continue to decline or remain at current levels for a prolonged period, our business, financial condition and results of operations may be materially and adversely affected.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to

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wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been extremely volatile and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

•changes in global supply and demand for oil and natural gas, including changes in demand resulting from general and specific economic conditions relating to the business cycle and other factors (e.g., global health epidemics such as the recent COVID-19 pandemic);

•~~the actions of OPEC / OPEC+;~~

•~~the price and quantity of imports of foreign oil and natural gas;~~

•~~political conditions, including embargoes, in or affecting other oil-producing activity;~~

•~~the level of global oil and natural gas exploration and production activity~~

•~~the level of global oil and natural gas inventories;~~

•~~weather conditions;~~

•~~technological advances affecting energy consumption; and~~

•~~the price and availability of alternative fuels.~~

Global economic growth drives demand for energy from all sources, including fossil fuels. Historically, when the U.S. and global economies experience weakness, demand for energy has declined. Similarly, should growth in global energy production outstrip demand, excess supplies may arise. Declines in demand and excess supplies may result in accompanying declines in commodity prices and deterioration of our financial position along with our ability to operate profitably and our ability to obtain financing to support operations.

In the first quarter of 2020, crude oil prices fell sharply and dramatically, due in part to significantly decreased demand as a result of the COVID-19 pandemic coupled with the increase in supply from the actions of OPEC+. On June 6, 2020, members of OPEC+ agreed to certain production cuts, which slightly offset the decrease in demand resulting from the COVID-19 pandemic. In August 2020, these production cuts were eased slightly and the current output reduction levels are expected to remain through the end of the year.

During the second and third quarters 2020, oil prices recovered slightly from the historical low levels at the beginning of the second quarter as global demand began to increase gradually with containment of the COVID-19 outbreak in areas around the globe and the supply surge was curtailed as members of OPEC+ agreed to certain production cuts. This recovery appears fragile and has flattened, with oil price volatility remaining elevated and oil demand remaining below pre-COVID-19 pandemic levels. Demand, and pricing, may again decline due to the ongoing COVID-19 pandemic, particularly if there is a resurgence of the outbreak during the latter part of the year as some are predicting, although the extent of the additional impact on our industry and our business cannot be reasonably predicted at this time. If storage availability also becomes further constrained, Brent and/or California oil prices may go materially lower and could potentially even become negative as WTI oil prices did on April 20, 2020. If crude oil prices continue to decline or remain at current levels for a prolonged period, our operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to our properties may be materially and adversely affected.

Additionally, although the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. Even as Brent pricing fell during the second quarter 2020, we experienced an adverse widening in the price differential between Brent and the California benchmark due to the lack of local demand and storage capacity. Although market conditions improved and the differential widening softened toward the end of the second quarter 2020, if California pricing remains weak, or declines, our financial and operating results will be adversely affected.

Past declines in prices reduced, and any declines that may occur in the future can be expected to reduce, our revenues and profitability as well as the value of our reserves. Such declines adversely affect well and reserve economics and may reduce the amount of oil and natural gas that we can produce economically, resulting in deferral or cancellation of planned drilling and related activities until such time, if ever, as economic conditions improve

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sufficiently to support such operations. Any extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

The marketability of our production is dependent upon transportation and storage facilities and other facilities, most of which we do not control, and the availability of such transportation and storage capabilities, which have been severely limited by recent market conditions related to the COVID-19 pandemic and the current oversupply of oil and natural gas. If additional facilities do not become available, or, even if such facilities are available, but we are unable to access such facilities on commercially reasonable terms, our operations will likely be interrupted, our production could be curtailed, and our revenues reduced, among other consequences.

The marketing of oil, natural gas and NGLs production depends in large part on the availability, proximity and capacity of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. Because of the significantly reduced demand for oil and natural gas as a result of the COVID-19 pandemic and the current oversupply of oil and natural gas in the market, available storage and transportation capacity for our production is limited and may become completely unavailable in the near future. Storage became scarce during the second quarter of 2020 due to the unprecedented dual impact of a severe global oil demand decline coupled with a substantial increase in supply. As traditional tanks filled, large quantities of oil were being stored in offshore tankers around the world, including off the coast of California. Where storage was available, such as offshore tankers, storage costs increased sharply. If the imbalance between supply and demand and the related shortage of storage capacity worsen, the prices we receive for our production could deteriorate and could potentially even become negative as WTI oil prices did on April 20, 2020.

During the second quarter of 2020, we obtained additional storage capacity to support our planned production for the remainder of the year and into 2021. As market conditions improved, we released a portion of the capacity. However, the risk remains that storage for oil may be unavailable and our existing capacity may be insufficient to support planned production rates in the event of demand for our oil deteriorating again or a supply surge or both. If we are unable to obtain additional storage capacity if needed, we could be forced to shut-in a significant amount of our California production, as well as curtail some of our Utah and Colorado production, which could have a material, adverse effect on our financial condition, liquidity and operational results. Whether and when we will have to reduce or shut-in production, and the extent and duration to which we may have to do so, cannot be reasonably predicted at this time. If we are forced to shut in production, we will incur additional costs to bring the associated wells back online. While production is shut in, we will likely incur additional costs and operating expenses to, among other things, maintain the health of the reservoirs, meet contractual obligations and protect our interests, but without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we have also shut-in steam injection for the associated reservoirs rather than incur those costs, the wells may not, initially or at all, come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state, our proved reserve estimates could be decreased and there could be potential additional impairments and associated charges to our earnings. A reduction in our reserves could also result in a reduction to our borrowing base under the RBL Facility and our liquidity. The ultimate significance of the impact of any production disruptions, including the extent of the adverse impact on our financial and operational results, will be dictated by the length of time that such disruptions continue which will, in turn, depend on the how long storage remains filled and unavailable to us, which is largely based on the lack of demand for our products due to the impact of the COVID-19 impact, the duration of which is currently unknowable.

In addition to the constraints we face due to storage capacity shortages, the volume of oil and natural gas that we can produce is subject to limitations resulting from pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, and physical damage to the gathering, transportation, storage, processing, fractionation, refining or export facilities that we utilize. The curtailments arising from these and similar circumstances may last from a few days to several months or longer and, in many cases, we may be provided only limited, if any, advance notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or any inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.

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We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations, which could adversely affect our net income and cash flows.

We currently have substantial U.S. federal and state net operating loss (“NOL”) carryforwards and U.S. federal general business credits (subject to change each quarter; as of December 31, 2019 estimated U.S. federal and state NOL carryforwards of approximately $122 million and $42 million, respectively, and U.S. federal general business credits of approximately $48 million). Our ability to use these tax attributes to reduce our future U.S. federal and state income tax obligations depends on many factors, including our future taxable income, which cannot be assured. In addition, our ability to use NOL carryforwards and other tax attributes may be subject to significant limitations under Section 382 and Section 383 of the Internal Revenue Code of 1986, as amended (the “Code”). Under those sections of the Code, if a corporation undergoes an “ownership change” (as defined in Section 382 of the Code), the corporation’s ability to use its pre-change NOL carryforwards and other tax attributes may be substantially limited.

Determining the limitations under Section 382 of the Code is technical and highly complex. A corporation generally will experience an ownership change if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. We may in the future undergo an ownership change under Section 382 of the Code. If an ownership change occurs, our ability to use our NOL carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations may be materially limited, which could adversely affect our net income and cash flows.

~~The payment of dividends will be at the discretion of our Board of Directors.~~

While we have regularly declared a quarterly dividend since our July 2018 IPO, including a dividend of $0.12 per share for the first quarter of 2020, the payment and amount of future dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deems relevant. Additionally, covenants contained in our RBL Facility and the indentures governing our 2026 Notes could limit the payment of dividends. In April 2020, in response to the unprecedented impact on our business from the significant decline in oil prices and the COVID-19 pandemic, we temporarily suspended our quarterly dividend until oil prices recover. We are under no obligation to make dividend payments on our common stock and cannot be certain when such payments may resume in the future.

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

Stock Repurchase Program

In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at ~~that~~the time, they authorized ~~initial~~ repurchases of up to $50 million under the program. The Company repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million in 2018 and 2019. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million of our $100 million repurchase program. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase shares during any period or at all. Any shares acquired will be available for general corporate purposes.

~~The Company~~ We have not repurchased ~~a total of 5,057,682~~any shares under the stock repurchase program ~~for approximately $50 million as of December 31,~~since 2019. ~~For the nine months ended September 30, 2020, we did not repurchase any shares under the stock repurchase program.~~

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Item 6. Exhibits


Exhibit Number						Description
3.1						Second Amended and Restated Certificate of Incorporation of Berry Petroleum Corporation (incorporated by reference to Exhibit 3.1 of Form 8-K filed February 19, 2020)
3.2						Third Amended and Restated Bylaws of Berry Corporation (bry) (incorporated by reference to Exhibit 3.2 of Form 8-K filed February 19, 2020)
3.3						Certificate of Designation of Series A Convertible Preferred Stock of Berry Petroleum Corporation (incorporated by reference to Exhibit 3.4 to the Company’s Registration Statement on Form S-1 (File No. 333-226011))
3.4						Certificate of Amendment to Certificate of Designation (incorporated by reference to Exhibit 3.1 of Form 8-K filed July 30, 2018)
~~10.1~~						~~Employment Agreement by and between Berry Petroleum Company, LLC and Fernandez Araujo, effective August 14, 2020~~ ~~(incorporated by reference to Exhibit 10.1 of Form 8-K filed August 20, 2020)~~
31.1*						Section 302 Certification of Chief Executive Officer
31.2*						Section 302 Certification of Chief Financial Officer
32.1*						Section 906 Certification of Chief Executive Officer and Chief Financial Officer
101.INS*						Inline XBRL Instance Document (the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
101.SCH*						Inline XBRL Taxonomy Extension Schema Document
101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Data Document
101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

__________

*(*) Filed herewith.

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GLOSSARY OF COMMONLY USED TERMS

The following are abbreviations and definitions of certain terms that may be used in this report, which are commonly used in the oil and natural gas industry:

“Absolute TSR” means absolute total stockholder return.

“AROs” means asset retirement obligations.

“Adjusted EBITDA” is a non-GAAP financial measure defined as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual ~~out-of-period~~ and infrequent ~~items, including gains and losses on sale of assets, restructuring costs and reorganization~~ items.

“Adjusted G&A” or “Adjusted General and Administrative Expenses” is a non-GAAP financial measure defined as general and administrative expenses adjusted for ~~restructuring and other non-recurring costs and~~ non-cash stock compensation ~~expense.~~expense, as well as unusual and infrequent costs.

“Adjusted Net Income (Loss)” is a non-GAAP financial measure defined as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual ~~out-of-period~~ and infrequent ~~items, including restructuring costs and reorganization~~ items, and the income tax expense or benefit of these adjustments using our effective tax rate.

“API” gravity means the relative density, expressed in degrees, of petroleum liquids based on a specific gravity scale developed by the American Petroleum Institute.

“basin” means a large area with a relatively thick accumulation of sedimentary rocks.

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

“~~Bcf~~bcf” means one billion cubic feet, which is a unit of measurement of volume for natural gas.

“BLM” means for the U.S. Bureau of Land Management.

“b~~Boe~~oe” means barrel of oil equivalent, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.

“b~~Boe/~~oe/d” means ~~Boe~~boe per day.

“Break even” means the Brent price at which we expect to generate positive Levered Free Cash Flow.

“Brent” means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea.

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

“CAA” is an abbreviation for the Clean Air Act, which governs air emissions.

“CalGEM” is an abbreviation for the California Geologic Energy Management Division.

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“Cap-and-trade” is a statewide program in California established by the Global Warming Solutions Act of 2006 which outlined an enforceable compliance obligation beginning with 2013 GHG emissions and currently extended through 2030.

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“CARB” is an abbreviation for the California Air Resources Board.

“CCA” or “CCAs” is an abbreviation for California carbon allowances.

“CERCLA” is an abbreviation for the Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous substances have been released into the environment (commonly known as “Superfund”).

“Clean Water Rule” refers to the rule issued in August 2015 by the EPA and U.S. Army Corps of Engineers which expanded the scope of the federal jurisdiction over wetlands and other types of waters.

“COGCC” is an abbreviation for the Colorado Oil and Gas Conservation Commission.

“Completion” means the installation of permanent equipment for the production of oil or natural gas.

“Condensate” means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“CPUC” is an abbreviation for the California Public Utilities Commission.

“CWA” is an abbreviation for the Clean Water Act, which governs discharges to and excavations within the waters of the United States.

“DD&A” means depreciation, depletion & amortization.

“Development drilling” or “Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.

“Diatomite” means a sedimentary rock composed primarily of siliceous, diatom shells.

“Differential” means an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

“Downspacing” means additional wells drilled between known producing wells to better develop the reservoir.

~~"EH&S"~~“EH&S” is an abbreviation for Environmental, Health & Safety.

“Enhanced oil recovery” means a technique for increasing the amount of oil that can be extracted from a field.

“EOR” means enhanced oil recovery.

“EPA” is an abbreviation for the United States Environmental Protection Agency.

“EPS” is an abbreviation for earnings per share.

“ESA” is an abbreviation for the federal Endangered Species Act.

“Exploration activities” means the initial phase of oil and natural gas operations that includes the generation of a prospect or play and the drilling of an exploration well.

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“FASB” is an abbreviation for the Financial Accounting Standards Board.

“FERC” is an abbreviation for the Federal Energy Regulatory Commission.

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

“FIP” is an abbreviation for Federal Implementation Plan.

“Formation” means a layer of rock which has distinct characteristics that differ from those of nearby rock.

“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.

“GAAP” is an abbreviation for U.S. generally accepted accounting principles.

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

“GHG” or “GHGs” is an abbreviation for greenhouse gases.

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

“Held by production” means acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.

“Henry Hub” is a distribution hub on the natural gas pipeline system in Erath, Louisiana.

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

“Horizontal drilling” means a wellbore that is drilled laterally.

“ICE” means Intercontinental Exchange.

“Infill drilling” means drilling of an additional well or wells at less than existing spacing to more adequately drain a reservoir.

“Injection Well” means a well in which water, gas or steam is injected, the primary objective typically being to maintain reservoir pressure and/or improve hydrocarbon recovery.

“IOR” means improved oil recovery.

“IPO” is an abbreviation for initial public offering.

“LCFS” is an abbreviation for low carbon fuel standard.

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

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“Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less interest expense, dividends and capital expenditures.

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“LIBOR” is an abbreviation for London Interbank Offered Rate.

“~~MBbl~~mbbl” means one thousand barrels of oil, condensate or NGLs.

“~~MBbl/~~mbbl/d” means ~~MBbl~~mbbl per day.

“~~MBoe~~mboe” means one thousand barrels of oil equivalent.

“~~MBoe/~~mboe/d” means ~~MBoe~~mboe per day.

“~~Mcf~~mcf” means one thousand cubic feet, which is a unit of measurement of volume for natural gas.

“~~MMBbl~~mmbbl” means one million barrels of oil, condensate or NGLs.

“~~MMBoe~~mmboe” means one million barrels of oil equivalent.

“~~MMBtu~~mmbtu” means one million ~~Btus.~~btus.

“~~MMBtu/~~mmbtu/d” means ~~MMBtu~~mmbtu per day.

“~~MMcf~~mmcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.

“~~MMcf/~~mmcf/d” means ~~MMcf~~mmcf per day.

“MTBA” is an abbreviation for Migratory Bird Treaty Act.

“MW” means megawatt.

“MWHs”means megawatt hours.

“NAAQS” is an abbreviation for the National Ambient Air Quality Standard.

“NASDAQ” means Nasdaq Global Select Market.

“NEPA” is an abbreviation for the National Environmental Policy Act, which requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands.

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

“Net revenue interest” means all of the working interests, less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.

“NGA” is an abbreviation for the Natural Gas Act.

“NGL” or “NGLs” means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

“NRI” is an abbreviation for net revenue interest.

“NYMEX” means New York Mercantile Exchange.

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“Oil” means crude oil or condensate.

“OPEC” is an abbreviation for the Organization of the Petroleum Exporting Countries.

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“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

“OSHA” is an abbreviation for the Occupational Safety and Health Act of 1970.

“OTC” means over-the-counter

“PALs” is an abbreviation for project approval letters.

“PCAOB” is an abbreviation for the Public Company Accounting Oversight Board.

“PDNP” is an abbreviation for proved developed non-producing.

“PDP” is an abbreviation for proved developed producing.

“Permeability” means the ability, or measurement of a rock’s ability, to transmit fluids.

“PHMSA” is an abbreviation for the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration.

“Play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations.

“PPA” is an abbreviation for power purchase agreement.

“Production costs” means costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

“Productive well” means a well that is producing oil, natural gas or NGLs or that is capable of production.

“Proppant” means sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.

“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved developed producing reserves” means reserves that are being recovered through existing wells with existing equipment and operating methods.

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

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“Proved undeveloped drilling location” means a site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

“Proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“PSUs” means performance-based restricted stock units

“PURPA” is an abbreviation for the Public Utility Regulatory Policies Act.

“PV-10” is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.

“QF” means qualifying facility.

“RCRA” is an abbreviation for the Resource Conservation and Recovery Act, which governs the management of solid waste.

“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.

“Reasonable certainty” means a high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.

“Relative TSR” means relative total stockholder return.

“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

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“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

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

“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.

“RSUs” is an abbreviation for restricted stock units.

“SARs” is an abbreviation for stock appreciation rights.

“SDWA” is an abbreviation for the Safe Drinking Water Act, which governs the underground injection and disposal of wastewater;.

“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended on the given date.

“Seismic Data” means data produced by an exploration method of sending energy waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.

“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“SPCC plans” means spill prevention, control and countermeasure plans.

“Steamflood” means cyclic or continuous steam injection.

“Standardized measure” means discounted future net cash flows estimated by applying year-end prices to the estimated future production of proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Stimulating” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.

“Strip Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules with the exception of pricing that is based on average annual forward-month ICE (Brent) oil and NYMEX Henry Hub natural gas contract pricing in effect on a given date to reflect the market expectations as of that date.

“Superfund” is a commonly known term for CERLA.

“UIC” is an abbreviation for the Underground Injection Control program.

“Unconventional resource plays” means a resource play that uses methods other than traditional vertical well extraction. Unconventional resources are trapped in reservoirs with low permeability, meaning little to no ability for

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the oil or natural gas to flow through the rock and into a wellbore. Examples of unconventional oil resources include oil shales, oil sands, extra-heavy oil, gas-to-liquids and coal-to-liquids.

“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

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

“Unproved reserves” means reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.

“Wellbore” means the hole drilled by the bit that is equipped for natural resource production on a completed well. Also called well or borehole.

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

“Workover” means maintenance on a producing well to restore or increase production.

“WST” is an abbreviation for well stimulation treatment.

“WTI” means West Texas Intermediate.

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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.




		Berry Corporation (bry)
		(Registrant)

Date:	~~November~~August 4, ~~2020~~2021	/s/ Cary Baetz
		Cary Baetz
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer)


Date:	~~November~~August 4, ~~2020~~2021	/s/ M. S. Helm
		Michael S. Helm
		Chief Accounting Officer
		(Principal Accounting Officer)

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		Page
Part I – Financial Information
Item 1.	Financial Statements (unaudited)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Stockholders ’Equity	3
	Condensed Consolidated Statements of Cash Flows	54
	Notes to Condensed Consolidated Financial Statements	65
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1815
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5751
Item 4.	Controls and Procedures	5952

Part II – Other Information
Item 1.	Legal Proceedings	6053
Item 1A.	Risk Factors	6053
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities	6454
Item 6.	Exhibits	6555
	Glossary of Terms	6656
	Signatures	7464


	Q4 2020		1H 2021		2H 2021




Fixed Price Oil Swaps (Brent):
Hedged volume (MBbls)	2,208		3,438		2,084
Weighted-average price ($/Bbl)	$	59.85	$	45.82	$	46.17







Purchased Oil Calls Options (Brent):
Hedged volume (MBbls)	276		0		0
Weighted-average price ($/Bbl)	$	65.00	$	0	$	0
Fixed Price Gas Purchase Swaps (Kern, Delivered):
Hedged volume (MMBtu)	5,060,000		9,045,000		5,535,000
Weighted-average price ($/MMBtu)	$	2.76	$	2.71	$	2.73
Fixed Price Gas Purchase Swaps (SoCal Citygate):
Hedged volume (MMBtu)	155,000		0		0
Weighted-average price ($/MMBtu)	$	3.80	$	0	$	0