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 March 31, ~~2022~~2023


☐						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)~~232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting ~~company”~~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 April 30, ~~2022 80,760,354~~2023 77,081,809

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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.

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


		March 31, 2022		December 31, 2021			March 31, 2023		December 31, 2022
		(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	$	17,960	$	15,283	Cash and cash equivalents	$	14,117	$	46,250
Accounts receivable, net of allowance for doubtful accounts of $866 at March 31, 2022 and $866 at December 31, 2021		111,961		86,269

Accounts receivable, net of allowance for doubtful accounts of $866 at March 31, 2023 and December 31, 2022						Accounts receivable, net of allowance for doubtful accounts of $866 at March 31, 2023 and December 31, 2022	83,113		101,713
Derivative instruments						Derivative instruments	497		36,367

Other current assets	Other current assets	36,567		45,946		Other current assets	34,885		33,725
Total current assets	Total current assets	166,488		147,498		Total current assets	132,612		218,055
Noncurrent assets:	Noncurrent assets:					Noncurrent assets:
Oil and natural gas properties	Oil and natural gas properties	1,585,525		1,537,894		Oil and natural gas properties	1,746,216		1,725,864
Accumulated depletion and amortization	Accumulated depletion and amortization	(372,136)		(340,328)		Accumulated depletion and amortization	(495,883)		(465,889)
Total oil and natural gas properties, net	Total oil and natural gas properties, net	1,213,389		1,197,566		Total oil and natural gas properties, net	1,250,333		1,259,975
Other property and equipment	Other property and equipment	151,479		140,710		Other property and equipment	159,612		155,619
Accumulated depreciation	Accumulated depreciation	(41,840)		(36,927)		Accumulated depreciation	(63,063)		(55,781)
Total other property and equipment, net	Total other property and equipment, net	109,639		103,783		Total other property and equipment, net	96,549		99,838

Derivative instruments	Derivative instruments	—		1,070		Derivative instruments	5,858		76
Deferred income taxes	Deferred income taxes	171		—		Deferred income taxes	45,371		42,844
Other noncurrent assets	Other noncurrent assets	5,040		6,562		Other noncurrent assets	9,518		10,242
Total assets	Total assets	$	1,494,727	$	1,456,479	Total assets	$	1,540,241	$	1,631,030
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	$	154,084	$	157,524	Accounts payable and accrued expenses	$	141,063	$	203,101
Derivative instruments	Derivative instruments	92,472		29,625		Derivative instruments	20,476		31,106

Total current liabilities	Total current liabilities	246,556		187,149		Total current liabilities	161,539		234,207
Noncurrent liabilities:	Noncurrent liabilities:					Noncurrent liabilities:
Long-term debt	Long-term debt	394,846		394,566		Long-term debt	437,036		395,735
Derivative instruments	Derivative instruments	56,208		18,577		Derivative instruments	2,555		13,642
Deferred income taxes		—		1,831

Asset retirement obligations	Asset retirement obligations	142,999		143,926		Asset retirement obligations	156,411		158,491
Other noncurrent liabilities	Other noncurrent liabilities	23,692		17,782		Other noncurrent liabilities	29,764		28,470
Commitments and Contingencies - Note 4	Commitments and Contingencies - Note 4	0		0		Commitments and Contingencies - Note 4
Stockholders' Equity:	Stockholders' Equity:					Stockholders' Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 86,342,808 and 85,590,417 shares issued; and 80,759,540 and 80,007,149 shares outstanding, at March 31, 2022 and December 31, 2021, respectively)		86		86
Common stock ($0.001 par value; 750,000,000 shares authorized; 87,166,043 and 86,350,771 shares issued; and 76,582,775 and 75,767,503 shares outstanding, at March 31, 2023 and December 31, 2022, respectively)						Common stock ($0.001 par value; 750,000,000 shares authorized; 87,166,043 and 86,350,771 shares issued; and 76,582,775 and 75,767,503 shares outstanding, at March 31, 2023 and December 31, 2022, respectively)	88		86
Additional paid-in-capital	Additional paid-in-capital	907,059		912,471		Additional paid-in-capital	822,172		821,443
Treasury stock, at cost (5,583,268 and 5,583,268 shares at March 31, 2022 and December 31, 2021, respectively)		(52,436)		(52,436)
Retained deficit		(224,283)		(167,473)
Treasury stock, at cost (10,583,268 shares at March 31, 2023 and December 31, 2022, respectively)						Treasury stock, at cost (10,583,268 shares at March 31, 2023 and December 31, 2022, respectively)	(103,739)		(103,739)
Retained earnings						Retained earnings	34,415		82,695
Total stockholders' equity	Total stockholders' equity	630,426		692,648		Total stockholders' equity	752,936		800,485
Total liabilities and stockholders' equity	Total liabilities and stockholders' equity	$	1,494,727	$	1,456,479	Total liabilities and stockholders' equity	$	1,540,241	$	1,631,030

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

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BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

Three Months Ended
March 31,
2022 2021
(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales $ 210,351 $ 135,265
Services revenue 39,836 —
Electricity sales 5,419 10,069
Losses on oil and gas sales derivatives (161,858) (53,504)
Marketing revenues 289 2,234
Other revenues 45 137
Total revenues and other 94,082 94,201
Expenses and other:
Lease operating expenses 63,124 62,284
Costs of services 33,472 —
Electricity generation expenses 4,463 7,648
Transportation expenses 1,158 1,576
Marketing expenses 299 2,227
General and administrative expenses 22,942 17,070
Depreciation, depletion, and amortization 39,777 33,840
Taxes, other than income taxes 6,605 9,557
Gains on natural gas purchase derivatives (29,054) (27,730)
Other operating expenses 3,769 799
Total expenses and other 146,555 107,271
Other (expenses) income:
Interest expense (7,675) (8,485)
Other, net (13) (143)
Total other (expenses) income (7,688) (8,628)
Loss before income taxes (60,161) (21,698)
Income tax benefit (3,351) (376)
Net loss $ (56,810) $ (21,322)
Net loss per share:
Basic $ (0.71) $ (0.27)
Diluted $ (0.71) $ (0.27)



	Three Months Ended March 31,
		2023		2022
		(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales		$	166,357	$	210,351
Services revenue		44,623		39,836
Electricity sales		5,445		5,419
Gains (losses) on oil and gas sales derivatives		38,499		(161,858)
Marketing revenues		—		289
Other revenues		45		45
Total revenues and other		254,969		94,082
Expenses and other:
Lease operating expenses		134,835		63,124
Costs of services		36,099		33,472
Electricity generation expenses		2,500		4,463
Transportation expenses		1,041		1,158
Marketing expenses		—		299
General and administrative expenses		31,669		22,942
Depreciation, depletion, and amortization		40,121		39,777

Taxes, other than income taxes		10,460		6,605

Gains on natural gas purchase derivatives		(610)		(29,054)
Other operating (income) expenses		(286)		3,769
Total expenses and other		255,829		146,555
Other (expenses) income:
Interest expense		(7,837)		(7,675)
Other, net		(75)		(13)
Total other expenses		(7,912)		(7,688)

Loss before income taxes		(8,772)		(60,161)
Income tax benefit		(2,913)		(3,351)
Net loss		$	(5,859)	$	(56,810)



Net loss per share:
Basic		$	(0.08)	$	(0.71)
Diluted		$	(0.08)	$	(0.71)

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

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BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

Three-Month Period Ended March 31, 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

Three-Month Period Ended March 31, 2022
Common Stock Additional Paid-in Capital Treasury Stock Retained Deficit Total Stockholders’ Equity
(in thousands)
December 31, 2021 $ 86 $ 912,471 $ (52,436) $ (167,473) $ 692,648
Shares withheld for payment of taxes on equity awards and other — (4,096) — — (4,096)
Stock based compensation — 3,920 — — 3,920
Dividends declared on common stock, $0.06/share — (5,236) — — (5,236)
Net loss — — — (56,810) (56,810)
March 31, 2022 $ 86 $ 907,059 $ (52,436) $ (224,283) $ 630,426



	Three-Month Period Ended March 31, 2022
	Common Stock		Additional Paid-in Capital		Treasury Stock		Accumulated Deficit		Total Stockholders’ Equity
	(in thousands)
December 31, 2021	$	86	$	912,471	$	(52,436)	$	(167,473)	$	692,648

Shares withheld for payment of taxes on equity awards and other	—		(4,096)		—		—		(4,096)
Stock based compensation	—		3,920		—		—		3,920


Dividends declared on common stock, $0.06/share	—		(5,236)		—		—		(5,236)
Net loss	—		—		—		(56,810)		(56,810)
March 31, 2022	$	86	$	907,059	$	(52,436)	$	(224,283)	$	630,426


	Three-Month Period Ended March 31, 2023
	Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Earnings		Total Stockholders’ Equity
	(in thousands)
December 31, 2022	$	86	$	821,443	$	(103,739)	$	82,695	$	800,485

Shares withheld for payment of taxes on equity awards and other	—		(4,260)		—		—		(4,260)
Stock based compensation	—		4,989		—		—		4,989
Issuance of common stock	2		—		—		—		2

Dividends declared on common stock, $0.50/share	—		—		—		(42,421)		(42,421)
Net loss	—		—		—		(5,859)		(5,859)
March 31, 2023	$	88	$	822,172	$	(103,739)	$	34,415	$	752,936

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)

Three Months Ended
March 31,
2022 2021
(in thousands)
Cash flows from operating activities:
Net loss $ (56,810) $ (21,322)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization 39,777 33,840
Amortization of debt issuance costs 576 1,360
Stock-based compensation expense 3,686 3,779
Deferred income taxes (2,002) (376)
Other operating expenses (910) —
Derivative activities:
Total losses 132,804 25,774
Cash settlements on derivatives (32,152) 850
Changes in assets and liabilities:
Increase in accounts receivable (25,648) (296)
Decrease (increase) decrease in other assets 9,231 (5,663)
(Decrease) increase in accounts payable and accrued expenses (14,093) 1,300
(Decrease) in other liabilities (5,929) (816)
Net cash provided by operating activities 48,530 38,430
Cash flows from investing activities:
Capital expenditures:
Capital expenditures (27,620) (23,569)
Changes in capital expenditures accruals 9,992 3,508
Acquisitions, net of cash received (18,932) —
Proceeds from sale of property and equipment and other — 124
Net cash used in investing activities (36,560) (19,937)
Cash flows from financing activities:
Borrowings under 2021 RBL credit facility 107,000 —
Repayments on 2021 RBL credit facility (107,000) —
Dividends paid on common stock (5,197) (246)
Shares withheld for payment of taxes on equity awards and other (4,096) (1,442)
Net cash used in financing activities (9,293) (1,688)
Net increase in cash and cash equivalents 2,677 16,805
Cash and cash equivalents:
Beginning 15,283 80,557
Ending $ 17,960 $ 97,362


	Three Months Ended March 31,
	2023		2022
	(in thousands)
Cash flows from operating activities:
Net loss	$	(5,859)	$	(56,810)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	40,121		39,777
Amortization of debt issuance costs	636		576

Stock-based compensation expense	4,766		3,686
Deferred income taxes	(2,913)		(2,002)

Other operating expenses (income)	604		(910)

Derivative activities:
Total (gains) losses	(39,109)		132,804
Cash settlements on derivatives	47,467		(32,152)

Changes in assets and liabilities:
Decrease (increase) in accounts receivable	18,615		(25,648)
(Increase) decrease in other assets	(383)		9,231
Decrease in accounts payable and accrued expenses	(57,933)		(14,093)
Decrease in other liabilities	(4,231)		(5,929)
Net cash provided by operating activities	1,781		48,530

Cash flows from investing activities:
Capital expenditures:
Capital expenditures	(20,633)		(27,620)


Changes in capital expenditures accruals	(6,170)		9,992

Acquisitions, net of cash received	(3,657)		(18,932)




Net cash used in investing activities	(30,460)		(36,560)

Cash flows from financing activities:
Borrowings under 2021 RBL credit facility	53,000		107,000
Repayments on 2021 RBL credit facility	(12,000)		(107,000)




Dividends paid on common stock	(40,194)		(5,197)

Shares withheld for payment of taxes on equity awards and other	(4,260)		(4,096)









Net cash used in financing activities	(3,454)		(9,293)
Net (decrease) increase in cash and cash equivalents	(32,133)		2,677
Cash and cash equivalents:
Beginning	46,250		15,283
Ending	$	14,117	$	17,960

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

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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 each of its 3three Delaware limited liability company subsidiaries: (1) Berry Petroleum Company, LLC (“Berry LLC”), (2) CJ Berry Well Services Management, LLC (“C&J Management”) and (3) C&J Well Services, LLC (“~~CJWS”~~C&J”). As the context may require, the “Company”, “we”, “our” or similar words refer to Berry Corp. and its ~~subsidiary,~~subsidiaries, Berry LLC, C&J Management and ~~as of October 1, 2021 this also includes CJWS and CJ Management.~~C&J.

Nature of Business

We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional ~~oil~~ reserves in the San Joaquin basin of California (100% oil) and the Uinta basin of Utah (oil and gas), with ~~newly acquired~~ well servicing and abandonment capabilities in California. ~~As of October 1, 2021, we have operated~~We operate in 2two business segments: (i) ~~development~~exploration and production (“DE&P”) and (ii) well servicing and abandonment. The D&P business segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which now constitutes our well servicing and abandonment segment, also referred to as “CJWS”.

Berry Corp. was incorporated under Delaware law in February 2017 and its common stock began trading on NASDAQ under the symbol “bry” in July 2018. Berry Corp. operates through its 3 wholly owned subsidiaries. Berry LLC owns and operates our oil and gas assets, all of which are located onshore in the United States (the “U.S.”), in California (in the San Joaquin basin), and Utah (in the Uinta basin). We are focused on the development and production of onshore, low geologic risk, long-lived conventional oil reserves. In January 2022, we divested our natural gas properties in the Piceance basin of Colorado.

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~~Securities 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, ~~2021.~~

~~New Accounting Standards Adopted~~2022.

~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases (Topic 842)~~, which requires lessees to recognize assets and liabilities on the balance sheet 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. In January 2018, the FASB issued ASU 2018-01, ~~Leases (Topic 842), which is~~an update to the lease standard providing an optional transition approach for land easements allowing entities to evaluate only new or modified land easements. In July 2018, the FASB issued ASU 2018-11, ~~Leases (Topic 842)~~,

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

which provided optional transition relief allowing a prospective approach in applying the new rules by not adjusting comparative period financial information for the effects of the new rules and not requiring disclosures for periods before the effective date. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers. During the second 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 adopted these rules in the first quarter of 2022 prospectively.

Note 2—Debt

The following table summarizes our outstanding debt:


		March 31, 2022		December 31, 2021		Interest Rate	Maturity	Security		March 31, 2023		December 31, 2022		Interest Rate	Maturity	Security
		(in thousands)								(in thousands)
2021 RBL Facility	2021 RBL Facility	$	—	$	—	variable rates 5.5% (2022) and 5.3% (2021)	August 26, 2025	Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets	2021 RBL Facility	$	41,000	$	—	variable rates 10.25% (2023) and 9.50% (2022)	August 26, 2025	Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets
2022 ABL Facility									2022 ABL Facility	—		—		variable rates 9.0% (2023) and 8.3% (2022)	June 5, 2025	Personal property assets, other than excluded accounts

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		400,000					Long-Term Debt - Principal Amount	441,000		400,000
Less: Debt Issuance Costs	Less: Debt Issuance Costs	(5,154)		(5,434)					Less: Debt Issuance Costs	(3,964)		(4,265)
Long-Term Debt, net	Long-Term Debt, net	$	394,846	$	394,566				Long-Term Debt, net	$	437,036	$	395,735

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At March 31, ~~2022~~2023 and December 31, ~~2021,~~2022, debt issuance costs ~~for the 2021 RBL Facility (as defined below)~~ reported in “other noncurrent assets” on the balance sheet were approximately (i) $3 million and $4 million, ~~and $5 million~~respectively, net of amortization, ~~respectively.~~for the Credit Agreement, dated as of August 26, 2021, among Berry Corp, as a guarantor, Berry LLC, as the borrower, JPMorgan Chase Bank, N.A., as the administrative agent and the other parties thereto (as amended, restated, modified or otherwise supplemented from time to time, the “2021 RBL Facility”) and (ii) an immaterial amount, net of amortization, for the Revolving Loan and Security Agreement, dated as of August 9, 2022, among C&J and C&J Management, as borrowers, and Tri Counties Bank, as lender (as amended, restated, supplemented or otherwise modified from time to time, the “2022 ABL Facility”). At March 31, ~~2022~~2023 and December 31, ~~2021,~~2022, debt issuance costs, net of amortization, for the unsecured notes due February 2026 (the “2026 Notes”) reported in “Long-Term Debt, net” on the balance sheet was approximately $5$4 million.

For each of the three month periods ended March 31, ~~2022~~2023 and ~~2021,~~2022, the amortization expense for the 2021 RBL Facility, ~~the 2017 RBL~~2022 ABL Facility ~~(as defined below)~~ and the 2026 Notes, combined, was approximately $1 million. The amortization of debt issuance costs is presented in “interest expense” inon the condensed consolidated statements of operations.

Fair Value

Our debt is recorded at the carrying amount on the balance sheets. The carrying ~~amount~~amounts of the 2021 RBL Facility ~~approximates~~and the 2022 ABL Facility approximate fair value because the interest rates are variable and reflect market rates. The 2021 RBL and 2022 ABL are Level 2 in the fair value hierarchy. The fair value of the 2026 Notes was approximately ~~$398 million and $400~~$369 million at March 31, ~~2022~~2023 and December 31, ~~2021, respectively.~~2022. The 2026 Notes are Level 1 in the fair value hierarchy.

2021 RBL Facility

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

2021 RBL Facility is redetermined semi-annually, and the borrowing base redeterminations generally become effective each May and November, although the borrower and the lenders may each make one interim redetermination between scheduled redeterminations. ~~In December~~The 2021 ~~we completed~~RBL Facility matures on August 26, 2025, unless terminated earlier in accordance with the ~~first scheduled semi-annual borrowing base redetermination and entered into that certain First Amendment~~2021 RBL Facility terms. The 2021 RBL Facility is available to Credit Agreement (the “First Amendment”), which resulted in a reaffirmed borrowing base at $200 million and changes to the hedging covenants in respect of the exclusion of short puts or similar derivatives in the calculation of minimum and maximum hedging requirements. In May 2022, Berry Corp., as a guarantor, and Berry LLC, as the borrower, entered into that certain Second Amendment to Credit Agreement and Limited Consent and Waiver (the “Second Amendment”) pursuant to which, among other things, the requisite lendersus for general corporate purposes, including working capital.

The outstanding borrowings under the 2021 RBL Facility (i) consented to certain dividends and distributions and to certain investments made by Berry LLC in C&J Well Services, LLC and/or CJ Berry Well Services Management, LLC, in each case, as further described therein, (ii) waived certain minimum hedging requirements for the time periods described therein, (iii) waived any breach, default or event of default which may have arisen as a result of any of the foregoing, (iv) amended the restricted payments covenant to give us additional flexibility to make restricted payments, subject to satisfaction of certain leverage and availability conditions and other conditions described below and in the Second Amendment and (v) amended the minimum hedging covenant to not, until October 1, 2022, require hedges for any full calendar month from and after January 1, 2025, as further described in the Second Amendment.

If the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the 2021 RBL Facility exceeds the borrowing base at any time as a result of a redetermination of the borrowing base, we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, deliver reserve engineering reports and mortgages covering additional oil and gas properties sufficient in certain lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the next six-month period. Upon certain adjustments to the borrowing base other than a result of a redetermination, we are required to make a lump sum payment in an amount equal to the amount by which the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the 2021 RBL Facility exceeds the borrowing base. In addition, the 2021 RBL Facility provides that if there are any outstanding borrowings and the consolidated cash balance exceeds $20 million at the end of each calendar week, such excess amounts shall be used to prepay borrowings under the credit agreement. Otherwise, any unpaid principal will be due at maturity.

~~The outstanding borrowings under the revolving loan~~ bear interest at a rate equal to, at our option, either ~~(i)~~(a) a customary base rate plus an applicable margin ranging from 2.0% to 3.0% ~~per annum, and (ii)~~or (b) a ~~customary benchmark~~term SOFR reference rate, plus an applicable margin ranging from 3.0% to 4.0% ~~per annum, and~~, in each case ~~depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.5%~~determined based on the ~~average daily unused amount of the borrowing availability~~utilization level under the 2021 RBL Facility. ~~We have~~Interest rate on base borrowings is payable quarterly in arrears and is computed on the ~~right to prepay any~~basis of a year of 365/366 days, and interest on term SOFR borrowings ~~under~~accrues in respect of interest periods of one, three or six months, at the ~~2021 RBL Facility with prior notice~~election of the borrower, and is computed on the basis of a year of 360 days and is payable on the last day of such interest period (or, for interest periods of six months, three months after the commencement of such interest period and at ~~any time without~~the end of such interest period.) Unused commitment fees are charged at a ~~prepayment penalty.~~

rate of 0.50%.

The 2021 RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a leverage ratio of not more than 3.0 to 1.0 and (ii) a current ratio of not less than 1.0 to 1.0. As of March 31, ~~2022,~~2023, our leverage ratio and current ratio were ~~1.7:~~1.4 to 1.0 and ~~2.4:~~1.8 to 1.0, respectively. ~~In addition, the 2021 RBL Facility currently provides that, to the extent~~As of March 31, 2023, 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 of the debt covenants.

The 2021 RBL Facility also contains other customary affirmative and negative covenants, as well as events of default and remedies. If we do not comply with the financial and other covenants in the 2021 RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the 2021 RBL Facility and terminate the commitments thereunder.

As of March 31, 2023, we had $41 million borrowings outstanding, $7 million in letters of credit outstanding and approximately $152 million of available borrowing capacity under the 2021 RBL Facility.

2022 ABL Facility

Subject to satisfaction of customary conditions precedent to borrowing, as of March 31, ~~2022.~~2023, C&J and C&J Management could borrow up to the lesser of (x) $15 million and (y) the borrowing base under the 2022 ABL Facility, with a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $7.5 million (with borrowing availability being reduced by the face amount of any letters of credit issued under the subfacility). The “borrowing base” is an amount equal to 80% of the balance due on eligible accounts receivable, subject to reserves that Tri Counties Bank may implement in its reasonable discretion. Interest on the outstanding principal amount of the revolving loans under the 2022 ABL Facility accrues at a per annum rate equal to 1.25% in excess of The Wall Street Journal Prime Rate. The “Wall Street Journal Prime Rate” is the variable rate of interest, on a per annum basis, which is announced and/or published in the “Money Rates” section of The Wall Street Journal from time to time as its “Prime Rate”. The rate will be redetermined whenever The Wall Street Journal Prime Rate changes. Interest is due quarterly, in arrears. The 2022 ABL Facility matures on June 5, 2025, unless terminated in accordance with the 2022 ABL Facility terms.

The 2022 ABL Facility requires CJWS to comply with the following financial covenants (i) maintain on a consolidated basis a ratio of total liabilities to tangible net worth of no greater than 1.5 to 1.0 at any time; (ii) reduce the amount of revolving advances outstanding under the 2022 ABL Facility to not more than 90% of the lesser of (a) the maximum revolving advance amount, or (b) the borrowing base, as of Tri Counties Bank’s close of business on the last day of each fiscal quarter; and (iii) maintain net income before taxes of not less than $1.00 as of each fiscal year end. As of March 31, 2023, CJWS was in compliance with all of the debt covenants.

The ~~2021 RBL~~2022 ABL Facility also contains ~~usual~~other customary affirmative and ~~customary~~negative covenants, as well as events of default and ~~remedies for credit facilities of a similar nature. The 2021 RBL Facility also places restrictions on~~remedies. If CJWS does not comply with the ~~borrower and its restricted subsidiaries with respect to additional indebtedness, liens, dividends~~financial and other ~~payments~~covenants in the 2022 ABL Facility, the lender may, subject to ~~shareholders, repurchases~~customary cure rights, require immediate payment of all amounts outstanding under the 2022 ABL Facility and terminate the commitment thereunder. CJWS’s obligations under the 2022 ABL Facility are not guaranteed by Berry Corp. or ~~redemptions of our common stock, redemptions of the borrower’s senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions~~Berry LLC and ~~other matters.~~

Berry Corp. and Berry LLC do not and are not required to provide any

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~~From~~credit support for such obligations.

In March 2023, we entered into the Amendment to Revolving Loan and after August 26, 2022, the 2021 RBL Facility permits us to repurchase certain indebtedness so long as both before and after giving pro forma effect to such repurchase, no default or event of default exists, availability is equal to or greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to 1.0.Security Agreement (the “First Amendment”). The 2021 RBL Facility also permits us to make restricted payments so long as both before and after giving pro forma effect to such distribution, no default or event of default exists, availability exceeds 75% of the borrowing base, and our pro forma leverage ratio is less than or equal to 1.5 to 1.0. In addition, we can make other restricted payments in an aggregate amount not to exceed 100% of Free Cash Flow (as defined under the 2021 RBL Facility) for the fiscal quarter most recently ended prior to such distribution so long as,First Amendment, in addition to other ~~conditions and limitations as~~changes described intherein, amended the ~~2021 RBL~~2022 ABL Facility ~~both before and after giving pro forma effect~~ to ~~such distribution, no default or event of default exists, availability is greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to 1.0.~~

~~Berry LLC is the borrower on the 2021 RBL Facility and Berry Corp. is the guarantor. Each future subsidiary of~~

~~Berry Corp., with~~substitute certain exceptions, is required to guarantee our obligations and obligations of the other guarantors under the 2021 RBL Facility and under certain hedging transactions and banking services arrangements (the “Guaranteed Obligations”). The lenders under the 2021 RBL Facility hold a mortgage on at least 90% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions.collateral.

As of March 31, ~~2022, we~~2023, CJWS had no borrowings ~~outstanding, $7~~and $2 million in letters of credit outstanding ~~and approximately $193~~with $13 million of available borrowing capacity under the ~~2021 RBL~~2022 ABL Facility.

~~2017 RBL Facility~~Senior Unsecured Notes

~~On July 31, 2017, we entered into~~In February 2018, Berry LLC completed a ~~credit agreement that provided for a revolving loan with up to $1.5 billion~~private issuance of ~~commitment, subject to a reserve borrowing base (“2017 RBL Facility”~~$400 million in aggregate principal amount of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”)~~. In April 2021, we completed our scheduled semi-annual borrowing base redetermination under our 2017 RBL Facility,~~, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount.

The 2026 Notes are Berry LLC’s senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The 2026 Notes are fully and unconditionally guaranteed on a ~~reaffirmed borrowing base at $200 million. On August 26, 2021, we cancelled~~senior unsecured basis by Berry Corp.

The indenture governing the ~~2017 RBL Facility agreement. There~~2026 Notes contains customary covenants and events of default (in some cases, subject to grace periods). We were ~~no borrowings outstanding at~~in compliance with all covenants under the ~~time~~2026 Notes as of ~~cancellation.~~March 31, 2023.

Debt 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 do not obligate Berry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any notes under this program.

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~~(Unaudited)~~

Note 3—Derivatives

We utilize derivatives, such as swaps, puts, calls and collars, 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. In addition to satisfying the oil hedging requirements of the 2021 RBL Facility, we target covering our operating expenses and a majority of our fixed charges, which includes capital needed to sustain production levels, as well as interest and fixed dividends as applicable, with the oil and gas sales hedges for a period of up to three 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 three years. We have also entered into Utah gas transportation contracts to help reduce the price fluctuation exposure, however these do not qualify as hedges. 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. We had no such transactions in the periods presented.

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~~bbl and per mmbtu, respectively, and receive settlement payments for prices below the indicated weighted-average price per ~~barrel~~bbl and per mmbtu, respectively.

For our long put spreads, in addition to any deferred premium payments, we would receive settlement payments for prices below the indicated highest price of the long put with the maximum payment received per barrel equal to the difference between the indicated prices of the long and short put. No payment would be made or received for prices above the highest indicated price of the long put. The short put spreads offset the long put spreads.

~~For our~~ purchased ~~oil~~ puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel, net of ~~Brent.~~ any deferred premium. No payment would be made or received for prices above the indicated weighted-average price per barrel, other than any applicable deferred premium.

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For our sold puts, we would make settlement payments for prices below the indicated weighted-average price per barrel, net of any deferred premium. No payment would be made or received for prices above the indicated weighted-average price per barrel, other than any applicable deferred premium.

For our sold call options, we would make settlement payments for prices above the indicated weighted-average price per barrel, net of any deferred premium. No payment would be made or received for prices above the indicated weighted-average price per barrel, other than any applicable deferred premium.

A consumer collar is used for the purchase of fuel gas and is the combination of buying a call option and selling a put option. We would receive settlement payments for prices above the indicated weighted-average price of the call option and we would make settlement payments for prices below the indicated weighted-average price of the put option. No payment would be made or received for prices above the indicated weighted-average price per barrel, other than any applicable deferred premium.

For natural gas basis swaps, we make settlement payments if the difference between NWPL and Henry Hub is below the indicated weighted-average price of our contracts and receive settlement payments if the difference between NWPL and Henry Hub is above the indicated weighted-average price.

For some of our options we paid or received a premium at the time the positions were created and for others, the premium payment or receipt is deferred until the time of settlement. As of March 31, ~~2022~~2023 we have net payable deferred premiums of approximately ~~$14~~$4 million, which is reflected in the mark-to-market valuation and will be payable ~~beginning in 2022~~ through ~~2024, in approximately the same amount each year.~~

~~For our sold oil calls, we would make settlement payments for prices above the indicated weighted-average price. No payment would be due for prices below the indicated weighted-average price.~~

For our purchased gas calls, we would receive settlement payments for prices above the indicated weighted-average price. No payment would be received for prices below the indicated weighted-average price.

~~For our sold oil and gas puts, we would make settlement payments for prices below the indicated weighted-average price. No payment would be due for prices above the indicated weighted-average price.~~December 31, 2024.

We use oil and gas production hedges to protect our sales against decreases in oil and gas prices. We also use natural gas purchase hedges 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.

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As of March 31, ~~2022,~~2023, we had the following ~~hedges for our~~ crude oil production and gas purchases hedges.


	Q2 2023		Q3 2023		Q4 2023		FY 2024		FY 2025		FY 2026
Brent - Crude Oil production
Swaps
Hedged volume (bbls)	1,387,750		1,211,717		1,196,000		3,412,817		99,337		9,518
Weighted-average price ($/bbl)	$	77.01	$	76.26	$	76.18	$	76.07	$	71.55	$	71.55

Sold Calls
Hedged volume (bbls)	364,000		368,000		368,000		1,098,000		2,486,127		472,500
Weighted-average price ($/bbl)	$	106.00	$	106.00	$	106.00	$	105.00	$	91.11	$	82.21
Purchased Puts (net)(1)
Hedged volume (bbls)	546,000		552,000		552,000		1,281,000		2,486,127		472,500
Weighted-average price ($/bbl)	$	50.00	$	50.00	$	50.00	$	50.00	$	58.53	$	60.00

Sold Puts (net)(1)
Hedged volume (bbls)	132,668		184,000		154,116		183,000		—		—
Weighted-average price ($/bbl)	$	40.00	$	40.00	$	40.00	$	40.00	$	—	$	—




Henry Hub - Natural Gas purchases



Consumer Collars
Hedged volume (mmbtu)	1,820,000		—		—		—		—		—
Weighted-average price ($/mmbtu)	$4.00/$2.75		$	—	$	—	$	—	$	—	$	—
NWPL - Natural Gas purchases
Swaps
Hedged volume (mmbtu)	3,640,000		3,680,000		3,680,000		7,320,000		6,080,000		—
Weighted-average price ($/mmbtu)	$	5.34	$	5.34	$	5.34	$	4.27	$	4.27	$	—
Gas Basis Differentials
NWPL/HH - basis swaps
Hedged volume (mmbtu)	—		—		610,000		—		—		—
Weighted-average price ($/mmbtu)	$	—	$	—	$	1.12	$	—	$	—	$	—

__________

(1) Purchase puts and sold puts with the same strike price have been presented on a net basis.

In addition to the table above, in April 2023, we added a natural gas ~~purchases.~~

Q2 2022 Q3 2022 Q4 2022 FY 2023 FY 2024
Brent - Crude Oil production
Swaps
Hedged volume (bbls) 1,299,500 1,288,000 1,196,000 3,420,750 1,917,000
Weighted-average price ($/bbl) $ 75.92 $ 75.97 $ 74.05 $ 72.98 $ 75.52
Put Spreads
Long $50/$40 Put Spread hedged volume (bbls) 409,500 414,000 414,000 2,555,000 1,647,000
Short $50/$40 Put Spread hedged volume (bbls) 45,500 46,000 46,000 365,000 366,000
Producer Collars hedged volume (bbls) — — — 1,460,000 1,098,000
Weighted-average price ($/bbl) — — — $40.00/$106.00 $40.00/$105.00
Henry Hub - Natural Gas purchases
Consumer Collars
Hedged volume (mmbtu) 2,730,000 2,760,000 2,760,000 10,950,000 9,150,000
Weighted-average price ($/mmbtu) $4.00/$2.75 $4.00/$2.75 $4.00/$2.75 $4.00/$2.75 $4.00/$2.75

~~In April we added consumer collars (Henry Hub)~~purchase swap (NWPL) of ~~300,000 mmbtu for the second quarter of 2022 and 1,840,000 mmbtu for the second half of 2022~~10,000 mmbtu/d at ~~$4.00/$2.75. We terminated consumer collars (Henry Hub) of 5,520,000 mmbtu for 2023 and 9,150,000 mmbtu for~~$4.10 beginning January 2024 ~~at $4.00/$2.75, resulting in a net cash impact of less than $1 million.~~

~~We sold fixed price oil swaps (Brent) of 245,000 bbls at $102.36 for May 2022~~ through December ~~2022 and 12,778 bbls at $93.10 for 2023.~~2024.

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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 March 31, ~~2022~~2023 and December 31, ~~2021:~~2022:


		March 31, 2022								March 31, 2023
		Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in 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	$	23,513	$	(23,513)	$	—	Commodity Contracts	Current assets	$	23,352	$	(22,855)	$	497
Commodity Contracts	Commodity Contracts	Non-current assets	43,081		(43,081)		—		Commodity Contracts	Non-current assets	46,315		(40,457)		5,858
Liabilities:	Liabilities:								Liabilities:
Commodity Contracts	Commodity Contracts	Current liabilities	(115,985)		23,513		(92,472)		Commodity Contracts	Current liabilities	(43,331)		22,855		(20,476)
Commodity Contracts	Commodity Contracts	Non-current liabilities	(99,289)		43,081		(56,208)		Commodity Contracts	Non-current liabilities	(43,012)		40,457		(2,555)
Total derivatives	Total derivatives		$	(148,680)	$	—	$	(148,680)	Total derivatives		$	(16,676)	$	—	$	(16,676)

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

~~(Unaudited)~~


		December 31, 2021								December 31, 2022
		Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in 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	$	5,360	$	(5,360)	$	—	Commodity Contracts	Current assets	$	66,974	$	(30,607)	$	36,367
Commodity Contracts	Commodity Contracts	Non-current assets	29,828		(28,758)		1,070		Commodity Contracts	Non-current assets	39,886		(39,810)		76
Liabilities:	Liabilities:								Liabilities:
Commodity Contracts	Commodity Contracts	Current liabilities	(34,985)		5,360		(29,625)		Commodity Contracts	Current liabilities	(61,713)		30,607		(31,106)
Commodity Contracts	Commodity Contracts	Non-current liabilities	(47,335)		28,758		(18,577)		Commodity Contracts	Non-current liabilities	(53,452)		39,810		(13,642)
Total derivatives	Total derivatives		$	(47,132)	$	—	$	(47,132)	Total derivatives		$	(8,305)	$	—	$	(8,305)

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 2021 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 A2 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.

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Note 4—Lawsuits, Claims, Commitments and Contingencies

In the normal course of business, we, or our subsidiaries, 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.

We accrue 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 at March 31, ~~2022~~2023 and December 31, ~~2021.~~2022. 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 accruals on our balance sheet would not be material to our consolidated financial position or results of operations.

We, or our subsidiaries, 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 March 31, ~~2022,~~2023, we are not aware of material indemnity claims pending or threatened against us.

Securities Litigation ~~Matter~~Matters

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 (collectively, the “Defendants”). The complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933 (as amended, the “Securities Act”), and Sections 10(b) and 20(a) of the Exchange Act of 1934 (as amended, the “Exchange Act”), 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 2018 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,

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

~~(Unaudited)~~

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.

On January 21, 2021, multiple plaintiffs filed motions in the Torres Lawsuit seeking to be appointed lead plaintiff and lead counsel. After briefing and a stipulation between the remaining movants, the Court appointed Luis Torres and Allia DeAngelis as co-lead plaintiffs on August 18, 2021. On November 1, 2021, the court-appointed co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended 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. The Defendants filed a Motion to Dismiss on January 24, 2022 and on September 13, 2022, the ~~plaintiffs’~~Court issued an order denying that motion. The case is now in discovery. On February 13, 2023, the plaintiffs filed a motion for class certification, and on April 14, 2023, the defendants filed their ~~opposition~~opposition; the plaintiffs are required to file their reply on ~~April 11, 2022; Defendants’ reply is due on June 6, 2022.~~or before May 30, 2023.

We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the ~~preliminary~~early 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

related securities class action. On January 20, 2023, a second shareholder derivative lawsuit was filed, this time in the United States District Court for the District of Delaware, by putative stockholder Molly Karp allegedly on behalf of the Company, again piggy-backing on the securities class action referenced above. This complaint, similar to the first derivative complaint, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the securities violations alleged in the securities class action. In addition, the complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry’s 2022 Proxy Statement was false and misleading in that it suggested the Company’s internal controls were sufficient and the board of directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case. The defendants believe the claims in the shareholder derivative actions are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to this matter.

In addition, on or around April 17, 2023, the Company received a stockholder litigation demand that the Company’s board of directors investigate and commence legal proceedings against certain current and former officers and directors based ostensibly on the same claims asserted in the derivative actions.

Note 5—Equity

Cash Dividends

~~Our Board of Directors approved a regular cash dividend of $0.06 per share on our common stock for~~In the first quarter of 2023, our Board of Directors declared a quarterly fixed cash dividend totaling $0.06 per share, as well as variable cash dividends of $0.44 per share which was based on the results of the fourth quarter of 2022, for a total of $0.50 per share, which we paid in ~~April 2022.~~March 2023. The Board of Directors approved a ~~$0.06~~$0.12 per share ~~regular~~fixed cash dividend based on ~~our common stock for~~ the ~~second~~results of the first quarter of ~~2022,~~2023, which is expected to be paid in ~~July 2022.~~ May 2023.

The Company anticipates that it will continue to pay quarterly cash dividend in the future. However, the payment and amount of future dividends remain within the discretion of the Board ~~of Directors approved a $0.13 per share variable dividend on our common stock based on our first quarter results, which is expected to be paid in June 2022.~~and will depend upon the Company’s future earnings, financial condition, capital requirements, and other factors.

Stock Repurchase Program

We did not repurchase any shares during the three months ended March 31, 2023. As of March 31, 2023, the Company had repurchased a total of 10,528,704 shares under the stock repurchase program for approximately $104 million. As previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company intends to allocate a portion of Adjusted Free Cash Flow to opportunistic share repurchases.

In ~~April of 2022, our Company’s~~February 2023, the Board of Directors approved an increase of $102 million to the Company’s stock repurchase authorization bringing the Company’s remaining share authority to $200 million. As of March 31, 2023, the Company’s remaining total share repurchase authority ~~to $150~~is $200 million. The Board’s authorization permits the Company to make purchases of its common stock from time to time in the open market and in privately negotiated transactions, subject to market conditions and other factors, up to the aggregate amount authorized by the Board. The Board’s authorization has no expiration date. In 2018 and 2019, the Company repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million in aggregate. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million available under the repurchase program and through December 2021, we repurchased an additional 471,022 shares for approximately $2 million in aggregate. The Company did not repurchase any shares during the three months ended March 31, 2022. Accordingly, as of March 31, 2022, the Company has repurchased a total of 5,528,704 shares under the stock repurchase program for approximately $52 million in aggregate. As discussed in this quarterly report, we implemented a new shareholder return model in early 2022, for which we intend to allocate a portion of Discretionary Free Cash Flow to opportunistic share repurchases.

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 the company to purchase shares during any period or at all. Any shares repurchased are reflected as treasury stock and any shares acquired will be available for general corporate purposes.

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Stock-Based Compensation

In February ~~2022,~~2023, the Company granted awards of approximately ~~1,300,000~~1,031,000 shares of restricted stock units (“RSUs”), which will vest annually in equal amounts over three ~~years. In March 2022, the Company granted awards~~years and a target number of approximately ~~611,000~~437,000 shares of performance-based restricted stock units (“PSUs”), which will cliff vest, if at all, at the end of a three year performance period. The ~~RSUs awarded are equity awards as they will be settled in stock. The PSUs awarded are liability awards as they can be settled in cash or stock. The~~ fair value of these awards was approximately ~~$19 million, of which $8 million relates to liability awards, which will be subsequently remeasured at each reporting period.~~$14 million.

The RSUs awarded in February ~~2022~~2023 are solely time-based awards. Of the PSUs awarded to certain Berry employees (excluding CJWS employee awards) in ~~March 2022,~~February 2023, (a) 50% of such will vest, if at all, based on a total stockholder return (“TSR”) performance metric (the “TSR PSUs”), which is defined as the capital gains per share of stock plus dividends paid assuming reinvestment, with TSR measured on an absolute basis and relative to the TSR of the 44 exploration and production companies in the Vanguard World Fund - Vanguard Energy ETF Index plus the S&P SmallCap 600 Value Index (collectively, the “Peer Group”) during the performance period and (b) 50% of such awards will vest, if at all, based on the consolidated Company's average cash returned on invested capital (“CROIC PSUs”) over the performance period. The PSUs awarded to certain CJWS employees in ~~March 2022~~February 2023 will vest, if at all, based on the CJWS average cash returned on invested capital (“ROIC PSUs”) over the performance 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%~~200% of the target TSR, ~~PSUs granted and from 0% to 200% of the~~ CROIC and ROIC PSUs granted.

The fair value of the RSUs, ~~was determined using the grant date stock price. The fair value of the~~ CROIC PSUs and ROIC PSUs was determined using the grant date stock ~~price and estimated performance as of the reporting period as the awards are liability awards.~~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 ~~Peer Group~~peer group over the performance ~~periods as of the reporting period as the awards are liability awards.~~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:


		March 31, 2022		December 31, 2021			March 31, 2023		December 31, 2022
		(in thousands)					(in thousands)
Prepaid expenses	Prepaid expenses	$	19,702	$	26,840	Prepaid expenses	$	11,495	$	12,330
Materials and supplies	Materials and supplies	9,305		9,533		Materials and supplies	9,813		8,976

Deposits	Deposits	3,720		6,415		Deposits	7,323		7,266

Oil inventories	Oil inventories	2,756		2,933		Oil inventories	4,751		4,036
Other	Other	1,084		225		Other	1,503		1,117
Total other current assets	Total other current assets	$	36,567	$	45,946	Total other current assets	$	34,885	$	33,725

Other non-current assets at March 31, ~~2022 and December 31, 2021,~~2023 included approximately $4$6 million of operating lease right-of-use assets, net of amortization and $5$3 million of deferred financing costs, net of amortization. At December 31, 2022 other non-current assets included approximately $6 million of operating lease right-of-use assets, net of amortization ~~respectively.~~and $4 million of deferred financing costs, net of amortization.

1314

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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


		March 31, 2022		December 31, 2021			March 31, 2023		December 31, 2022
		(in thousands)					(in thousands)
Accounts payable-trade	Accounts payable-trade	$	23,599	$	17,699	Accounts payable-trade	$	31,756	$	40,286
Accrued expenses	Accrued expenses	63,029		62,962		Accrued expenses	54,132		85,360
Royalties payable	Royalties payable	18,373		24,816		Royalties payable	16,093		38,264
Greenhouse gas liability - current portion		6,972		7,513

Taxes other than income tax liability	Taxes other than income tax liability	11,095		8,273		Taxes other than income tax liability	11,236		6,640
Accrued interest	Accrued interest	3,713		10,736		Accrued interest	4,004		10,885
Dividends payable	Dividends payable	4,840		4,800		Dividends payable	2,227		—
Asset retirement obligations - current portion	Asset retirement obligations - current portion	20,000		20,000		Asset retirement obligations - current portion	20,000		20,000
Operating lease liability	Operating lease liability	1,779		—		Operating lease liability	1,615		1,666
Other		684		725

Total accounts payable and accrued expenses	Total accounts payable and accrued expenses	$	154,084	$	157,524	Total accounts payable and accrued expenses	$	141,063	$	203,101

The decrease of $1$2 million in the long-term portion of the asset retirement obligations from ~~$144~~$158 million at December 31, ~~2021~~2022 to ~~$143~~$156 million at March 31, ~~2022~~2023 was due to $5 million of liabilities settled during the period, ~~and a $1 million reduction related to property sales. These decreases were~~ offset by $3 million of ~~accretion and $3 million of liabilities incurred.~~accretion.

Other ~~non-current~~noncurrent liabilities at March 31, ~~2022~~2023 included approximately ~~$17~~$25 million of greenhouse gas liability, which is due in 2024, and $7$5 million of operating lease noncurrent liability. ~~For~~At December 31, ~~2021, we had $18~~2022 other non-current liabilities included approximately $23 million innon-current greenhouse gas liability, which is due 2024, and $5 million of non-current operating lease liability.

Supplemental Information on the Statement of Operations

For the three months ended March 31, 2023, other operating income was less than $1 million. For the three months ended March 31, 2022, other operating expenses ~~was~~were $4 million and mainly consisted of over $2 million in royalty audit charges incurred prior to our emergence and restructuring in 2017, and approximately $1 million loss on the divestiture of the Piceance properties. ~~For the three months ended March 31, 2021, other operating expenses was $1 million and mainly consisted of oil tank storage fees.~~

Supplemental Cash Flow Information

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


		Three Months Ended March 31,					Three Months Ended March 31,
		2022		2021			2023		2022
		(in thousands)					(in thousands)

Supplemental Disclosures of Significant Non-Cash Investing Activities:	Supplemental Disclosures of Significant Non-Cash Investing Activities:					Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties	Material inventory transfers to oil and natural gas properties	$	243	$	1,020	Material inventory transfers to oil and natural gas properties	$	288	$	243
Supplemental Disclosures of Cash Payments (Receipts):	Supplemental Disclosures of Cash Payments (Receipts):					Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	Interest, net of amounts capitalized	$	14,539	$	14,637	Interest, net of amounts capitalized	$	14,388	$	14,539

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 payable and accrued expenses” in the condensed consolidated balance sheets. Such amounts are immaterial as of March 31, 2022 and December 31, 2021.

~~Table of Contents~~

~~BERRY CORPORATION (bry)~~

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

~~(Unaudited)~~

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.

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the three months ended March 31, ~~2022~~2023 and ~~2021~~March 31, 2022, no incremental RSU orand PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the “if converted” method.


		Three Months Ended March 31,					Three Months Ended March 31,
		2022		2021					2023		2022
		(in thousands except per share amounts)				(in thousands except per share amounts)
Basic EPS calculation	Basic EPS calculation							Basic EPS calculation
Net loss	Net loss	$	(56,810)	$	(21,322)			Net loss	$	(5,859)	$	(56,810)

Weighted-average shares of common stock outstanding	Weighted-average shares of common stock outstanding	80,298		80,115				Weighted-average shares of common stock outstanding	76,112		80,298
Basic loss per share	Basic loss per share	$	(0.71)	$	(0.27)			Basic loss per share	$	(0.08)	$	(0.71)
Diluted EPS calculation	Diluted EPS calculation							Diluted EPS calculation
Net loss	Net loss	$	(56,810)	$	(21,322)			Net loss	$	(5,859)	$	(56,810)

Weighted-average shares of common stock outstanding	Weighted-average shares of common stock outstanding	80,298		80,115				Weighted-average shares of common stock outstanding	76,112		80,298
Dilutive effect of potentially dilutive securities(1)	Dilutive effect of potentially dilutive securities(1)	—		—				Dilutive effect of potentially dilutive securities(1)	—		—
Weighted-average common shares outstanding - diluted	Weighted-average common shares outstanding - diluted	80,298		80,115				Weighted-average common shares outstanding - diluted	76,112		80,298
Diluted loss per share	Diluted loss per share	$	(0.71)	$	(0.27)			Diluted loss per share	$	(0.08)	$	(0.71)

__________

(1) We excluded approximately ~~4.1~~3.1 million and ~~2.2~~4.1 million of combined RSUs and PSUs from the dilutive weighted-average common shares outstanding for the three months ended March 31, ~~2022~~2023 and ~~2021,~~2022, because their effect was anti-dilutive.

~~Table of Contents~~

~~BERRY CORPORATION (bry)~~

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

~~(Unaudited)~~

Note 8—Revenue Recognition

We derive revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with additional revenue generated from sales of electricity and marketing activities. ~~Effective October 1, 2021, we completed the acquisition of CJWS, a well servicing and abandonment business.~~ Revenue from CJWS is generated from well servicing and abandonment business.

The following table provides disaggregated revenue for the three months ended March 31, ~~2022~~2023 and ~~2021:~~2022:


		Three Months Ended March 31,					Three Months Ended March 31,
		2022		2021					2023		2022
		(in thousands)				(in thousands)
Oil sales	Oil sales	$	202,724	$	122,359			Oil sales	$	152,134	$	202,724
Natural gas sales	Natural gas sales	5,982		12,077				Natural gas sales	13,543		5,982
Natural gas liquids sales	Natural gas liquids sales	1,645		829				Natural gas liquids sales	680		1,645
Service revenue	Service revenue	39,836		—				Service revenue	44,623		39,836
Electricity sales	Electricity sales	5,419		10,069				Electricity sales	5,445		5,419
Marketing revenues	Marketing revenues	289		2,234				Marketing revenues	—		289
Other revenues	Other revenues	45		137				Other revenues	45		45
Revenues from contracts with customers	Revenues from contracts with customers	255,940		147,705				Revenues from contracts with customers	216,470		255,940
Losses on oil and gas sales derivatives		(161,858)		(53,504)
Gains (losses) on oil and gas sales derivatives								Gains (losses) on oil and gas sales derivatives	38,499		(161,858)
Total revenues and other	Total revenues and other	$	94,082	$	94,201			Total revenues and other	$	254,969	$	94,082

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 9—~~Acquisition and Divestiture~~

~~2022~~

~~Piceance Divestiture~~

~~In January 2022, we completed the divestiture of all of our natural gas properties in Colorado, which were in the Piceance basin. The divestiture closed with a loss of approximately $1 million.~~

~~Antelope Creek Acquisition~~

In February 2022, we completed the acquisition of oil and gas producing assets in the Antelope Creek area of Utah for approximately $18 million. These assets are adjacent to our existing Uinta assets and prior to our acquisition produced approximately 600 boe/d.

~~Note 10—~~Segment Information

~~As of October 1, 2021, we have operated~~We operate in 2two business segments: (i) ~~development and production~~E&P and (ii) well servicing and abandonment. The ~~development and production~~E&P segment is engaged in the ~~development~~exploration and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. ~~On October 1, 2021, we completed the acquisition of an upstream~~The well servicing and abandonment ~~business~~segment is operated by CJWS and provides wellsite services in California ~~which became~~to oil and natural gas production companies, with a ~~reportable segment (well~~focus on well servicing, well abandonment services and water logistics.

The well servicing and ~~abandonment) under U.S. GAAP. Prior~~abandonment segment occasionally provides services to ~~October 1, 2021,~~our E&P segment, as such, we ~~did not have more than 1 reportable segment, thus no prior period segment information has been presented.~~recorded an intercompany elimination of $2 million in revenue and expense during consolidation for the three months ended March 31, 2023. The intercompany elimination was immaterial for the three months ended March 31, 2022.

The following table represents selected financial information for the periods presented regarding the Company's business segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis.

~~Table of Contents~~

~~BERRY CORPORATION (bry)~~

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

~~(Unaudited)~~


	Three Months Ended March 31, 2023
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues(1)	$	171,847	$	46,363	$	(1,740)	$	216,470
Net income (loss) before income taxes	$	24,170	$	2,114	$	(35,056)	$	(8,772)
Adjusted EBITDA	$	75,797	$	5,438	$	(21,898)	$	59,337
Capital expenditures	$	19,272	$	982	$	379	$	20,633
Total assets	$	1,471,679	$	80,897	$	(12,335)	$	1,540,241

Three Months Ended March 31, 2022
Development & Production Well Servicing and Abandonment Corporate/Eliminations Consolidated Company
(in thousands)
Revenues - excluding hedges $ 216,104 $ 39,836 $ — $ 255,940
Net loss before income taxes $ (34,291) $ (284) $ (25,586) $ (60,161)
Adjusted EBITDA $ 105,649 $ 3,300 $ (13,237) $ 95,712
Capital expenditures $ 26,437 $ 628 $ 555 $ 27,620
Total assets $ 1,471,358 $ 73,887 $ (50,518) $ 1,494,727


	Three Months Ended March 31, 2022
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues(1)	$	216,104	$	39,836	$	—	$	255,940
Net loss before income taxes	$	(34,291)	$	(284)	$	(25,586)	$	(60,161)
Adjusted EBITDA	$	105,649	$	3,300	$	(13,237)	$	95,712
Capital expenditures	$	26,437	$	628	$	555	$	27,620
Total assets	$	1,471,358	$	73,887	$	(50,518)	$	1,494,727

__________

(1) These revenues do not include hedge settlements.

Adjusted EBITDA is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources to and assessing performance of each segment. ~~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.~~ Adjusted EBITDA is calculated 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 unusual and infrequent items. While Adjusted EBITDA is a non-GAAP measure, the amounts included in the calculations of Adjusted EBITDA, were computed in accordance with GAAP. This measure is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP and should not be considered as an alternative to, or more meaningful than, income and liquidity measures calculated in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

Three Months Ended March 31, 2022
Development & Production Well Servicing and Abandonment Corporate/Eliminations Consolidated Company
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net loss $ (34,291) $ (284) $ (22,235) (56,810)
Add (Subtract):
Interest expense — — 7,675 7,675
Income tax benefit — — (3,351) (3,351)
Depreciation, depletion, and amortization 35,474 3,179 1,124 39,777
Losses on derivatives 132,804 — — 132,804
Net cash paid for scheduled derivative settlements (32,152) — — (32,152)
Other operating expenses 3,495 174 100 3,769
Stock compensation expense 319 33 3,450 3,802
Non-recurring costs — 198 — 198
Adjusted EBITDA $ 105,649 $ 3,300 $ (13,237) $ 95,712

~~Table of Contents~~

~~BERRY CORPORATION (bry)~~

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

~~(Unaudited)~~

~~Note 11—Leases~~

In the first quarter of 2021, we adopted ASC 842 using the modified retrospective approach that requires us to determine our lease balances as of the date of adoption. Prior periods continue to be reported under accounting standards in effect for those periods.

The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s balance sheet. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. We have long-term operating leases generally for offices. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rate used for the three months ended March 31, 2022 was 5%.

~~Leases with an initial term of 12 months or less are not recorded on the balance sheet and the Company recognizes lease expense for these leases on a straight-line basis over the lease term.~~

~~The following table presents supplemental interim consolidated balance sheet information related to leases as of March 31, 2022.~~


	Three Months Ended March 31, 2022		~~Balance Sheet Classification~~
	~~(in thousands)~~
~~Leases~~
~~Assets~~
~~Operating lease assets~~	$	~~8,045~~	~~Other property and equipment~~
~~Operating lease noncurrent assets~~	~~526~~		~~Other noncurrent assets~~
~~Total assets~~	$	~~8,571~~



~~Liabilities~~
~~Operating lease liability~~	$	~~1,779~~	~~Accounts payable and accrued expenses~~
~~Operating lease noncurrent liability~~	~~6,792~~		~~Other noncurrent liabilities~~
~~Total liabilities~~	$	~~8,571~~


	Three Months Ended March 31, 2022
~~Long-Term and Discount Rate~~
~~Weighted-average remaining lease term:~~

~~Operating Lease~~	~~5.0 years~~
~~Weighted-average discount rate:~~

~~Operating Lease~~	5	%

1817

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

~~The following table presents a schedule~~


	Three Months Ended March 31, 2023
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	24,170	$	2,114	$	(32,143)	$	(5,859)
Add (Subtract):
Interest expense	—		5		7,832		7,837
Income tax benefit	—		—		(2,913)		(2,913)
Depreciation, depletion, and amortization	33,835		3,256		3,030		40,121


Gains on derivatives	(39,109)		—		—		(39,109)
Net cash received for scheduled derivative settlements	47,467		—		—		47,467
Other operating expenses (income)	1,809		(82)		(2,013)		(286)

Stock compensation expense	312		145		4,309		4,766
Non-recurring costs(1)	7,313		—		—		7,313

Adjusted EBITDA	$	75,797	$	5,438	$	(21,898)	$	59,337

__________

(1) Non-recurring costs included executive transition costs and workforce reduction costs in the first quarter of ~~future minimum lease payments required under all operating lease agreements as of March 31, 2022.~~

As of March 31, 2022
Operating Leases
(in thousands)
2022 $ 1,779
2023 1,903
2024 1,603
2025 1,551
2026 1,555
Thereafter 1,213
Total lease payments 9,604
Less imputed interest (1,033)
Total lease obligations 8,571
Less current obligations (1,779)
Long-term lease obligations $ 6,792
2023.


	Three Months Ended March 31, 2022
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net loss	$	(34,291)	$	(284)	$	(22,235)	$	(56,810)
Add (Subtract):
Interest expense	—		—		7,675		7,675
Income tax benefit	—		—		(3,351)		(3,351)
Depreciation, depletion, and amortization	35,474		3,179		1,124		39,777


Losses on derivatives	132,804		—		—		132,804
Net cash paid for scheduled derivative settlements	(32,152)		—		—		(32,152)
Other operating expenses	3,495		174		100		3,769

Stock compensation expense	319		33		3,450		3,802
Non-recurring costs(1)	—		198		—		198

Adjusted EBITDA	$	105,649	$	3,300	$	(13,237)	$	95,712

__________

(1) Non-recurring costs included legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022.

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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 (“MD&A”) 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, ~~2021~~2022 (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) for periods prior to October 1, 2021,~~ Berry Corporation (bry), a Delaware corporation (formerly known as Berry Petroleum Corporation,“Berry Corp.”), together with its ~~subsidiary~~subsidiaries, Berry Petroleum, LLC, a Delaware limited liability company (“Berry LLC”)~~; and (ii) for periods on or after October 1, 2021, Berry Corp. together with its subsidiaries, Berry LLC,~~, CJ Berry Well Services Management, LLC, a Delaware limited liability company (“C&J Management”), and C&J Well Services, LLC, a Delaware limited liability company (“C&J ~~Well Services~~”).

Our Company

We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional ~~oil~~ reserves in the San Joaquin basin of California (100% oil) and the Uinta basin of Utah (oil and gas), with ~~newly acquired~~ well servicing and abandonment capabilities in California. Since October 1, 2021, we have operated in two business segments: (i) ~~development~~exploration and production (“DE&P”) and (ii) well servicing and abandonment. The D&P business segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which now constitutes our well servicing and abandonment segment, also referred to as “CJWS.”

The assets in our DE&P business, in the aggregate, are characterized by high oil content ~~with 100% oil content for our~~(our California assets are 100% oil) and are predominantly located in rural areas with low ~~population.~~population density. 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. The California oil market has primarily Brent-influenced pricing which has ~~recently~~typically realized premium pricing to WTI. All of our California assets are located in the oil-rich reservoirs in the San Joaquin basin, which has more than 150 years of production history and substantial oil remaining in place. As a result of the substantial data produced over the basin’s long history, its reservoir characteristics ~~are well understood, which enables predictable, repeatable,~~and low geological risk ~~and low-cost development opportunities.~~opportunities are well understood. We also have upstream assets in the ~~low-operating cost,~~ oil-rich reservoirs in the Uinta basin of Utah. ~~In January 2022,~~

On October 1, 2021, we ~~divested~~completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which operates as C&J Well Services (“CJWS”) and constitutes our ~~natural gas properties in the Piceance basin of Colorado.~~

well servicing and abandonment segment. CJWS provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics. CJWS’ services include rig-based and coiled tubing-based well maintenance and workover services, recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, CJWS performs plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic growth opportunity for ~~Berry. CJWS is a synergistic fit with~~Berry based on the ~~services required by our oil and gas operations and supports our commitment to be a responsible operator and reduce our emissions, including through the proactive plugging and abandonment~~significant market of wells. Additionally, CJWS is critical to advancing our strategy to work with the State of California to reduce fugitive emissions - including methane and carbon dioxide - from idle wells. There are approximately 35,000 idle wells estimated to be in California according to third-party sources. We believe that CJWS is uniquely positioned to capture both state and federal funds to help remediate orphan idle wells (an idle well that has been abandoned by the operator and as a result becomes a burden of the State is referred to as an orphan well), in addition to helping third-party customers address their idle wells.

Our goal is to continue maximizing shareholder value through overall returns. Since our ~~Initial Public Offering~~initial public offering in July 2018 (“IPO”), we have demonstrated our commitment to maximizing shareholder value and returning a substantial amount of capital to shareholders ~~delivering $139~~through dividends and share purchases. In early February 2023, we updated our shareholder return model, including the plan to double our quarterly fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow. Inclusive of the fixed dividends declared in April 2023, since our IPO, we will have returned $342 million to our shareholders, ~~through~~which represents 311% of our IPO proceeds, consisting of $238 million in fixed and variable dividends and ~~share repurchases through April 30, 2022. In 2022, we initiated a new~~$104 million to repurchase 10.5 million shares, which represents 14% of our outstanding shares as of March 31, 2023.

Our shareholder return model ~~designed~~went into effect January 1, 2022, and we updated the allocations for 2023. Specifically, in 2023, the annual cumulative allocation of Adjusted Free Cash Flow is (a) 80% primarily in the form of opportunistic debt or share repurchases, as well as strategic growth, such as acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors.

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Like our business model, this shareholder return model is simple and demonstrates our commitment to ~~significantly increase cash~~optimize capital allocation and returns to our ~~shareholders from~~shareholders. The model is based on our ~~Discretionary~~Adjusted Free Cash ~~Flow. We define “Discretionary Free Cash~~ Flow,” which is ~~a non-GAAP financial measure,~~defined as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital, which represents the capital expenditures needed to ~~hold~~optimize production ~~flat. This supplemental~~volumes for a given year, is defined as capital expenditures, excluding, when applicable, (i) E&P capital expenditures that are related to strategic business expansion, such as acquisitions of oil and gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes, (ii) capital expenditures in our well servicing and abandonment segment, (iii) corporate expenditures that are related to ancillary sustainability initiatives and/or (iv) other expenditures that are discretionary and unrelated to maintenance of our core business. As part of our strategy, we opportunistically consider bolt-on acquisitions, which contribute to our goal to maintain our existing production volumes (particularly in the current regulatory environment, when there are restrictions on the ability to obtain permits for new drills), and could even moderately grow production. Depending on size, bolt-on acquisitions may be funded in whole or in part from maintenance capital or the 80% portion of our target Adjusted Free Cash Flow allocation.

Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchases,bolt-on acquisitions or other discretionary expenditures, since we have non-discretionary expenditures that are not deducted from this measure. Adjusted Free Cash Flow is a non-GAAP financial ~~measure is used by management, including as described below under “Management’s Discussion and Analysis—How We Plan and Evaluate~~

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~~Operations,” as well as by external users of our financial statements. Please see “Management’s Discussion and Analysis—Non-GAAP~~measure. See “Non-GAAP Financial Measures” for a reconciliation of ~~Discretionary~~Adjusted Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. ~~Like our business model, this new shareholder returns model is simple and further demonstrates our commitment to return capital to our shareholders.~~

We believe that the successful execution of our strategy across our low-declining, oil-weighted production base coupled with extensive inventory of identified drilling locations with attractive full-cycle economics will support our objectives to generate ~~Levered Free Cash Flow to fund~~free cash flow, which funds our operations, ~~optimize~~optimizes capital efficiency and ~~generate Discretionary Free Cash Flow, while maintaining~~maximizes shareholder returns. We also strive to maintain a low leverage profile and ~~focusing on~~explore attractive organic and strategic growth through commodity price cycles. “Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less capital expenditures, interest expense and dividends. “Adjusted EBITDA” is also 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 and infrequent items. These supplemental non-GAAP financial measures are used by management, including as described below under “Management’s Discussion and Analysis—How We Plan and Evaluate Operations,” as well as by external users of our financial statements. Please see “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for reconciliations of Levered Free Cash Flow and Adjusted EBITDA to net cash provided by operating activities and of Adjusted EBITDA to net income (loss), our most directly comparable financial measures calculated and presented in accordance with GAAP.

~~We have a progressive approach to growing and evolving our businesses 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 the utility of our assets, create value for shareholders, and support environmental goals that align with ~~safe,~~safer, more efficient and lower emission operations. As part of our commitment to creating long-term value for our ~~stockholders,~~shareholders, we are dedicated to conducting our operations in an ethical, safe and responsible manner, to protecting the environment, and to taking care of our people and the communities in which we live and operate. We believe that oil and gas will remain an important part of the energy landscape going forward and our goal is to conduct our business safely and responsibly, while supporting economic stability and social equity through engagement with our stakeholders. We recognize the oil and gas industry’s role in the energy transition and advocate a co-existence between renewable and conventional energy. We are ~~determined~~committed to bebeing part of the ~~solution.~~energy transition solution by continuing to provide safe, reliable, and affordable energy to our communities.

How We Plan and Evaluate Operations

We use the following metrics to manage and assess the performance of our operations: (a) ~~Levered Free Cash Flow;~~Adjusted EBITDA; (b) Adjusted ~~EBITDA; (c) Discretionary~~ Free Cash Flow for shareholder returns; (c) production from our E&P business (d) ~~operating expenses;~~E&P field operations measures; (e) ~~environmental, health & safety (“EH&S”)~~HSE results; (f) general and administrative expenses; ~~(g) production from our D&P business;~~ and ~~(h)~~(g) the performance of our well servicing and abandonment operations based on activity levels, pricing and relative performance for each service provided.

~~Levered Free Cash Flow~~

We use “Levered Free Cash Flow” in planning our capital allocation to sustain production levels and fund internal growth opportunities, as well as determine our strategic hedging needs. We also hedge to meet the hedging requirements of the 2021 RBL Facility. 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.

Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of both our DE&P business and CJWS. We also use Adjusted EBITDA in planning our capital allocation to sustain production levels and determining our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility (defined below in “—Liquidity and Capital Resources”). Adjusted EBITDA is a non-GAAP financial measure that we define as earnings before interest expense; income taxes; depreciation, depletion, and amortization (“DD&A”); derivative gains or losses net of cash received or paid

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for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items.

~~Table~~ See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for a reconciliation of ~~Contents~~

Adjusted EBITDA to net (loss) income and to net cash provided by operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP. This supplemental non-GAAP financial measure is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.

Shareholder Returns

~~In early~~Commencing in 2022, we implemented a ~~new~~ shareholder return model ~~in accordance with which we intend to allocate a significant portion of Discretionary Free Cash Flow to pay variable quarterly cash dividends. The model is~~ based on our ~~Discretionary~~Adjusted Free Cash Flow, which is a non-GAAP measure that we define as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital represents the capital expenditures needed to ~~hold~~maintain substantially the same volume of annual oil and gas production ~~flat. We expect remaining Discretionary~~and is defined as capital expenditures, excluding, when applicable, E&P capital expenditures that are related to strategic business expansion, such as acquisitions of oil and gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes and capital expenditures in our well servicing and abandonment segment and corporate expenditures that are related to ancillary sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. Adjusted Free Cash Flow ~~will~~does not represent the total increase or decrease in our cash balance, and it should not be ~~allocated to fund opportunistic~~inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt ~~repurchases, opportunistic growth (including from our extensive inventory of drilling opportunities), advancing our short- and long-term sustainability initiatives,~~or share repurchases, ~~and/~~bolt-on acquisitions or ~~capital retention. See “Management’s Discussion and Analysis—~~other discretionary expenditures, since we have non-discretionary expenditures that are not deducted from this measure. Refer to “—Non-GAAP Financial Measures” for a reconciliation of ~~Discretionary~~Adjusted Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP.

Under our shareholder return model, which was revised in February 2023, we plan to pay a fixed dividend of $0.12 per quarter. We also modified the allocations of Adjusted Free Cash Flow to be (a) 80% primarily in the form of opportunistic debt or share repurchases, as well as strategic growth, such as acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors.

Our focus on shareholder returns is also demonstrated through our performance-based restricted stock awards, which ~~are~~include performance metrics based on the Company's average cash returned on invested capital and total stockholder return on both a relative and absolute basis. Our short-term incentive plan also includes Adjusted Free Cash Flow performance goals.

~~Operating Expenses~~

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.

E&P Field Operations

Overall, management assesses the efficiency of our E&P field operations by considering core E&P operating ~~expense~~expenses together with our cogeneration, marketing and transportation activities. In particular, a core component of our E&P operations in California is ~~used by management as a measure~~steam, which we use to lift heavy oil to the surface. We operate several cogeneration facilities to produce some of the steam needed in our operations. In comparing the cost effectiveness of our cogeneration plants against other sources of steam in our operations, management considers the cost of operating the cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the steam and electricity used in our E&P field operations and the revenues we receive from sales of excess electricity to the grid. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural gas purchase hedges. Consequently, the efficiency ~~with which~~of our E&P field operations are ~~performing.~~impacted by the cash

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settlements we receive or pay from these derivatives. We also have contracts for the transportation of fuel gas from the Rockies which has historically been cheaper than the California markets. With respect to our D&P business, 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~~management also considers opportunistic sales of incremental capacity in assessing the ~~effect~~overall efficiencies of ~~derivative settlements (received or paid) for gas purchases.~~ E&P operations.

Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. ~~Taxes~~Electricity generation expenses include the portion of fuel, labor, maintenance, and tools and supplies from two of our cogeneration facilities allocated to electricity generation expense; the remaining cogeneration expenses are included in lease operating expense. Transportation expenses relate to our costs to transport the oil and gas that we produce within our properties or move it to the market. Marketing 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. Electricity revenue is from the sale of excess electricity from two of our cogeneration facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are sized to satisfy the steam needs in their respective fields, but the corresponding electricity produced is more than the electricity that is currently required for the operations in those fields. Transportation sales relate to water and other ~~than income taxes~~liquids that we transport on our systems on behalf of third parties and ~~costs of services are excluded from operating expenses. Marketing~~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 California steam operations with gas hedges, and more recently agreements to transport fuel gas from the Rockies which have historically been cheaper than the California markets.parties

~~Environmental,~~ Health, Safety & ~~Safety (EH&S)~~Environmental

Like other companies in the oil and gas industry, the operations of both our DE&P business and CJWS are subject to complex federal, state and local laws and regulations that govern health and safety, the release or discharge of materials, and land use or environmental protection that may restrict the use of our properties and operations, increase our costs or lower demand for or restrict the use of our products and services. Please see ~~“Management’s Discussion and Analysis—~~“—Regulatory Matters” in this quarterly report as well as ~~“Part~~Part I, Item 1 “Regulatory Matters” and Part I, Item 1A. “Risk Factors” in our Annual Report for a discussion of the potential impact that government regulations, including those regarding ~~EH&S~~HSE matters, may have upon our business, operations, capital expenditures, earnings and competitive position.

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~~HSE performance through various measures, and we hold our employees and contractors to high standards. Meeting corporate ~~EH&S~~HSE metrics, including with respect to ~~EH&S~~HSE incidents and spill prevention, is a part of our short-term incentive program for all employees.

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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 10% of such costs are capitalized, which we believe is significantly less than industry norms.~~activities. 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.

~~Production~~

Well Servicing and Abandonment Operations Performance

We consistently monitor our well servicing and abandonment operations performance with revenue and cost by service and customer, as well as Adjusted EBITDA for this business.

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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, including ~~the~~ differentials, ~~between the relevant benchmarks and the prices we receive for our oil and natural gas production in our D&P business,~~which have ~~fluctuated,~~ and may continue to, fluctuate significantly as a result of numerous market-related variables, including global geopolitical, economic conditions, and ~~economic conditions. While oil~~local and regional market factors and dislocations. Oil prices slightly decreased in the first quarter of 2023 and they have ~~improved in 2022, they still~~remained, and may continue to remain, volatile.

Our well ~~servicing~~services and abandonment business is dependent on expenditures of oil and gas companies, which ~~tend to fluctuate~~can in ~~line with~~part reflect the volatility of commodity prices. ~~However, because~~Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells historically have been relatively stable and predictable. Additionally, our customers' requirements to plug and abandon wells are largely driven by regulatory requirements ~~which are not~~that is less dependent on commodity prices.

~~Brent prices trended higher~~Currently, global oil inventories are low relative to historical levels and supply from OPEC+ and other oil producing nations are not expected to be sufficient to meet forecasted oil demand growth, including for transportation, for the ~~three months ended March 31,~~foreseeable future. It is believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected levels due to their lack of capital investments in developing incremental oil supplies over the past few years. In October 2022, ~~as compared~~OPEC+ determined to ~~the three months ended~~reduce production beginning in November 2022 through December ~~31, 2021 and March 31, 2021, reflecting a premium~~2023 by 2 million bbls per day, due to the ~~reduction~~uncertainty surrounding the global economic and oil market outlooks. OPEC+ took further action in ~~crude~~early April 2023 to reduce production by approximately 1.7 million bbls per day through December 2023. Furthermore, sanctions and import bans on Russian oil ~~supply resulting from sanctions imposed on Russia~~have been implemented by various countries in response to ~~its large-scale invasion~~the war in Ukraine, further impacting global oil supply. Still, oil and natural gas prices have recently declined from the highs experienced in the first half of ~~Ukraine in February~~ 2022 and ~~building on the ongoing recovery~~could decrease or increase with any changes in ~~the oil and gas industry in early 2022 due to increasing~~ demand as more states and countries re-open and national and global economies continue to recover from the global COVID-19 pandemic. The demand for oil, while improving as the ability of the global industry to grow supply diminishes and so long as exports from Russia are subject to sanctions, could again decline due to, among other things, ~~uncertainty and volatility arising from~~China lifting COVID-19 restrictions in December 2022, the ongoing conflict in Ukraine, ~~release of~~international sanctions, ~~on Russia,~~speculation as to future actions by OPEC+, developing COVID-19 variants and the potential for a widespread ~~resurgence~~COVID-19 outbreak, higher gas prices, inflation and government efforts to reduce inflation, and possible changes in the overall health of the ~~COVID-19 outbreak or increasing inflation.~~global economy, including a prolonged recession. Further, the volatility in oil and natural gas prices ~~driven by the conflict between Russia and Ukraine~~ could accelerate ~~the~~a transition away from fossil fuels, resulting in reduced demand over the longer term. The extent to which our operating and financial results of future periods will be adversely impacted by the ongoing conflict in Ukraine, increasing inflation, the 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, toTo what extent these ~~events do~~and other external factors (such as government action with respect to climate change regulation) ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors, including future developments, that are not within our control and cannot be ~~predicted, including~~accurately predicted.

In the ~~duration~~past few years, there have been numerous global events that have greatly impacted the oil and ~~extent~~gas environment, such as the COVID-19 pandemic, the impacts of the ~~conflict~~Russia and Ukraine war, and OPEC+’s actions. The COVID-19 pandemic resulted in ~~Ukraine, government action~~a severe decrease in demand for oil, which created significant volatility and uncertainty in the oil and gas industry beginning in 2020. When combined with ~~respect to climate change regulation,~~an excess supply of oil and related products, oil prices declined significantly in the first half of 2020. Although there has been some volatility, overall oil prices have steadily improved since the lows experienced in 2020, in line with increasing ~~inflation~~demand despite the ongoing pandemic and ~~international sanctions and speculation as to future actions by OPEC+.~~

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uncertainties surrounding the COVID-19 variants.

Commodity Pricing and Differentials

Our revenue, costs, profitability, shareholder returns 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 I, Item 1A. “Risk Factors” in our Annual Report. We utilize derivatives 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.

Average Brent oil prices, as noted below, ~~were higher~~decreased by $6.47, or 7% for the three months ended March 31, ~~2022~~2023 compared to the three months ended December 31, ~~2021~~2022 and decreased by $15.74, or 16% compared to the three months ended March 31, ~~2021.~~2022. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand ~~dynamics.~~dynamics, including third-party transportation and

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market takeaway infrastructure capacity.

For our California steam operations, the price we pay for fuel gas purchases is generally based on the Northwest, Rocky Mountains index for the purchases made in the Rockies and the SoCal Gas city-gate index for the purchases made in California. We currently buy most of our gas in the Rockies. Now that we are purchasing a majority of our fuel gas in the Rockies, most of the purchases made in California use the SoCal Gas city-gate index, whereas prior to this shift the predominant index for California purchases was Kern, ~~Delivered Index, which~~Delivered. The price from the Northwest, Rocky Mountain index was as high as ~~$8.00~~$49.57 per mmbtu and as low as ~~$3.70~~$5.07 per mmbtu ~~during~~in the first quarter of 2023. The price from the SoCal Gas city-gate index was as high as $54.31 per mmbtu and as low as $6.93 per mmbtu in the first quarter of 2023. Overall, we paid an average of $20.74 per mmbtu in the first quarter of 2023, excluding the positive impact of our gas purchase hedges. The price we paid on average increased by $11.12 per mmbtu, or 116% and $14.44 per mmbtu, or 229% for the first quarter of 2023, compared to the fourth quarter of 2022 and the first quarter of 2022, ~~while~~respectively. When including hedging effects in our gas purchases, we paid ~~an average of $6.30~~$8.88, $7.34 and $6.01 per mmbtu in ~~this period.~~the first quarter of 2023, the fourth quarter of 2022, and the first quarter of 2022, respectively.

The following table presents the average Brent, WTI, ~~Kern, Delivered,~~SoCal Gas city-gate, Northwest, Rocky Mountains, and Henry Hub prices for the three months ended March 31, ~~2022,~~2023, December 31, ~~2021~~2022 and March 31, ~~2021:~~2022.


		Three Months Ended						Three Months Ended
		March 31, 2022		December 31, 2021		March 31, 2021				March 31, 2023		December 31, 2022		March 31, 2022
Oil (bbl) – Brent	Oil (bbl) – Brent	$	97.90	$	79.66	$	61.32		Oil (bbl) – Brent	$	82.16	$	88.63	$	97.90
Oil (bbl) – WTI	Oil (bbl) – WTI	$	94.54	$	76.89	$	57.82		Oil (bbl) – WTI	$	76.15	$	82.51	$	94.54
Natural gas (mmbtu) – Kern, Delivered		$	4.83	$	5.65	$	7.99
Natural gas (mmbtu) – SoCal Gas city-gate									Natural gas (mmbtu) – SoCal Gas city-gate	$	24.81	$	9.71	$	6.74
Natural gas (mmbtu) – Northwest, Rocky Mountains									Natural gas (mmbtu) – Northwest, Rocky Mountains	$	22.36	$	7.54	$	5.76
Natural gas (mmbtu) – Henry Hub	Natural gas (mmbtu) – Henry Hub	$	4.67	$	4.75	$	3.50		Natural gas (mmbtu) – Henry Hub	$	2.64	$	5.55	$	4.67

As mentioned above, California oil prices are Brent-influenced as California refiners import approximately ~~70%~~75% 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~~ 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. Our key exposure to gas prices is in our costs. We purchase substantially more natural gas for our California steamfloods and cogeneration facilities than we produce and sell in the Rockies. In ~~recent history,~~May 2022, we began purchasing most of our gas in the Rockies and transporting it to our California ~~gas markets have generally had higher gas prices than~~operations using our Kern River pipeline capacity. We buy approximately 48,000 mmbtu/d in the Rockies, and the ~~rest of~~remainder comes from California markets. The volume purchased in California fluctuates and averaged 3,000 mmbtu/d in Q1 2023, 12,000 mmbtu/d in Q4 2022 and 16,000 mmbtu/d in Q1 2022. The natural gas we purchase in the ~~United States. Higher~~Rockies is shipped to our operations in California to help limit our exposure to California fuel 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~~purchase price fluctuations. We strive to ~~third parties at prices linked to the price of natural gas. We also strive to~~further minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of ~~such~~our gas purchases. In addition, we have entered into pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that help 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.

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Our current expectations are that natural gas prices in the western US will remain elevated in 2023 relative to the rest of the US. Our hedging strategy coupled with our midstream access to gas from the Rockies, also helps us mitigate the impact of high natural gas prices on our cost structure.

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.

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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 two of our cogeneration facilities under ~~long-term~~ contracts with terms ending in ~~July 2022 through~~ December 2023 and November 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, most notably in June through September, due to negotiated capacity payments we receive.

Additionally, like other companies in the oil and gas industry, our operations are subject to 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. Federal, state and local agencies may assert overlapping authority to regulate in these areas. For more information related to regulatory risks, see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry” in our Annual Report.

Regulatory Matters

Like other companies in the oil and gas industry, both our DE&P business and CJWS are subject to complex and stringent federal, state, and local laws and regulations, and California, where most of our operations and assets are located, is one of the most heavily regulated states in the United States with respect to oil and gas operations. A combination of federal, state and local laws and regulations govern most aspects of our activities in California. Collectively, the effect of the existing laws and regulations is to ~~potentially~~ limit the number and location of our wells through restrictions on the use of our properties, limit our ability to develop certain assets and conduct certain operations, including through a restrictive and ~~reduce~~burdensome permitting and approval process, and regulate the amount of oil and natural gas that we can produce from our wells, potentially reducing below levels that would otherwise be possible. Additionally, the regulatory burden on the industry ~~increases our~~in the past has and in the future could result in increased costs and consequently may have an adverse effect upon operations, capital expenditures, earnings and our competitive position. Violations and liabilities with respect to these laws and regulations could also result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and future prospects. Our operations in California are particularly exposed to increased regulatory risks given the stringent environmental regulations imposed on the oil and gas industry, and current political and social trends in California continue to increase limitations on and impose additional permitting, mitigation, and emission control obligations, amongst others, upon the oil and gas industry. We cannot predict what new environmental laws or regulations California may impose upon our operations in the future; however, any such future laws or regulations could materially and adversely impact our business and results of operations. For additional information about the potential impact that government regulations, including those regarding environmental matters, may have upon our business, operations, capital expenditures, earnings and competitive position, please see Part I, Item 1 “Regulatory Matters,” as well as Part I, Item 1A. “Risk Factors” in our Annual Report.

~~Our oil and gas operations in California are subject to compliance with~~On September 16, 2022, the California ~~Environmental Quality Act (“CEQA”), and we cannot receive~~Governor signed into law Senate Bill No. 1137 which prohibits CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or rework is within 3,200 feet of certain ~~permits and other approvals required for our operations until we have demonstrated compliance with CEQA. There have been~~sensitive receptors such as homes, schools or parks effective January 1, 2023. In December 2022, proponents of a voter referendum (the Referendum) collected more than the requisite number of developments at both the California state and local levels that have resulted in delays in the issuance of new drilling permits for oil and gas activities in Kern County where all of our California assets are located, as well as a more time- and cost- intensive permitting process. Most notably, in Kern County, we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (an “EIR”) covering oil and gas operations in Kern County (“Kern County EIR”). In 2020, a lawsuit was filed challenging the Kern County EIR, and subsequently the California Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR until Kern County made certain revisionssignatures required to the Kern County EIR and recertified it (“Kern County Ruling”). To address the Kern County Ruling, Kern County elected to prepare a supplemental EIR which was approved by the Kern County Board of Supervisors in March 2021. Following further challenges by plaintiffs, a Kern County Superior Court judge suspended use of the Kern County EIR as supplemented, stopping the issuance of new oil and gas permits by Kern County (the “Kern County Permit Suspension”) in October 2021, pending a determination by the Kern County Superior Court that the Kern County EIR complied with the CEQA requirements. A hearingput Senate Bill No. 1137 on the ~~challenge to~~2024 ballot. On February 3, 2023, the ~~EIR is scheduled in Kern County Superior Court for May 26, 2022. We cannot predict~~Secretary of State of California certified the ~~outcome of this hearing or whether it will result in the imposition of more onerous permit requirements or other requirements or restrictions on land use and exploration and production activities.~~

Importantly, neither the Kern County Ruling nor the Kern County Permit Suspension invalidated existing permits and our plans and operations have not been materially impacted to date. Until Kern County is able to resolve the challenges regarding the sufficiency of the Kern County EIR and resume the ability to issue permits, our ability to obtain new permits and approvals to enable our future plans in Kern County requires demonstrating to CalGEM compliance with CEQA. Demonstrating CEQA compliance without being able to reference the Kern County EIR or another CEQA-compliant EIR is a more technically, time and cost intensive process and may, among other things, require that we conduct an environmental impact review. As a result, we together with other Kern County operators

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~~have experienced delays in~~signatures and confirmed that the issuance of permits for new wells by CalGEM, as well as a more time- and cost- intensive permitting process. We have, however, received a number of permits to drill new wells in areas covered by a previously conducted CEQA analysis. We believe that we have sufficient permit inventory (that is, permits in hand) to support our drilling plans for new wells into June 2022, and we have submitted permit applications to facilitate our full 2022 drilling plans for new wells. We have not experienced delays in the issuance of permitsReferendum qualifies for the ~~workover~~November 2024 ballot. Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote, although any stay could be delayed if there are legal challenges to the Secretary of ~~existing wells.~~

~~Approximately 6%~~State’s certification. Relatedly, a legislator recently introduced Senate Bill No. 556 into the California Senate providing for joint and several liability for operators and owners of ~~our current 2022~~an entity that owns an oil and gas production ~~plans is expected~~facility for certain adverse health conditions in a setback zone, subject to ~~come from~~limited defenses. Senate Bill No. 556 also provides for civil penalties to be assessed against potentially responsible parties. We continue to assess the ~~drilling~~impacts of new wells, which requires the issuance of new permits and extensive environmental review. Approximately 4% of our 2022 production is expected to come from the workover of existing wells, for which we have continued to receive permitsSenate Bill No. 1137 and the ~~environmental review is expedited because the well already exists. Our existing producing wells are expected~~potential impacts of Senate Bill No. 556, to ~~contribute the other 90%, what we call our base production. Our drilling plans for the remainder of the year, and therefore our current 2022 production goals, may be impacted by~~include our ability to ~~timely obtain~~operate and any increased exposure to liability.

Inflation

The U.S. inflation rate increased throughout much of 2022. The Company, similar to other companies in our industry, has experienced inflationary pressures on our costs - namely inflationary pressures have resulted in increases to the ~~required permits~~costs of our goods, services and ~~approvals~~personnel, which in turn, have caused our capital expenditures and operating costs to ~~support those planned activities, particularly if there are further delays~~rise. Such inflationary pressures have resulted from supply chain disruptions caused by the COVID pandemic, increased demand, labor shortages and other factors, including the conflict between Russia and the Ukraine which began in ~~or new restrictions imposed upon~~late February 2022. In late 2022 and early 2023, inflation rates began to stabilize and even decrease from the ~~issuance or renewal of permits and approvals required for oil and gas activities~~levels experienced earlier in ~~Kern County. If we~~2022. We are unable to ~~obtain~~accurately predict if such inflationary pressures and contributing factors will continue through 2023. However, as of March 31, 2023, we determined there has not been any material changes in inflationary pressures since the permits required to support our current 2022 drilling plans, we may modify our drilling plans and production goals, and reduce our planned capital expenditures or deploy that capital to other activities.year ended December 31, 2022.

Seasonality

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

~~Natural gas prices fluctuate based on seasonal and other market-related impacts.~~ For example, during the first quarter of 2023, we experienced an increase in costs, production downtime and transportation delays due to the unprecedented snowy and rainy weather in Utah and California. Unusually heavy rains caused flooding and power outages which adversely impacted our ability to operate in California, while Utah was impacted by historic snowfall.

Among other factors, extreme cold weather conditions drove high natural gas prices ~~increased significantly~~ in the first quarter of ~~2022 reflecting a premium driven by European instability which brought new demand for domestic production as a way~~2023. We seek to replace natural gas previously produced by Russia, as well as lower storage levels.We purchase significantly more gas than we sell to generate steam and electricity in our cogeneration facilities for our production activities in our D&P business. As a result, our key exposure to gas prices is in our costs. We mitigate a substantial portion of ~~this~~the gas purchase exposure for our cogeneration plants by selling excess electricity from our cogeneration operations to third ~~parties. The pricing of these electricity sales is closely tied~~parties at prices linked to the ~~purchase~~ price of natural gas. ~~These~~Aside from the impact gas prices have on electricity prices, 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~~Our hedging strategy coupled with our midstream access to ~~consume and in 2021 we entered into new pipeline capacity agreements for the shipment of natural~~ gas from the Rockies toalso helps mitigate the impact of the high natural gas prices on our ~~operations in California to help limit our exposure to fuel gas purchase price fluctuations.~~cost structure.

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Capital Expenditures

For the three months ended March 31, ~~2022,~~2023 our ~~consolidated~~total capital expenditures were approximately ~~$28~~$21 million, ~~on an accrual basis~~ including capitalized overhead and interest and excluding acquisitions and asset retirement spending. E&P and corporate expenditures were $20 million for the three months ended March 31, 2023 (excluding well servicing and abandonment capital of $1 million). Approximately ~~53%~~92% and ~~35%~~8% of these capital expenditures for the three months ended March 31, ~~2022 was~~2023 were directed to California ~~oil~~ and Utah operations, respectively.

Our ~~2022~~2023 capital expenditure budget for DE&P operations and corporate activities is ~~approximately $125~~between $95 to ~~$135~~$105 million, ~~excluding $8 million for C&J Well Services,~~ which we expect will ~~keep our annual~~result in a slight decline in production ~~flat. We~~year over year. Based on activity to date and expected for the remainder of 2022, we currently anticipate ~~oil production~~our full year capital expenditures will be ~~approximately 92%~~slightly more than our initial budget and will be between $140 and $145 million. We have adjusted our planned California capital program in late 2022 based on the success of ~~total production volume in 2022, compared to 88% in 2021. Based on current commodity prices and~~recent development activity. To keep up the momentum into 2023, we are accelerating our ~~drilling success rate to date, we expect to be able to fund our 2022 capital~~ development ~~programs with cash flow from operations. The execution~~program during the fourth quarter of ~~these plans requires that we timely obtain certain regulatory permits and approvals, which we may not be able to obtain on a timely basis or at all.~~

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~~The amount and timing of capital expenditures are within our control and subject to our discretion, and~~2022. Additionally, due to the ~~speed with~~results achieved from mid-year workover and recompletion activity in Utah, we allocated incremental funding to perform additional workovers in Utah. The increase in full-year capital expenditures is also partially due to cost inflation in excess of our initial expectations, which we ~~are able~~began 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 attractive ratesexperience mid-year.

Exclusive of return. We believe it is important to retain the flexibility to defer planned capital expenditures 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 ~~2022,~~2023, we plan to spend approximately $21 million to $24 million on plugging and abandonment activities, ~~including 280 to 320 wells and satisfying~~exceeding our annual ~~obligations~~obligation requirements under ~~the~~ California ~~Idle Well Management Program.~~idle well management plan. We spent approximately $5 million for plugging and abandonment activities in the first quarter of 2022. Our well servicing and abandonment segment expects to plug and abandon approximately 2,000 wells for their third party customers in 2022, helping to safely address the environmental hazards and others risk from California’s number of idle wells.three months ended March 31, 2023.

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~~Summary by Area~~

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

California
(San Joaquin and Ventura basins)(3)
Three Months Ended
March 31, 2022 December 31, 2021 March 31, 2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales $ 186,252 $ 158,317 $ 113,177
Operating income(1)
$ 60,162 $ 17,217 $ 18,965
Depreciation, depletion, and amortization (DD&A) $ 35,786 $ 35,647 $ 32,896
Average daily production (mboe/d) 22.2 22.7 21.9
Production (oil % of total) 100 % 100 % 100 %
Realized sales prices:
Oil (per bbl) $ 93.16 $ 75.90 $ 57.34
NGLs (per bbl) $ — $ — $ —
Gas (per mcf) $ — $ — $ —
Capital expenditures(2)
$ 14,622 $ 22,596 $ 22,760

Utah
(Uinta basin)
Colorado
(Piceance basin)(4)
Three Months Ended Three Months Ended
March 31,
2022 December 31,
2021 March 31,
2021 March 31,
2022 December 31,
2021 March 31,
2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales $ 23,038 $ 19,762 $ 15,889 $ 1,056 $ 3,294 $ 6,194
Operating income(1)
$ 11,173 $ 8,713 $ 7,433 $ 610 $ 3,050 $ 5,039
Depreciation, depletion, and amortization (DD&A) $ 803 $ 597 $ 554 $ 9 $ 38 $ 38
Average daily production (mboe/d) 4.1 4.2 4.0 0.4 1.0 1.2
Production (oil % of total) 53 % 51 % 49 % — % 1 % 2 %
Realized sales prices:
Oil (per bbl) $ 83.02 $ 66.56 $ 52.08 $ 89.41 $ 84.38 $ 25.80
NGLs (per bbl) $ 47.03 $ 47.45 $ 26.81 $ — $ — $ —
Gas (per mcf) $ 5.93 $ 5.63 $ 6.65 $ 5.12 $ 5.54 $ 9.83
Capital expenditures(2)
$ 9,752 $ 1,007 $ 392 $ — $ — $ 1

~~__________~~

(1) Operating income (loss) includes oil, natural gas and NGL sales, marketing revenues, other revenues, 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.~~

~~(3) Our Placerita properties, in the Ventura basin, were divested in October 2021.~~

~~(4) Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.~~

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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						Three Months Ended
		March 31, 2022		December 31, 2021		March 31, 2021				March 31, 2023		December 31, 2022		March 31, 2022
Average daily production:(1)	Average daily production:(1)								Average daily production:(1)
Oil (mbbl/d)	Oil (mbbl/d)	24.4		24.8		23.9			Oil (mbbl/d)	22.6		24.1		24.4
Natural Gas (mmcf/d)	Natural Gas (mmcf/d)	11.5		16.4		16.9			Natural Gas (mmcf/d)	8.7		7.8		11.5
NGL (mbbl/d)	NGL (mbbl/d)	0.4		0.4		0.3			NGL (mbbl/d)	0.2		0.4		0.4
Total (mboe/d)(2)	Total (mboe/d)(2)	26.7		27.9		27.1			Total (mboe/d)(2)	24.3		25.8		26.7
Total Production:	Total Production:								Total Production:
Oil (mbbl)	Oil (mbbl)	2,198		2,281		2,151			Oil (mbbl)	2,037		2,219		2,198
Natural gas (mmcf)	Natural gas (mmcf)	1,037		1,496		1,517			Natural gas (mmcf)	779		716		1,037
NGLs (mbbl)	NGLs (mbbl)	35		36		31			NGLs (mbbl)	20		33		35
Total (mboe)(2)	Total (mboe)(2)	2,406		2,566		2,435			Total (mboe)(2)	2,187		2,371		2,406
Weighted-average realized sales prices:	Weighted-average realized sales prices:								Weighted-average realized sales prices:
Oil without hedges ($/bbl)	Oil without hedges ($/bbl)	$	92.25	$	75.11	$	56.89		Oil without hedges ($/bbl)	$	74.69	$	80.61	$	92.25
Effects of scheduled derivative settlements ($/bbl)	Effects of scheduled derivative settlements ($/bbl)	$	(15.38)	$	(20.50)	$	(12.08)		Effects of scheduled derivative settlements ($/bbl)	$	(3.65)	$	(7.22)	$	(15.38)
Oil with hedges ($/bbl)	Oil with hedges ($/bbl)	$	76.87	$	54.61	$	44.81		Oil with hedges ($/bbl)	$	71.04	$	73.39	$	76.87
Natural gas ($/mcf)	Natural gas ($/mcf)	$	5.77	$	5.60	$	7.96		Natural gas ($/mcf)	$	17.39	$	12.02	$	5.77
NGL ($/bbl)	NGL ($/bbl)	$	47.03	$	47.45	$	26.81		NGL ($/bbl)	$	34.10	$	29.67	$	47.03
Average Benchmark prices:	Average Benchmark prices:								Average Benchmark prices:
Oil (bbl) – Brent	Oil (bbl) – Brent	$	97.90	$	79.66	$	61.32		Oil (bbl) – Brent	$	82.16	$	88.63	$	97.90
Oil (bbl) – WTI	Oil (bbl) – WTI	$	94.54	$	76.89	$	57.82		Oil (bbl) – WTI	$	76.15	$	82.51	$	94.54
Natural gas (mmbtu) – Kern, Delivered(3)		$	4.83	$	5.65	$	7.99
Natural gas (mmbtu) – SoCal Gas city-gate(3)									Natural gas (mmbtu) – SoCal Gas city-gate(3)	$	24.81	$	9.71	$	6.74
Natural gas (mmbtu) – Northwest, Rocky Mountains(4)									Natural gas (mmbtu) – Northwest, Rocky Mountains(4)	$	22.36	$	7.54	$	5.76
Natural gas (mmbtu) – Henry Hub(4)	Natural gas (mmbtu) – Henry Hub(4)	$	4.67	$	4.75	$	3.50		Natural gas (mmbtu) – Henry Hub(4)	$	2.64	$	5.55	$	4.67

__________

(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 based on energy content of six mcf of gas to one 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 March 31, ~~2022,~~2023, the average prices of Brent oil and Henry Hub natural gas were ~~$97.90~~$82.16 per bbl and ~~$4.67~~$2.64 per mmbtu.

(3) ~~Kern, Delivered~~The natural gas we purchase to generate steam and electricity is primarily based on Rockies price indexes, including transportation charges, as we currently purchase a substantial majority of our gas needs from the Rockies, with the balance purchased in California at various California indices. SoCal Gas city-gate Index is the relevant index used only for the portion of gas purchases in California. Now that we are purchasing a majority of our fuel gas in the Rockies, most of the purchases made in California utilize the SoCal Gas city-gate index, whereas prior to this shift the predominant index for California purchases were Kern, Delivered.

(4) Northwest, Rocky Mountains and Henry Hub isare the relevant ~~index~~indices used for gas purchases and sales, respectively, in the Rockies.

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


		Three Months Ended				Three Months Ended
		March 31, 2022	December 31, 2021	March 31, 2021		March 31, 2023	December 31, 2022	March 31, 2022
Average daily production (mboe/d):(1)	Average daily production (mboe/d):(1)				Average daily production (mboe/d):(1)
California	California	22.2	22.7	21.9	California	19.9	21.1	22.2
Utah(2)	Utah(2)	4.1	4.2	4.0	Utah(2)	4.4	4.7	4.1
Colorado(3)	Colorado(3)	0.4	1.0	1.2	Colorado(3)	—	—	0.4

Total average daily production	Total average daily production	26.7	27.9	27.1	Total average daily production	24.3	25.8	26.7

__________

(1) Production represents volumes sold during the period.

~~Average~~(2) Includes production for Antelope Creek area from February 2022, when it was acquired, through March 31, 2023.

(3) In January 2022, we divested all of our natural gas properties in Colorado.

On a sequential basis, our average daily production decreased by ~~1.2~~1.5 mboe/d for the three months ended March 31, ~~2022,~~2023, compared to the three months ended December 31, ~~2021. Production~~2022. Our California production was 19.9 mboe/d for the first quarter ~~was impacted by the sales~~ of ~~our Placerita (California) properties in~~2023, a decrease of 1.2 mboe/d from the fourth quarter ~~2021~~2022, which was largely due to severe rainstorms in January and ~~Piceance (Colorado) properties~~February. The rainstorms ultimately led to flooding and power outages in ~~the first quarter 2022, as~~a number of our fields which decreased well ~~as the acquisition of the Antelope Creek (Utah) properties in the first quarter 2022. Daily~~operating time and prevented routine workover and well maintenance that further negatively impacted production in the first quarter ~~was essentially flat when compared to the fourth quarter after considering the net reduction~~ of ~~approximately 1.0 mboe/d from these transactions. Our California production of 22.2 mboe/d for~~2023. Additionally, in the first quarter ~~2022 decreased 0.5 mboe/d from the fourth quarter 2021 due in part to the Placerita sale, as well as certain offset wells being~~of 2023, we temporarily shut-in wells during ~~planned reworks~~development and abandonment ~~activities.~~activities in one of our most productive fields. The impact of the weather and these activities improved toward the end of the quarter. Utah production was also hampered by extreme weather conditions in the first quarter of 2023. Above-average snowfall limited access to wells, which decreased well uptimes and the ability to transport produced oil, and also prevented normal workover and well maintenance necessary for optimal well performance.

Average daily production in California for the three months ended March 31, 2023 decreased 2.3 mboe/d compared to the same period in 2022. The decrease was primarily due to weather conditions and the other activities discussed above. Additionally, variation in the timing of new wells brought online in 2023 relative to same period in 2022 was ~~1.5% or 0.4 mboe/d lower than the three months ended March 31, 2021. Production for the first quarter 2022 was impacted by the transactions noted above. Daily production~~also a contributing factor.The increase in the ~~first quarter 2022 was higher~~Utah production, when compared to the first quarter ~~2021 after considering these transactions.~~

of last year, was driven by our additional development of the Antelope Creek properties we acquired in February 2022, somewhat offset by previously discussed weather related production losses.

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Results of Operations

Three Months Ended March 31, ~~2022~~2023 compared to Three Months Ended December 31, ~~2021.~~2022.


		Three Months Ended										Three Months Ended
		March 31, 2022		December 31, 2021		$ Change		% Change		March 31, 2023				December 31, 2022			$ 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	$	210,351	$	181,377	$	28,974	16	%		Oil, natural gas and NGL sales	$	166,357		$	188,442		$	(22,085)		(12)	%
Service revenue	Service revenue	39,836		35,840		3,996		11	%		Service revenue	44,623			46,792			(2,169)			(5)	%
Electricity sales	Electricity sales	5,419		6,308		(889)		(14)	%		Electricity sales	5,445			8,284			(2,839)			(34)	%
Losses on oil and gas sales derivatives		(161,858)		(16,378)		(145,480)		888	%
Gains (losses) on oil and gas sales derivatives											Gains (losses) on oil and gas sales derivatives	38,499			(48,872)			87,371			n/a
Marketing and other revenues	Marketing and other revenues	334		939		(605)		(64)	%		Marketing and other revenues	45			37			8			22	%

Total revenues and other	Total revenues and other	$	94,082	$	208,086	$	(114,004)	(55)	%		Total revenues and other	$	254,969		$	194,683		$	60,286		31	%

Revenues and Other

Oil, natural gas and NGL sales ~~increased~~decreased by ~~$29~~$22 million, or ~~16%~~12%, to approximately ~~$210~~$166 million for the three months ended March 31, ~~2022,~~2023, compared to the three months ended December 31, ~~2021.~~2022. The ~~increase~~decrease was driven by ~~$38 million higher unhedged oil prices and partially offset by $6~~$15 million of lower oil volumes and $2$12 million of lower oil prices, partially offset by a $5 million increase in gas ~~prices and gas volumes. The decrease in oil and gas volumes was largely a result of the recent sales of the Placerita and Piceance properties.~~revenue, primarily from higher prices.

Service revenue consisted entirely of revenue from the well servicing and abandonment ~~business we acquired on October 1, 2021.~~business. Service revenue ~~increased~~decreased by $4$2 million or ~~11%~~5% to approximately ~~$40~~$45 million in the first quarter ~~2022, largely~~2023, due to ~~seasonal impact.~~severe flooding in its primary service area. The well servicing and abandonment segment periodically provides services to our E&P segment, as such, we recorded an intercompany elimination of approximately $2 million in revenue and expense in each of the quarters presented. Service revenues in the table above are presented net of intercompany amounts.

Electricity sales represent sales to utilities and decreased $1$3 million, or ~~14%~~34%, to approximately $5 million for the three months ended March 31, ~~2022~~2023 compared to the three months ended December 31, ~~2021. The~~2022. This decrease was ~~primarily attributed~~due to ~~lower unit sales volumes mostly driven by the sale~~not running one of our ~~Placerita assets, which included an electricity-generating~~ cogeneration ~~facility (cogen),~~facilities for most of the first quarter resulting in lower sales volume. In the ~~fourth~~first quarter of ~~2021. Over~~2023, we reduced our steam injection, and thus our natural gas consumption, in certain fields to manage our operating costs due to the ~~last three years the Placerita cogen accounted~~dramatic increase in natural gas prices, and to a lesser extent for ~~approximately 41% of our electrical sales.~~development and abandonment activities.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement loss for the three months ended March 31, ~~2022~~2023 was ~~$34~~$7 million and the loss for the three months ended December 31, ~~2021~~2022 was ~~$43~~$16 million. ~~The~~This quarter-over-quarter decrease was primarily due to the decline in ~~settlement losses was driven by a decrease in notional volumes hedged and an increase in average swap strike~~Brent index prices, in the first quarter of 2022 compared to those of the fourth quarter of 2021. The average derivative fixed price increased to $69.78 in the first quarter of 2022 when compared to $50.33 in the fourth quarter of 2021.index for all our oil derivatives. The mark-to-market non-cash ~~loss of $128~~gain was $46 million for the three months ended March 31, ~~2022 was due to an increase in the difference between the the average market price~~2023 and ~~the fixed price. The mark-to-market non-cash gain~~a loss of ~~$30~~$33 million for ~~the~~ three months ~~end~~ended December 31, ~~2021 was due to the average~~2022. This change resulted from a narrower spread between future market ~~price being closer to, although higher than,~~prices and the fixed price at the end of the ~~prior~~quarter compared to that of the respective previous quarter. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index when such index prices are above the swap fixed price create valuation gains (losses).

Marketing and other revenues, ~~decreased by approximately $1 million~~which included third-party marketing activities, were not material for the three months ended March 31, ~~2022~~2023 and December 31, 2022.

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	Three Months Ended				$ Change		% Change
	March 31, 2023		December 31, 2022
	(in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses	$	134,835	$	87,601	$	47,234	54	%
Costs of services	36,099		35,010		1,089		3	%
Electricity generation expenses	2,500		5,199		(2,699)		(52)	%
Transportation expenses	1,041		1,021		20		2	%

General and administrative expenses	31,669		26,926		4,743		18	%
Depreciation, depletion and amortization	40,121		39,509		612		2	%

Taxes, other than income taxes	10,460		14,341		(3,881)		(27)	%

Gains on natural gas purchase derivatives	(610)		(41,460)		40,850		(99)	%
Other operating income	(286)		(1,023)		737		(72)	%
Total expenses and other	255,829		167,124		88,705		53	%
Other (expenses) income:
Interest expense	(7,837)		(7,646)		(191)		2	%
Other, net	(75)		(63)		(12)		19	%

Total other expenses	(7,912)		(7,709)		(203)		3	%
(Loss) income before income taxes	(8,772)		19,850		(28,622)		(144)	%
Income tax benefit	(2,913)		(52,114)		49,201		(94)	%
Net (loss) income	$	(5,859)	$	71,964	$	(77,823)	(108)	%
Adjusted EBITDA(1)	$	59,337	$	77,508	$	(18,171)	(23)	%
Adjusted Net Income (Loss)(1)	$	5,307	$	76,449	$	(71,142)	(93)	%

__________

(1) Adjusted EBITDA and Adjusted Net Income (Loss) are financial measures that are not calculated in accordance with GAAP. For definitions and a reconciliation to the Net Cash Provided by Operating Activities and Net Income (loss), please see “Item 7 - Non-GAAP Financial Measures”.

Expenses

Lease operating expenses, which does not include the effects of gas purchase hedges, increased 54% or $47 million on an absolute dollar basis to $135 million for the first quarter of 2023 when compared to the fourth quarter of 2022. Approximately 97% of this increase was the result of higher natural gas (fuel) costs for our California steam facilities. Average natural gas purchase price per mmbtu increased 116% compared to three months ended December 31, 2022, which increased fuel expense 82%, net of the benefit from 14% lower consumption of approximately $21 million. Lease operating expense excluding fuel increased 3% on an absolute dollar basis due to higher unit power costs and mostly weather related higher outside services and lease maintenance expenses partially offset by lower well maintenance spending.

Cost of services in 2022 consisted entirely of costs from the well servicing and abandonment business. Cost of services increased by $1 million, or 3%, to $36 million in the first quarter of 2023, due to annual wage increases and higher staffing.

Electricity generation expenses decreased $1.05 per boe or 48% to $1.14 per boe for the three months ended March 31, 2023, compared to $2.19 per boe for the three months ended December 31, ~~2021~~2022, which was a result of not running one of our cogeneration facilities for a majority of the first quarter. In the first quarter of 2023, we reduced our steam injection, and thus our natural gas consumption, in certain fields to manage our operating costs due to the ~~sale of our Piceance operations~~dramatic increase in ~~Colorado, which included third-party marketing activities, in the first quarter 2022. Piceance has historically accounted~~natural gas prices, and to a lesser extent for ~~nearly all of our marketing revenues.~~development and abandonment activities.

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Three Months Ended $ Change % Change
March 31, 2022 December 31, 2021
(in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses $ 63,124 $ 67,292 $ (4,168) (6) %
Costs of services 33,472 28,339 5,133 18 %
Electricity generation expenses 4,463 3,660 803 22 %
Transportation expenses 1,158 1,758 (600) (34) %
Marketing expenses 299 825 (526) (64) %
General and administrative expenses 22,942 22,357 585 3 %
Depreciation, depletion and amortization 39,777 38,903 874 2 %
Taxes, other than income taxes 6,605 11,920 (5,315) (45) %
(Gains) losses on natural gas purchase derivatives (29,054) 15,772 (44,826) n/a
Other operating expenses (income) 3,769 (1,726) 5,495 (318) %
Total expenses and other 146,555 189,100 (42,545) (22) %
Other (expenses) income:
Interest expense (7,675) (7,451) (224) 3 %
Other, net (13) (91) 78 (86) %
Total other (expenses) income (7,688) (7,542) (146) 2 %
Income (loss) before income taxes (60,161) 11,444 (71,605) (626) %
Income tax (benefit) expense (3,351) 2,619 (5,970) (228) %
Net (loss) income $ (56,810) $ 8,825 $ (65,635) (744) %
Expenses per boe:(1)
Lease operating expenses $ 26.25 $ 26.23 $ 0.02 — %
Electricity generation expenses 1.86 1.43 0.43 30 %
Electricity sales(1)
(2.25) (2.46) 0.21 (9) %
Transportation expenses 0.48 0.69 (0.21) (30) %
Transportation sales(1)
(0.02) (0.05) 0.03 (60) %
Marketing expenses 0.13 0.32 (0.19) (59) %
Marketing revenues(1)
(0.12) (0.33) 0.21 (64) %
Derivatives settlements received for gas purchases(1)
(0.69) (3.37) 2.68 (80) %
Total operating expenses $ 25.64 $ 22.46 $ 3.18 14 %
Total unhedged operating expenses(2)
$ 26.33 $ 25.83 $ 0.50 2 %
Total non-energy operating expenses(3)
$ 13.58 $ 13.41 $ 0.17 1 %
Total energy operating expenses(4)
$ 12.06 $ 9.05 $ 3.01 33 %
General and administrative expenses(5)
$ 9.54 $ 8.71 $ 0.83 10 %
Depreciation, depletion and amortization $ 16.53 $ 15.16 $ 1.37 9 %
Taxes, other than income taxes $ 2.74 $ 4.65 $ (1.91) (41) %
~~__________~~

~~Table of Contents~~

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

~~(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 $1.62 per boe and $2.14 per boe for the three months ended March 31, 2022 and December 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”, which include electricity, marketing and transportation revenues. On a hedged basis, operating expenses increased by 14%, or $3.18 per boe to $25.64 for the first quarter 2022 compared to the fourth quarter 2021. During the first quarter, energy operating expenses increased due to higher hedged purchased gas costs as our previous below market hedge book closed in Q4 and new hedged prices are more closely aligned to current market. As expected, non-energy operating expenses increased slightly on a per boe basis due to increased labor costs, compared to the fourth quarter of 2021.

~~Unhedged lease operating expenses per boe remained relatively flat at $26.25 for the three months ended March 31, 2022, compared to $26.23 per boe for the three months ended December 31, 2021.~~

Cost of services in 2021 consisted entirely of costs from the well servicing and abandonment business we acquired on October 1, 2021. Cost of services increased by $5 million or 18% compared to $33 million in the first quarter 2022, mainly due to improving revenue, higher costs primarily around labor and fuel, and seasonal activity levels.

Electricity generation expenses increased approximately 30% to $1.86 per boe for the three months ended March 31, 2022, compared to $1.43 per boe for the three months ended December 31, 2021 due to higher natural gas fuel costs. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.

Gains and losses on natural gas purchase derivatives resulted in a ~~$29~~$1 million gain for the three months ended March 31, ~~2022~~2023 and a ~~loss~~gain of ~~$16~~$41 million in the three months ended December 31, ~~2021.~~2022. Settlement gains for the three months ended March 31, ~~2022~~2023 and December 31, ~~2021~~2022 were $2$55 million, or ~~$0.69~~$25.11 per boe, and $9$12 million, or ~~$3.51~~$5.28 per boe, respectively, and ~~decreased~~increased due to ~~hedged~~higher index prices ~~being more closely in line with market~~relative to the derivative fixed prices of settled positions in the first quarter of 2023 compared to the fourth quarter of 2022. The mark-to-market valuation ~~gain~~loss was ~~$27~~$54 million for the three months ended March 31, ~~2022~~2023 and a ~~loss~~gain of ~~$24~~$29 million for the three months ended December 31, ~~2021 due~~2022. Because we are the fixed price payer on these natural gas swaps, generally, period to ~~higher futures prices relative to~~period increases (decreases) in the ~~derivative fixed prices.~~associated price index create valuation gains (losses).

Transportation ~~expense decreased to $0.48 per boe~~expenses were comparable for the ~~three months ended March 31, 2022 compared to $0.69 per boe for the three months ended December 31, 2021, primarily due to the sale of our Piceance operations in the first quarter of 2022.~~

Marketing expenses decreased by $0.19 per boe for the three months ended March 31, 2022 when compared to the three months ended December 31, 2021, due to the sale of our Piceance operations in the first quarter of 2022, which included third-party marketing activities.

~~Table of Contents~~

periods presented.

General and administrative expenses increased ~~by $0.6~~$5 million ~~or 3%,~~ to ~~$22.9~~$32 million for the three months ended March 31, ~~2022,~~2023 compared to $27 million for the three months ended December 31, ~~2021, due to the following matters and those noted in adjusted general and administrative expenses below.~~2022. For the three months ended March 31, ~~2022~~2023 and December 31, ~~2021,~~2022, general and administrative expenses included non-cash stock compensation costs of approximately ~~$3.7~~$5 million and ~~$3.5~~$4 million, respectively. We incurred ~~approximately $0.2~~non-recurring costs of $7 million and $2$3 million ~~of expenses related to acquisition and divestiture activity which have been categorized as non-recurring~~ for the three months ended March 31, ~~2022~~2023 and December 31, ~~2021,~~2022, respectively. ~~Less than 10%~~Non-recurring costs included executive transition costs in both the first quarter of ~~our overhead is capitalized~~2023 and ~~thus excluded from general~~the fourth quarter of 2022, and ~~administrative expenses.~~workforce reduction costs in the first quarter of 2023.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, ~~increased to $19~~were $20 million for the three months ended March 31, ~~2022 compared to $17~~2023, and $19 million for the three months ended December 31, ~~2021. As expected, adjusted general and administrative expenses increased~~2022. This increase is primarily due to ~~higher legal~~payroll taxes on restricted stock units that vested in the first quarter of 2023 and expected inflation of employee costs. See “—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 ~~was $1~~increased 2% to $40 million ~~or 2%, higher~~ for the three months ended March 31, ~~2022~~2023 compared to the three months ended December 31, ~~2021.~~2022. The increase was ~~a result of slightly higher DD&A rates for~~driven primarily by depletion rate changes in the DE&P ~~segment, partially offset by lower production.~~segment.

Taxes, Other Than Income Taxes


		Three Months Ended				$ Change		% Change			Three Months Ended				$ Change		% Change
		March 31, 2022		December 31, 2021							March 31, 2023		December 31, 2022
		(per boe)									(per boe)
Severance taxes	Severance taxes	$	1.26	$	0.58	$	0.68	117	%	Severance taxes	$	1.81	$	1.60	$	0.21	13	%
Ad valorem and property taxes	Ad valorem and property taxes	1.51		1.20		0.31		26	%	Ad valorem and property taxes	2.21		2.26		(0.05)		(2)	%
Greenhouse gas allowances	Greenhouse gas allowances	(0.03)		2.87		(2.90)		(101)	%	Greenhouse gas allowances	0.76		2.19		(1.43)		(65)	%

Total taxes other than income taxes	Total taxes other than income taxes	$	2.74	$	4.65	$	(1.91)	(41)	%	Total taxes other than income taxes	$	4.78	$	6.05	$	(1.27)	(21)	%

Taxes, other than income taxes, decreased in the three months ended March 31, ~~2022~~2023 by ~~$1.91~~$1.27 per boe, or ~~41%~~21%, to ~~$2.74. Severance taxes were higher~~$4.78. The reduction in ~~the~~ first quarter of 2022 due to a positive year-end adjustment lowering the fourth quarter expense. Ad valorem and property taxes were higher in the first quarter of 2022 due to lower assessments received in the fourth quarter of 2021. The first quarter of 20222023 greenhouse gas (“GHG”) ~~amount~~costs was a result of lower emissions and mark-to-market prices atcompared to the ~~end~~fourth quarter of ~~the period resulting~~2022. The increase in ~~reductions~~severance taxes is largely due to ~~cumulative emission costs to date, which are scheduled for payment~~an increase in ~~future periods.~~Utah revenue.

Other Operating ~~Expenses~~Income

For the three months ended March 31, 2022, other operating expenses were $4 million and consisted of over $2 million of royalty audit charges incurred prior to our emergence and restructuring in 2017, and over $1 million loss on the divestiture of the Piceance properties. Other operating income were comparable for ~~the three months ended December 31, 2021 was approximately $2 million and consisted of a gain on the divestiture of the Placerita properties.~~periods presented.

Interest Expense

Interest expense was relatively flat at $8 million for each of the three months ended March 31, ~~2022~~2023 and December 31, ~~2021.~~2022.

Table of Contents

Income ~~Tax Benefit~~Taxes

Our effective tax rate was ~~approximately 5%~~33% for the three months ended March 31, ~~2022 compared to 23%~~2023 and included the impact of certain permanent items which are not deductible. The effective tax rate for the three months ended December 31, ~~2021. The rate in the first quarter of~~ 2022 was ~~impacted~~(263%) which was driven by ~~changes in~~ the full release of our valuation allowance ~~recorded against deferred tax assets.~~

~~Table of Contents~~

during the period.

Three Months Ended March 31, ~~2022~~2023 compared to Three Months Ended March 31, ~~2021.~~2022.


		Three Months Ended March 31,				$ Change		% Change			Three Months Ended March 31,				$ Change		% Change
		2022		2021							2023		2022
		(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	$	210,351	$	135,265	$	75,086	56	%	Oil, natural gas and NGL sales	$	166,357	$	210,351	$	(43,994)	(21)	%
Service revenue	Service revenue	39,836		—		39,836		100	%	Service revenue	44,623		39,836		4,787		12	%
Electricity sales	Electricity sales	5,419		10,069		(4,650)		(46)	%	Electricity sales	5,445		5,419		26		—	%
Losses on oil and gas sales derivatives		(161,858)		(53,504)		(108,354)		203	%
Gains (losses) on oil and gas sales derivatives										Gains (losses) on oil and gas sales derivatives	38,499		(161,858)		200,357		n/a
Marketing and other revenues	Marketing and other revenues	334		2,371		(2,037)		(86)	%	Marketing and other revenues	45		334		(289)		(87)	%
Total revenues and other	Total revenues and other	$	94,082	$	94,201	$	(119)	—	%	Total revenues and other	$	254,969	$	94,082	$	160,887	171	%

Revenues and Other

Oil, natural gas and NGL sales ~~increased~~decreased by ~~$75~~$44 million, or ~~56%~~21%, to approximately ~~$210~~$166 million for the three months ended March 31, ~~2022~~2023 when compared to the three months ended March 31, ~~2021. This~~2022. The variance was ~~mostly the result~~driven by $36 million of lower oil prices and $15 million of lower oil volumes, partially offset by a $7 million increase in gas revenue, principally higher ~~unhedged commodity prices, as well as higher oil volumes.~~prices.

Service revenue in the first quarter 2023 was $45 million, a $5 million increase compared to the first quarter 2022, ~~was $40 million. Services revenue consisted entirely~~primarily due to rate increases which were effective in late 2022 to offset a portion of ~~revenue from the well servicing and abandonment business we acquired on October 1, 2021.~~cost inflation.

Electricity sales represent sales to utilities, and ~~decreased by $5 million, or 46%, to approximately~~remained flat at $5 million for the three months ended March 31, ~~2022~~2023 when compared to the three months ended March 31, 2021. The increase was largely due to lower unit sales volumes driven by sale of our Placerita assets, which included an electricity-generating cogeneration facility (cogen), in the fourth quarter 2021. Over the last three years the Placerita cogen accounted for approximately 41% of our electrical sales.2022.

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 for the three months ended March 31, ~~2022~~2023 and the three months ended March 31, ~~2021~~2022 were ~~$34~~$7 million and ~~$26~~$34 million, respectively. The quarter-over-quarter ~~increases~~decrease in settlement ~~losses and mark-to-market non-cash~~ losses were driven by ~~higher~~lower oil prices ~~in the first quarter 2022~~ relative to our derivative fixed prices ~~with notional~~in the first quarter of 2023 than that of the same period in 2022. Notional volumes ~~of 14~~were 15 mbbl/d in the first quarter ~~2022~~2023 and 1911 mbbls/d in the first quarter ~~2021.~~2022. The mark-to-market non-cash ~~losses~~gain was $46 million for the three months ended March 31, 2023 and a loss of $128 million for the months ended March 31, 2022, due to a narrower spread between future market prices and ~~$28~~the fixed price at the end of the quarter compared to that of the respective previous quarter. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index create valuation gains (losses).

Marketing and other revenues were not material for the three months ended March 31, 2023 and March 31, 2022.

Table of Contents


	Three Months Ended March 31,				$ Change		% Change
	2023		2022
	(in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses	$	134,835	$	63,124	$	71,711	114	%
Costs of services	36,099		33,472		2,627		8	%
Electricity generation expenses	2,500		4,463		(1,963)		(44)	%
Transportation expenses	1,041		1,158		(117)		(10)	%
Marketing expenses	—		299		(299)		(100)	%
General and administrative expenses	31,669		22,942		8,727		38	%
Depreciation, depletion and amortization	40,121		39,777		344		1	%

Taxes, other than income taxes	10,460		6,605		3,855		58	%

Gains on natural gas purchase derivatives	(610)		(29,054)		28,444		(98)	%
Other operating (income) expenses	(286)		3,769		(4,055)		(108)	%
Total expenses and other	255,829		146,555		109,274		75	%
Other (expenses) income:
Interest expense	(7,837)		(7,675)		(162)		2	%
Other, net	(75)		(13)		(62)		477	%

Total other expenses	(7,912)		(7,688)		(224)		3	%
Loss before income taxes	(8,772)		(60,161)		51,389		(85)	%
Income tax benefit	(2,913)		(3,351)		438		(13)	%
Net loss	$	(5,859)	$	(56,810)	$	50,951	90	%


Adjusted EBITDA(1)	$	59,337	$	95,712	$	(36,375)	(38)	%
Adjusted Net Income (Loss)(1)	$	5,307	$	19,447	$	(14,140)	(73)	%

__________

Expenses

Lease operating expenses, which does not include the effects of gas purchase hedges, increased 114% or $72 million on an absolute dollar basis to $135 million for the first quarter for 2023 when compared to the first quarter of 2022. Of this increase, approximately 87% was the result of higher natural gas (fuel) costs for our California steam facilities. Average natural gas purchase price per mmbtu increased 229% compared to three months ended March 31, 2022, which increased fuel expense 166%, net of the benefit from 19% lower consumption of approximately $29 million. Lease operating expense excluding fuel increased 30% on an absolute dollar basis due to higher unit power costs, and primarily weather related higher outside services and lease maintenance We estimated that inflation accounted for approximately 33% of the the increase in non-fuel operating costs.

Cost of services in the first quarter of 2023 were $36 million, an 8% increase when compared to costs of services in the first quarter of 2022 due to higher wage rates.

Electricity generation expenses decreased approximately 44% to $2.5 million for the three months ended March 31, 2023 from $4.5 million for the same period in 2022 due to not running one of our cogeneration facilities for most of the first quarter of 2023.

Table of Contents

Gains and losses on natural gas purchase derivatives for the three months ended March 31, 2023 and March 31, 2022 resulted in a gain of $1 million and $29 million, respectively. Settlement gains for the three months ended March 31, 2023 and March 31, 2022 were $55 million and $2 million, or $25.11 per boe and $0.69 per boe, respectively. The mark-to-market non-cash loss for three months ended March 31, 2023 was $54 million and a gain of $27 million for the three months ended March 31, 2022, due to a narrower spread between future market prices and the derivative fixed price at the end of the quarter compared to that of the respective previous quarter. Because we are the fixed price payer on these natural gas swaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses).

Transportation expenses were essentially unchanged for the three months ended March 31, 2023 compared to the three months ended March 31, 2022

Marketing expenses were not material for the three months ended March 31, 2023 and March 31, 2022.

General and administrative expenses increased $9 million, or 38%, to approximately $32 million for the three months ended March 31, 2023 compared to the three months ended March 31, 2022. For the three months ended March 31, 2023 and March 31, 2022, general and administrative expenses included non-cash stock compensation costs of approximately $5 million and $4 million, respectively. We incurred non-recurring costs of $7 million for the three months ended March 31, 2023 and these costs were insignificant in the first quarter of 2022. The non-recurring costs for the first quarter of 2023 included primarily executive transition and workforce reduction costs.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, increased 4% to $20 million for the three months ended March 31, 2023 compared to $19 million for the three months ended March 31, 2022, and ~~March 31, 2021, respectively, were~~was principally due to ~~higher futures prices relative~~expected inflation of employee costs.

DD&A was comparable for the periods presented.

Taxes, Other Than Income Taxes



	Three Months Ended March 31,				$ Change		% Change
	2023		2022
	(per boe)
Severance taxes	$	1.81	$	1.26	$	0.55	44	%
Ad valorem and property taxes	2.21		1.51		0.70		46	%
Greenhouse gas allowances	0.76		(0.03)		0.79		2,633	%
Total taxes other than income taxes	$	4.78	$	2.74	$	2.04	74	%

Taxes, other than income taxes increased 74% to ~~the derivative fixed prices at each period end.~~

~~Marketing and other revenues decreased by approximately $2 million~~$4.78 per boe for the three months ended March 31, ~~2022 when~~2023 compared to $2.74 per boe for the three months ended March 31, ~~2021~~2022. Severance taxes increased due to ~~sale~~a higher assessment in California, as well as an increase in revenue-based taxes in Utah for 2022. Property taxes increased in both California and Utah as a result of higher property values. The GHG expense increase was due to higher mark-to-market price changes.

Other Operating (Income) Expenses

Other operating (income) expenses decreased $4 million in three months ended March 31, 2023 when compared to the same quarter in 2022. The components in three months ended March 31, 2022 were $2 million of royalty audit charges incurred prior to our emergence and restructuring in 2017, and over $1 million loss on the divestiture of our Piceance ~~operations, which included third-party marketing activities,~~properties. Amounts in the first quarter ~~2022. The prior year’s revenue also reflected high gas prices as a result~~ of ~~Winter Storm Uri. Piceance has historically accounted for nearly all of our marketing revenues.~~2023 were insignificant.

Interest Expense

Interest expense was comparable in the three months ended March 31, 2023 and March 31, 2022.

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Three Months Ended
March 31, $ Change % Change
2022 2021
(in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses $ 63,124 $ 62,284 $ 840 1 %
Costs of services 33,472 — 33,472 100 %
Electricity generation expenses 4,463 7,648 (3,185) (42) %
Transportation expenses 1,158 1,576 (418) (27) %
Marketing expenses 299 2,227 (1,928) (87) %
General and administrative expenses 22,942 17,070 5,872 34 %
Depreciation, depletion and amortization 39,777 33,840 5,937 18 %
Taxes, other than income taxes 6,605 9,557 (2,952) (31) %
(Gains) on natural gas purchase derivatives (29,054) (27,730) (1,324) 5 %
Other operating expenses 3,769 799 2,970 372 %
Total expenses and other 146,555 107,271 39,284 37 %
Other (expenses) income:
Interest expense (7,675) (8,485) 810 (10) %
Other, net (13) (143) 130 (91) %
Total other (expenses) income (7,688) (8,628) 940 (11) %
Income (loss) before income taxes (60,161) (21,698) (38,463) 177 %
Income tax benefit (3,351) (376) (2,975) 791 %
Net loss $ (56,810) $ (21,322) $ (35,488) (166) %
Expenses per boe:(1)
Lease operating expenses $ 26.25 $ 25.58 $ 0.67 3 %
Electricity generation expenses 1.86 3.14 (1.28) (41) %
Electricity sales(1)
(2.25) (4.13) 1.88 (46) %
Transportation expenses 0.48 0.65 (0.17) (26) %
Transportation sales(1)
(0.02) (0.06) 0.04 (67) %
Marketing expenses 0.13 0.92 (0.79) (86) %
Marketing revenues(1)
(0.12) (0.92) 0.80 (87) %
Derivatives settlements (received) paid for gas purchases(1)
(0.69) (10.78) 10.09 (94) %
Total operating expenses $ 25.64 $ 14.40 $ 11.24 78 %
Total unhedged operating expenses(2)
$ 26.33 $ 25.18 $ 1.15 5 %
Total non-energy operating expenses(3)
$ 13.58 $ 12.74 $ 0.84 7 %
Total energy operating expenses(4)
$ 12.06 $ 1.66 $ 10.40 627 %
General and administrative expenses(5)
$ 9.54 $ 7.01 $ 2.53 36 %
Depreciation, depletion and amortization $ 16.53 $ 13.90 $ 2.63 19 %
Taxes, other than income taxes $ 2.74 $ 3.93 $ (1.19) (30) %
~~__________~~

~~Table of Contents~~

~~(1) We report electricity, transportation and marketing sales separately~~Income Taxes

Our effective tax rate was approximately 33% for the three months ended March 31, 2023 compared to 5% for the three months ended March 31, 2022. The rate in ~~our financial statements as revenues~~the first quarter of 2022 was impacted by changes 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~~valuation allowance recorded against deferred tax assets.

E&P Field Operations

Overall, management assesses the efficiency of our ~~hydrocarbon recovery.~~E&P field operations by considering core E&P operating expenses together with our cogeneration, marketing and transportation activities. In particular, a core component of our E&P operations in California is steam, which we use to lift heavy oil to the surface. We operate several cogeneration facilities to produce some of the steam needed in our operations. In comparing the cost effectiveness of our cogeneration plants against other sources of steam in our operations, management considers the cost of operating the cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the steam and electricity used in our E&P field operations and the revenues we receive from sales of excess electricity to the grid. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural gas purchase ~~third-party~~hedges. Consequently, the efficiency of our E&P field operations are impacted by the cash settlements we receive or pay from these derivatives. We also have contracts for the transportation of fuel gas from the Rockies which has historically been cheaper than the California markets. With respect to ~~generate electricity through~~transportation and marketing, management also considers opportunistic sales of incremental capacity in assessing the overall efficiencies of E&P operations.

Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Electricity generation expenses include the portion of fuel, labor, maintenance, and tools and supplies from two of our cogeneration facilities allocated to ~~be used~~electricity generation expense; the remaining cogeneration expenses are included in lease operating expense. Transportation expenses relate to our ~~field operations activities~~costs to transport the oil and ~~view~~gas that we produce within our properties or move it to the ~~added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations.~~market. 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. Electricity revenue is from the sale of excess electricity from two of our cogeneration facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are sized to satisfy the steam needs in their respective fields, but the corresponding electricity produced is more than the electricity that is currently required for the operations in those fields. 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) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity~~marketing revenues represent sales ~~and gas purchase derivative settlement (gains) losses.~~

~~(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 $1.62 per boe and $1.51 per boe for the three months ended March 31, 2022 and March 31, 2021, respectively.

~~Expenses and Other~~

On a hedged basis, operating expenses, increased by 78% or $11.24 per boe to $25.63 per boe for the first quarter 2022 compared to $14.40 per boe for the first quarter 2021. The increase was largely due to the impact the purchased gas hedges, discussed below, had on the higher energy operating expense.

Unhedged lease operating expenses were $26.25 per boe for the three months ended March 31, 2022, a 3% or $0.67 boe increase compared to $25.58 for the three months ended March 31, 2021. Unhedged fuel costs for our California steam operations decreased $1.57 per boe. Unhedged average fuel purchase price per mmbtu decreased 9% in the first quarter 2022 compared to the first quarter 2021 and gas volumes purchased were also down slightly. The prior year’s fuel costs reflected high gas prices as a result of Winter Storm Uri. As expected, non-energy operating expenses increased due to higher lease operating expense driven by higher well maintenance and recompletion activities, and higher labor costs.

Cost of services in the first quarter 2022 were $33 million and there were no costs of services in the first quarter of 2021, as we acquired the well servicing and abandonment business on October 1, 2021.

Electricity generation expenses decreased approximately 41% to $1.86 per boe for the three months ended March 31, 2022 from $3.14 per boe for the same period in 2021 due to lower natural gas costs, in part due to the impact of the Placerita properties sale. Fuel costs included in electricity generation expenses exclude the effects of natural gas ~~derivative settlements.~~

~~Gains~~purchased from and losses on natural gas purchase derivatives for the three months ended March 31, 2022 and March 31, 2021 resulted in a gain of $29 million and $28 million, respectively. Settlement gains for the three months ended March 31, 2022 were $2 million or $0.69 per boe comparedsold to the settlement gain of $26 million or $10.78 per boe for the three months ended March 31, 2021, driven by lower gas 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 March 31, 2022 was $27 million compared to $2 million gain for the same period in 2021, 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 decreased to $0.48 per boe for the three months ended March 31, 2022 compared to $0.65 per boe for the three months ended March 31, 2021, primarily due to the sale of our Piceance operations the first quarter 2022.

Marketing expenses decreased to $0.13 per boe for the three months ended March 31, 2022, compared to $0.92 per boe for the three months ended March 31, 2021, due to the sale of Piceance in the first quarter 2022. The prior year expenses also included the impact of higher gas prices due to Winter Storm Uri.

General and administrative expenses increased $6 million, or 34%, to approximately $23 million for the three months ended March 31, 2022 compared to the three months ended March 31, 2021. For the three months ended March 31, 2022 and March 31, 2021, general and administrative expenses included non-cash stock compensationthird parties.

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costs of approximately $3.7 million and $3.7 million, respectively, with $0.2 million non-recurring costs in 2022 and no non-recurring costs in the same period of 2021. The first quarter 2022 also included $3 million of general and administrative expenses from the well servicing and abandonment segment which had no corresponding amount in 2021 as we purchased these operations in the fourth quarter 2021.



	Three Months Ended
	March 31, 2023		December 31, 2022		$ Change		% Change
	(per boe)
Expenses from field operations
Lease operating expenses	$	61.65	$	36.95	$	24.70	67	%
Electricity generation expenses	1.14		2.19		(1.05)		(48)	%
Transportation expenses	0.48		0.43		0.05		12	%

Total	$	63.27	$	39.57	$	23.70	60	%

Cash settlements received for gas purchase hedges	$	(25.11)	$	(5.28)	$	(19.83)	376	%

E&P non-production revenues
Electricity sales	$	2.49	$	3.49	$	(1.00)	(29)	%
Transportation sales	0.02		0.02		—		—	%

Total	$	2.51	$	3.51	$	(1.00)	(28)	%

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, increased 46% to $19 million for the three months ended March 31, 2022 compared to $13 million for the three month periods ended March 31, 2021. The increase was primarily due to the new well servicing and abandonment operations, as well as higher legal and other professional service expenses and employee costs.

DD&A for the first quarter 2022 increased approximately $6 million to $40 million when compared to the first quarter 2021 driven primarily by the new well servicing and abandonment operations and higher DD&A rates for the D&P segment, partially offset by lower production.

~~Taxes, Other Than Income Taxes~~


	Three Months Ended
	March 31, 2023		March 31, 2022		$ Change		% Change
	(per boe)
Expenses from field operations
Lease operating expenses	$	61.65	$	26.25	$	35.40	135	%
Electricity generation expenses	1.14		1.86		(0.72)		(39)	%
Transportation expenses	0.48		0.48		—		—	%
Marketing expenses	—		0.13		(0.13)		(100)	%
Total	$	63.27	$	28.72	$	34.55	120	%

Cash settlements received for gas purchase hedges	$	(25.11)	$	(0.69)	$	(24.42)	3,539	%

E&P non-production revenues
Electricity sales	$	2.49	$	2.25	$	0.24	11	%
Transportation sales	0.02		0.02		—		—	%
Marketing revenues	—		0.12		(0.12)		(100)	%
Total	$	2.51	$	2.39	$	0.12	5	%

Three Months Ended
March 31, $ Change % Change
2022 2021
(per boe)
Severance taxes $ 1.26 $ 0.99 $ 0.27 27 %
Ad valorem and property taxes 1.51 2.01 (0.50) (25) %
Greenhouse gas allowances (0.03) 0.93 (0.96) (103) %
Total taxes other than income taxes $ 2.74 $ 3.93 $ (1.19) (30) %

Taxes, other than income taxes decreased 30% to $2.74 per boe for the three months ended March 31, 2022 compared to $3.93 per boe for the three months ended March 31, 2021. Severance taxes increased due to higher revenue in Utah, while property taxes in California were lower quarter over quarter. The first quarter of 2022 GHG amount was a result of lower mark-to-market prices at the end of the period resulting in reductions to cumulative emission costs to date, which are scheduled for payment in future periods.

~~Other Operating Expenses (Income)~~

For the three months ended March 31, 2022, other operating expenses were $4 million and consisted of over $2 million of royalty audit charges incurred prior to our emergence and restructuring in 2017, and over $1 million of loss on the divestiture of the Piceance properties. Other operating income for the three months ended March 31, 2021 was $1 million and comprised mainly of sales tax and bankruptcy-related refunds, partially offset by excess abandonment costs.

~~Interest Expense~~

~~Interest expense was comparable in the three months ended March 31, 2022 and March 31, 2021.~~

~~Income Tax Benefit~~

Our effective tax rate was approximately 5% for the three months ended March 31, 2022 compared to 2% for the three months ended March 31, 2021. The rates were impacted by changes in the valuation allowance recorded against deferred tax assets.

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Non-GAAP Financial Measures

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

Adjusted Net Income (Loss) is not a measure of net income (loss), ~~Levered~~Adjusted Free Cash Flow ~~and Discretionary Free Cash Flow are~~is not ~~measures~~a measure of cash flow, and Adjusted EBITDA is not a measure of either net income (loss) or cash flow, in all cases, as determined by GAAP. Adjusted EBITDA, ~~Levered~~Adjusted Free Cash Flow, Adjusted Net Income (Loss) and ~~Discretionary Free Cash Flow~~Adjusted General and Administrative Expenses are supplemental non-GAAP financial 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 unusual and infrequent 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~~We also use Adjusted EBITDA in planning our capital allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility.

We define Adjusted Net Income (Loss) as net income (loss) adjusted for ~~internal growth opportunities, as well as hedging needs. It also serves as a measure~~derivative gains or losses net of cash received or paid for ~~assessing~~scheduled derivative settlements, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our ~~financial performance and our ability to generate excess cash from operations to service debt and pay dividends.~~

statutory tax rate. Adjusted Net Income (Loss) excludes the impact of unusual 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~~believe Adjusted Net Income (Loss) ~~as net income (loss) adjusted~~is useful to investors because it reflects how management evaluates the Company’s ongoing financial and operating performance from period-to-period after removing certain transactions and activities that affect comparability of the metrics and are not reflective of the Company’s core operations. We believe this also makes it easier for ~~derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual and infrequent items, and the income tax expense or benefit of these adjustments using~~investors to compare our ~~effective tax rate.~~period-to-period results with our peers.

We define ~~Discretionary~~Adjusted Free Cash Flow, which is a non-GAAP financial measure, as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital represents the capital expenditures needed to ~~hold~~maintain substantially the same volume of annual oil and gas production ~~flat. We expect~~and is defined as capital expenditures, excluding, when applicable, E&P capital expenditures that are related to ~~allocate 60%~~strategic business expansion, such as acquisitions of ~~Discretionary~~oil and gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes and capital expenditures in our well servicing and abandonment and corporate segments that are related to ancillary sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. Management believes Adjusted Free Cash Flow ~~predominantly~~may be useful in ~~the form~~an investor analysis of our ability to generate cash ~~variable dividends, as well as opportunistic debt repurchases. The remaining 40% will be used for opportunistic growth, including~~from operating activities from our ~~extensive inventory~~existing oil and gas asset base after maintaining the existing production volumes of ~~drilling opportunities, advancing~~that asset base to return capital to stockholders, fund further business expansion through acquisitions or investments in our ~~short-~~existing asset base to increase production volumes and ~~long-term sustainability initiatives, share repurchases, and/or capital retention. Our management believes Discretionary~~pay other non-discretionary expenses. Management also uses Adjusted Free Cash Flow ~~provides useful information in assessing our financial condition, and is~~as the primary metric to determine the quarterly variable dividend. In early 2023, we updated our shareholder return model, including to double our quarterly fixed dividend to $0.12 per share. Any dividends actually paid will be determined by our Board of Directors in light of existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors. We also modified the allocations of Adjusted Free Cash Flow. Our goal is to continue maximizing shareholder value through overall returns. The allocation beginning in 2023 will be (a) 80% primarily in the form of opportunistic debt or share repurchases, as well as strategic growth, such as acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends.

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repurchases, strategic acquisitions or other discretionary expenditures, since we have mandatory debt service requirements and other non-discretionary expenditures that are not deducted from this measure.

We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and 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 believe Adjusted General and Administrative Expenses is useful to investors because it reflects how management evaluates the Company’s ongoing general and administrative expenses from period-to-period after removing non-cash stock compensation, as well as unusual or infrequent costs that affect comparability of the metrics and are not reflective of the Company’s administrative costs. We believe this also makes it easier for investors to compare our period-to-period results with our peers.

While Adjusted EBITDA, Adjusted ~~Net Income (Loss), Levered~~ Free Cash Flow, Adjusted Net Income (Loss) and ~~Discretionary Free Cash Flow~~Adjusted General and Administrative Expenses are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Adjusted ~~Net Income (Loss), Levered~~ Free Cash Flow, Adjusted Net Income (Loss) and ~~Discretionary Free Cash Flow~~Adjusted General and Administrative Expenses 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 and should not be considered as an alternative to, or more meaningful than 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), Levered~~ Free Cash Flow, Adjusted Net Income (Loss) and ~~Discretionary Free Cash Flow~~Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted ~~Net Income (Loss), Levered~~ Free Cash Flow, Adjusted Net Income (Loss) and ~~Discretionary Free Cash Flow~~Adjusted General and Administrative Expenses should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

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 unusual and infrequent costs. Management believes Adjusted General

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~~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~~measure Adjusted EBITDA ~~and Levered Free Cash Flow~~ to the GAAP financial measures of net income (loss) and net cash provided ~~or used~~(or used) by operating activities, as applicable, for each of the periods indicated.


		Three Months Ended								Three Months Ended
		March 31, 2022		December 31, 2021		March 31, 2021						March 31, 2023		December 31, 2022		March 31, 2022
		(in thousands)							(in thousands)
Adjusted EBITDA reconciliation to net income (loss):	Adjusted EBITDA reconciliation to net income (loss):							Adjusted EBITDA reconciliation to net income (loss):
Net (loss) income	Net (loss) income	$	(56,810)	$	8,825	$	(21,322)				Net (loss) income	$	(5,859)	$	71,964	$	(56,810)
Add (Subtract):	Add (Subtract):										Add (Subtract):
Interest expense	Interest expense	7,675		7,451		8,485					Interest expense	7,837		7,646		7,675
Income tax (benefit) expense		(3,351)		2,619		(376)
Income tax benefit											Income tax benefit	(2,913)		(52,114)		(3,351)
Depreciation, depletion and amortization	Depreciation, depletion and amortization	39,777		38,903		33,840					Depreciation, depletion and amortization	40,121		39,509		39,777

Losses on derivatives		132,804		32,150		25,774
Net cash (paid) received for scheduled derivative settlements		(32,152)		(33,421)		850
Other operating expenses (income)		3,769		(1,726)		799
(Gains) losses on derivatives											(Gains) losses on derivatives	(39,109)		7,412		132,804
Net cash received (paid) for scheduled derivative settlements											Net cash received (paid) for scheduled derivative settlements	47,467		(3,504)		(32,152)
Other operating (income) expenses											Other operating (income) expenses	(286)		(1,023)		3,769
Stock compensation expense	Stock compensation expense	3,802		3,564		3,779					Stock compensation expense	4,766		4,350		3,802
Non-recurring costs(1)	Non-recurring costs(1)	198		2,030		—					Non-recurring costs(1)	7,313		3,268		198

Adjusted EBITDA	Adjusted EBITDA	$	95,712	$	60,395	$	51,829				Adjusted EBITDA	$	59,337	$	77,508	$	95,712


	Three Months Ended
	March 31, 2023		December 31, 2022		March 31, 2022
	(in thousands)
Adjusted EBITDA reconciliation to net cash provided by operating activities:
Net cash provided by operating activities	$	1,781	$	105,407	$	48,530
Add (Subtract):
Cash interest payments	14,388		311		14,539
Cash income tax payments	—		828		—

Non-recurring costs(1)	7,313		3,268		198

Changes in operating assets and liabilities - working capital(2)	36,745		(31,003)		27,766
Other operating (income) expenses - cash portion(3)	(890)		(1,303)		4,679

Adjusted EBITDA	$	59,337	$	77,508	$	95,712

__________

(1) Non-recurring costs included executive transition costs in both the first quarter of 2023 and the fourth quarter of 2022, and workforce reduction costs in the first quarter of 2023. Non-recurring costs included legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022.

(2) Changes in other assets and liabilities consists of working capital and various immaterial items.

(3) Represents the cash portion of other operating expenses (income) from the income statement.

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Three Months Ended
March 31,
2022 December 31,
2021 March 31,
2021
(in thousands)
Adjusted EBITDA reconciliation to net cash provided by operating activities and Levered Free Cash Flow calculation:
Net cash provided by operating activities $ 48,530 $ 40,230 $ 38,430
Add (Subtract):
Cash interest payments 14,539 97 14,637
Cash income tax payments — 405 —
Non-recurring costs 198 2,030 —
Other changes in operating assets and liabilities 32,445 17,633 (1,238)
Adjusted EBITDA $ 95,712 $ 60,395 $ 51,829
Subtract:
Capital expenditures - accrual basis (27,620) (27,673) (23,569)
Interest expense (7,675) (7,451) (8,485)
Fixed cash dividends declared (5,236) (4,798) (3,474)
Levered Free Cash Flow(1)
$ 55,181 $ 20,473 $ 16,301
The following table presents a reconciliation of the non-GAAP financial measure Adjusted Free Cash Flow to the GAAP financial measure of operating cash flow for each of the periods indicated. We use Adjusted Free Cash Flow for our shareholder return model, which began in 2022.


	Three Months Ended
	March 31, 2023		December 31, 2022		March 31, 2022
	(in thousands)
Adjusted Free Cash Flow:
Net cash provided by operating activities(1)	$	1,781	$	105,407	$	48,530
Subtract:
Maintenance capital(2)	(19,272)		(45,047)		(26,437)
Fixed dividends(3)	(9,190)		(4,557)		(5,236)
Adjusted Free Cash Flow	$	(26,681)	$	55,803	$	16,857

__________

(1) ~~Levered Free Cash Flow,~~On a consolidated basis.

(2) Maintenance capital is the capital required to keep annual production substantially flat, and is calculated as ~~defined by~~follows:


		Three Months Ended
	March 31, 2023	December 31, 2022		March 31, 2022

		(in thousands)
Consolidated capital expenditures(a)		$	(20,633)	$	(50,398)	$	(27,620)
Excluded items(b)		1,361		5,351		1,183
Maintenance capital		$	(19,272)	$	(45,047)	$	(26,437)

__________

(a) Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.

(b) Comprised of the ~~Company, includes cash paid for scheduled derivative settlements~~capital expenditures in our E&P segment that are related to strategic business expansion, such as acquisitions of ~~$32 million~~oil and ~~$33 million for~~gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes and capital expenditures in our well servicing and abandonment segment and corporate expenditures that are related to ancillary sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. For the three months ended March 31, ~~2022 and~~2023, three months ended December 31, ~~2021, respectively,~~2022, and ~~cash received of $1 million for the~~ three months ended March 31, ~~2021.~~2022 we excluded approximately $1 million, $5 million, and $0.6 million of capital expenditures related to our well servicing and abandonment segment, which was substantially all used for sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. For three months ended March 31, 2023, the three months ended December 31, 2022, and three months ended March 31, 2022 we excluded approximately $0.4 million, $0.5 million, and $0.6 million of corporate capital expenditures, which we determined was not related to the maintenance of our baseline production.

(3) Represents fixed dividends declared for the periods presented.

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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). and Adjusted Net Income (Loss) per share — diluted to net income per share — diluted.

Three Months Ended
March 31,
2022 December 31,
2021 March 31,
2021
(in thousands)
Adjusted Net Income (Loss) reconciliation to net income (loss):
Net (loss) income $ (56,810) $ 8,825 $ (21,322)
Add: discrete income tax items 293 581 —
Add (Subtract):
Losses on derivatives 132,804 32,150 25,774
Net cash (paid) received for scheduled derivative settlements (32,152) (33,421) 850
Other operating expenses 3,769 (1,726) 799
Non-recurring costs 198 2,030 —
Total additions, net 104,619 (967) 27,423
Income tax (expense) benefit of adjustments at effective tax rate(1)
(5,231) 1,765 (474)
Adjusted Net Income (Loss) $ 42,871 $ 10,204 $ 5,627
Basic EPS on Adjusted Net Income (Loss) $ 0.53 $ 0.13 $ 0.07
Diluted EPS on Adjusted Net Income (Loss) $ 0.51 $ 0.12 $ 0.07
Weighted average shares of common stock outstanding - basic 80,298 80,007 80,115
Weighted average shares of common stock outstanding - diluted 84,447 84,011 82,276


	Three Months Ended
	March 31, 2023				December 31, 2022				March 31, 2022
	(in thousands)		per share - diluted		(in thousands)		per share - diluted		(in thousands)		per share - diluted
Adjusted Net Income (Loss) reconciliation to net income (loss):
Net (loss) income	$	(5,859)	$	(0.07)	$	71,964	$	0.90	$	(56,810)	$	(0.67)

Add (Subtract):
(Gains) losses on derivatives	(39,109)		(0.49)		7,412		0.09		132,804		1.57
Net cash received (paid) for scheduled derivative settlements	47,467		0.60		(3,504)		(0.04)		(32,152)		(0.38)
Other operating (income) expenses	(286)		(0.01)		(1,023)		(0.02)		3,769		0.05

Non-recurring costs(1)	7,313		0.09		3,268		0.04		198		—

Total additions, net	15,385		0.19		6,153		0.07		104,619		1.24
Income tax expense of adjustments(2)	(4,219)		(0.05)		(1,668)		(0.02)		(28,362)		(0.34)
Adjusted Net Income	$	5,307	$	0.07	$	76,449	$	0.95	$	19,447	$	0.23

Basic EPS on Adjusted Net Income	$	0.07			$	1.00			$	0.24
Diluted EPS on Adjusted Net Income	$	0.07			$	0.95			$	0.23

Weighted average shares of common stock outstanding - basic	76,112				76,181				80,298
Weighted average shares of common stock outstanding - diluted	79,210				80,312				84,447

__________

(1) ~~Excludes discrete income tax items from~~Non-recurring costs included executive transition costs in both the ~~total additions, net line item~~first quarter of 2023 and the fourth quarter of 2022, and workforce reduction costs in the first quarter of 2023. Non-recurring costs included legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022.

(2) The federal and state statutory rates were utilized in both 2023 and 2022. We updated the disclosure in 2022 to reflect the 2022 statutory rate, instead of the effective tax ~~effect the discrete income tax items have on the current rate.~~rate previously utilized.

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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
March 31,
2022 December 31,
2021 March 31,
2021
(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses: $/boe $/boe $/boe
General and administrative expenses $ 22,942 $ 22,357 $ 17,070
Subtract:
Non-cash stock compensation expense (G&A portion) (3,706) (3,457) (3,669)
Non-recurring costs (198) (2,030) —
Adjusted general and administrative expenses $ 19,038 $ 16,870 $ 13,401
Development and production segment, and corporate $ 15,968 $ 6.64 $ 13,677 $ 5.33 $ 13,401 $ 5.50
Well servicing and abandonment segment $ 3,070 $ 3,193 $ —

~~The following table presents a reconciliation of the non-GAAP financial measure Discretionary Free Cash Flow to the GAAP financial measure of operating cash flow for each of the periods indicated.~~

~~Three Months Ended~~


	Three Months Ended
	March 31, 2023		December 31, 2022		March 31, 2022
	(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
General and administrative expenses	$	31,669	$	26,926	$	22,942
Subtract:
Non-cash stock compensation expense (G&A portion)	(4,619)		(4,248)		(3,706)
Non-recurring costs(1)	(7,313)		(3,268)		(198)
Adjusted general and administrative expenses	$	19,737	$	19,410	$	19,038

Well servicing and abandonment segment	3,126		3,296		3,070

E&P segment, and corporate	$	16,611	$	16,114	$	15,968
E&P segment, and corporate ($/boe)	$	7.60	$	6.80	$	6.64

Total mboe	2,187		2,371		2,406

__________

~~March 31, 2022~~

~~(in thousands)~~

~~Discretionary Free Cash Flow:~~

~~Operating cash flow(1)~~

~~48,530~~

~~Subtract:~~

~~Maintenance capital(2)(3)~~

~~(26,437)~~

~~Fixed dividends(4)~~

~~(5,236)~~

~~Discretionary Free Cash Flow~~

~~16,857~~

~~__________~~

(1) ~~Combined D&P business~~Non-recurring costs included executive transition costs in both the first quarter of 2023 and ~~well servicing~~the fourth quarter of 2022, and ~~abandonment.~~

~~(2) D&P business only.~~

~~(3) Maintenance capital is~~workforce reduction costs in the ~~capital required~~first quarter of 2023. Non-recurring costs included legal and professional service expenses related to ~~keep annual production flat, calculated as the capital expenditures~~acquisition and divestiture activity for the ~~D&P business during the period presented.~~

~~(4) Represents fixed dividends declared as noted on the consolidated statement~~first quarter of ~~stockholders’ equity as “Dividends declared on common stock.”~~2022.

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Liquidity and Capital Resources

Currently, we expect to fund our ~~2022~~2023 capital expenditures with cash flows from our operations. As of March 31, ~~2022,~~2023, we had liquidity of ~~$213~~$179 million, consisting of ~~$20~~$14 million cash, ~~on hand and $193~~$152 million available for borrowings under our 2021 RBL ~~Facility. The 2021 RBL~~ Facility ~~has a borrowing base of $200~~and $13 million ~~with no further borrowing restrictions beyond the covenants summarized below.~~available for borrowings under our 2022 ABL Facility (as defined below). We also have $400 million in aggregate principal amount 7% senior unsecured notes due February 2026 (the “2026 Notes”) outstanding as further discussed below.

~~Our new~~In early February 2023, we updated our shareholder return model, ~~which went into effect January 1, 2022,~~including the plan to double our quarterly fixed dividend to $0.12 per share. We also modified the allocations of Adjusted Free Cash Flow. Our goal is ~~designed~~ to ~~increase cash returns~~continue maximizing shareholder value through overall returns. In 2023, the annual cumulative allocation of Adjusted Free Cash Flow is (a) 80% primarily in the form of opportunistic debt or share repurchases, as well as strategic growth, such as acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of Directors in light of then existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors. Inclusive of the fixed dividends declared in April 2023, since our IPO, we will have returned $342 million to our shareholders, ~~further demonstrating~~which represents 311% of our ~~commitment~~IPO proceeds, consisting of $238 million in fixed and variable dividends and $104 million to repurchase 10.5 million shares, which represents 14% of our outstanding shares as of March 31, 2023. From time to time we consider bolt-on acquisitions, which may be ~~a leading returner~~used to maintain our existing production volumes and would be funded out of maintenance capital, toor may support strategic growth, in which case they would be funded from the 80% portion of our ~~shareholders. The model is based on our Discretionary~~target Adjusted Free Cash Flow.

Adjusted Free Cash Flow ~~which~~does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is ~~defined as cash flow~~available for variable dividends, debt or share repurchases, strategic acquisitions or other discretionary expenditures, since we have non-discretionary expenditures that are not deducted from ~~operations less regular fixed dividends and the capital needed to hold production flat.~~this measure. Adjusted Free Cash Flow is a non-GAAP financial measure. See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for a reconciliation of ~~Discretionary~~Adjusted Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. Under this new model, the company intends to allocate Discretionary Free Cash Flow on a quarterly basis as follows: (a) 60% predominantly in the form of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; (b) 40% in the form of discretionary capital, to be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention.

We currently believe that our liquidity, capital resources and existing cash ~~on hand~~ will be sufficient to conduct our business and operations for at least the next 12 months. In the longer term, if oil prices were to significantly decline and remain weak, we may not be able to continue to generate the same level of ~~Levered~~Adjusted Free Cash Flow we are currently generating and our liquidity and capital resources may not be sufficient to conduct our business and operations until commodity prices recover. Please see Part II, Item 1A “Risk Factors” for a discussion of known material risks, many of which are beyond our control, that could adversely impact our business, liquidity, financial condition, and results of operations.

2021 RBL Facility

~~On August 26, 2021, Berry Corp, as a guarantor, together with Berry LLC, as~~As of March 31, 2023, the borrower, entered into a credit agreement that provided for a revolving loan with up to $500 million of commitment, subject to a reserve borrowing base (as amended by the First Amendment and the Second Amendment, each as defined below, the “2021 RBL Facility”). Our initial borrowing base was $200 million. The 2021 RBL Facility ~~provides~~had a ~~letter~~$500 million revolving commitment and a $250 million borrowing base with the aggregate elected commitments of ~~credit subfacility~~$200 million, and a $20 million sublimit for the issuance of letters of credit ~~in an aggregate~~(with borrowing availability being reduced by the face amount ~~not to exceed $20 million. Issuances~~ of any letters of credit ~~reduce~~issued under the ~~borrowing availability for revolving loans~~subfacility). Availability under the 2021 RBL Facility ~~on a dollar for dollar basis.~~may not exceed the lesser of the aggregate elected commitments or the borrowing base less outstanding advances and letters of credit. The ~~2021 RBL Facility matures on August 26, 2025, unless terminated earlier in accordance with~~borrowing base under the 2021 RBL Facility ~~terms. Borrowing~~is redetermined semi-annually, and the borrowing base redeterminations generally become effective each May and November, although the borrower and the lenders may each make one interim redetermination between scheduled redeterminations. ~~In December~~The 2021 ~~we completed the first scheduled semi-annual borrowing base redetermination and entered into that certain First Amendment to Credit Agreement (the “First Amendment”), which resulted~~RBL Facility matures on August 26, 2025, unless terminated earlier in a reaffirmed borrowing base at $200 million and changes to the hedging covenants in respect of the exclusion of short puts or similar derivatives in the calculation of minimum and maximum hedging requirements. In May 2022, Berry Corp., as a guarantor, and Berry LLC, as the borrower, entered into that certain Second Amendment to Credit Agreement and Limited Consent and Waiver (the “Second Amendment”) pursuant to which, among other things, the requisite lenders underaccordance with the 2021 RBL Facility (i) consented to certain dividends and distributions and to certain investments made by Berry LLC in C&J Well Services, LLC and/or CJ Berry Well Services Management, LLC, in each case, as further described therein, (ii) waived certain minimum hedging requirements for the time periods described therein, (iii) waived any breach, default or event of default which may have arisen as a result of any of the foregoing, (iv) amended the restricted payments covenant to give us additional flexibility to make restricted payments, subject to satisfaction of certain leverage and availability conditions and other conditions described below and in the Second Amendment and (v) amended the minimum hedging covenant to not, until October 1, 2022, require hedges for any full calendar month from and after January 1, 2025, as further described in the Second Amendment.

~~If the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit~~

~~Table of Contents~~

~~under the~~terms. The 2021 RBL Facility ~~exceeds the borrowing base at any time as a result of a redetermination of the borrowing base, we have the option within 30 days~~is available to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, deliver reserve engineering reports and mortgages covering additional oil and gas properties sufficient in certain lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the next six-month period. Upon certain adjustments to the borrowing base other than a result of a redetermination, we are required to make a lump sum payment in an amount equal to the amount by which the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the 2021 RBL Facility exceeds the borrowing base. In addition, the 2021 RBL Facility provides that if there are any outstanding borrowings and the consolidated cash balance exceeds $20 million at the end of each calendar week, such excess amounts shall be used to prepay borrowings under the credit agreement. Otherwise, any unpaid principal will be due at maturity.

us for general corporate purposes, including working capital.

The outstanding borrowings under the ~~revolving loan~~2021 RBL Facility bear interest at a rate equal to, at our option, either ~~(i)~~(a) a customary base rate plus an applicable margin ranging from 2.0% to 3.0% ~~per annum, and (ii)~~or (b) a ~~customary benchmark~~term SOFR reference rate, plus an applicable margin ranging from 3.0% to 4.0% ~~per annum, and~~, in each case ~~depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.5%~~determined based on the ~~average daily unused amount of the borrowing availability~~utilization level under the 2021 RBL Facility. ~~We have~~Interest rate on base borrowings is payable quarterly in arrears and is computed on the ~~right to prepay any~~basis of a

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year of 365/366 days, and interest on term SOFR borrowings ~~under~~accrues in respect of interest periods of one, three or six months, at the ~~2021 RBL Facility with prior notice~~election of the borrower, and is computed on the basis of a year of 360 days and is payable on the last day of such interest period (or, for interest periods of six months, three months after the commencement of such interest period and at ~~any time without~~the end of such interest period.) Unused commitment fees are charged at a ~~prepayment penalty.~~

rate of 0.50%.

debt covenants.

The 2021 RBL Facility also contains ~~usual~~other customary affirmative and ~~customary~~negative covenants, as well as events of default and ~~remedies for credit facilities of a similar nature. The 2021 RBL Facility also places restrictions on~~remedies. If we do not comply with the ~~borrower and its restricted subsidiaries with respect to additional indebtedness, liens, dividends~~financial and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of the borrower’s senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

From and after August 26, 2022, the 2021 RBL Facility permits us to repurchase certain indebtedness so long as both before and after giving pro forma effect to such repurchase, no default or event of default exists, availability is equal to or greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to 1.0. The 2021 RBL Facility also permits us to make restricted payments so long as both before and after giving pro forma effect to such distribution, no default or event of default exists, availability exceeds 75% of the borrowing base, and our pro forma leverage ratio is less than or equal to 1.5 to 1.0. In addition, we can make other restricted payments in an aggregate amount not to exceed 100% of Free Cash Flow (as defined under the 2021 RBL Facility) for the fiscal quarter most recently ended prior to such distribution so long as, in addition to other conditions and limitations as describedcovenants in the 2021 RBL Facility, ~~both before and after giving pro forma effect~~the lenders may, subject to ~~such distribution, no default or event~~customary cure rights, require immediate payment of ~~default exists, availability is greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to 1.0.~~

~~Berry LLC is the borrower on the 2021 RBL Facility and Berry Corp. is the guarantor. Each future subsidiary of~~

~~Berry Corp., with certain exceptions, is required to guarantee our obligations and obligations of the other guarantors~~all amounts outstanding under the 2021 RBL Facility and ~~under certain hedging transactions and banking services arrangements (the “Guaranteed Obligations”). The lenders under~~terminate the 2021 RBL Facility hold a mortgage on at least 90% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions.

commitments thereunder.

As of March 31, ~~2022,~~2023, we had no$41 million borrowings outstanding, $7 million in letters of credit outstanding and approximately ~~$193~~$152 million of available borrowing capacity under the 2021 RBL Facility.

2022 ABL Facility

Subject to satisfaction of customary conditions precedent to borrowing, as of March 31, 2023, C&J and C&J Management could borrow up to the lesser of (x) $15 million and (y) the borrowing base under the 2022 ABL Facility, with a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $7.5 million (with borrowing availability being reduced by the face amount of any letters of credit issued under the subfacility). The “borrowing base” is an amount equal to 80% of the balance due on eligible accounts receivable, subject to reserves that Tri Counties Bank may implement in its reasonable discretion. Interest on the outstanding principal amount of the revolving loans under the 2022 ABL Facility accrues at a per annum rate equal to 1.25% in excess of The Wall Street Journal Prime Rate. The “Wall Street Journal Prime Rate” is the variable rate of interest, on a per annum basis, which is announced and/or published in the “Money Rates” section of The Wall Street Journal from time to time as its “Prime Rate”. The rate will be redetermined whenever The Wall Street Journal Prime Rate changes. Interest is due quarterly, in arrears. The 2022 ABL Facility matures on June 5, 2025, unless terminated in accordance with the 2022 ABL Facility terms.

The 2022 ABL Facility also contains other customary affirmative and negative covenants, as well as events of default and remedies. If CJWS does not comply with the financial and other covenants in the 2022 ABL Facility, the lender may, subject to customary cure rights, require immediate payment of all amounts outstanding under the 2022 ABL Facility and terminate the commitment thereunder. CJWS’s obligations under the 2022 ABL Facility are not guaranteed by Berry Corp. or Berry LLC and Berry Corp. and Berry LLC do not and are not required to provide any credit support for such obligations.

In March 2023, we entered into the Amendment to Revolving Loan and Security Agreement (the “First Amendment”). The First Amendment, in addition to other changes described therein, amended the 2022 ABL Facility to substitute certain collateral.

As of March 31, 2023, CJWS had no borrowings and $2 million letters of credit outstanding with $13 million of available borrowing capacity under the 2022 ABL Facility.

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Senior Unsecured Notes

In February 2018, Berry LLC completed a private issuance of $400 million in aggregate principal amount of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount.

The indenture governing the 2026 Notes contains customary covenants and events of default (in some cases, subject to grace periods). We were in compliance with all covenants under the 2026 Notes as of March 31, 2023.

Debt Repurchase Program

Hedging

We have protected a significant portion of our anticipated cash flows ~~in 2022~~ through ~~2024, using~~ our commodity hedging program, including swaps, puts, calls and collars. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge ~~natural~~ gas purchases to protect against price increases. In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. 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 current hedging positions. For information regarding risks related to our hedging program, see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry” in our Annual Report.

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As of April ~~28, 2022,~~30, 2023, we had the following ~~hedges for our~~ crude oil production and gas ~~purchases.~~purchases hedges.


		Q2 2022		Q3 2022		Q4 2022		FY 2023		FY 2024			Q2 2023		Q3 2023		Q4 2023		FY 2024		FY 2025		FY 2026
Brent
Brent - Crude Oil production												Brent - Crude Oil production
Swaps	Swaps											Swaps
Hedged volume (bbls)	Hedged volume (bbls)	1,360,500		1,380,000		1,288,000		3,433,528		1,917,000		Hedged volume (bbls)	1,387,750		1,211,717		1,196,000		3,412,817		99,337		9,518
Weighted-average price ($/bbl)	Weighted-average price ($/bbl)	$	77.10	$	77.73	$	76.07	$	73.06	$	75.52	Weighted-average price ($/bbl)	$	77.01	$	76.26	$	76.18	$	76.07	$	71.55	$	71.55

Put Spreads

Sold Calls												Sold Calls
Hedged volume (bbls)												Hedged volume (bbls)	364,000		368,000		368,000		1,098,000		2,486,127		472,500
Weighted-average price ($/bbl)												Weighted-average price ($/bbl)	$	106.00	$	106.00	$	106.00	$	105.00	$	91.11	$	82.21
Purchased Puts (net)(1)												Purchased Puts (net)(1)
Hedged volume (bbls)												Hedged volume (bbls)	546,000		552,000		552,000		1,281,000		2,486,127		472,500
Weighted-average price ($/bbl)												Weighted-average price ($/bbl)	$	50.00	$	50.00	$	50.00	$	50.00	$	58.53	$	60.00
Sold Puts (net)(1)												Sold Puts (net)(1)
Hedged volume (bbls)	Hedged volume (bbls)	364,000		368,000		368,000		2,190,000		1,281,000		Hedged volume (bbls)	132,668		184,000		154,116		183,000		—		—
Weighted-average price ($/bbl)	Weighted-average price ($/bbl)	$50/$40		$50/$40		$50/$40		$50/$40		$50/$40		Weighted-average price ($/bbl)	$	40.00	$	40.00	$	40.00	$	40.00	$	—	$	—

Producer Collars
Hedged volume (bbls)		—		—		—		1,460,000		1,098,000
Weighted-average price ($/bbl)		$	—	$	—	$	—	$106/$40		$105/$40
Henry Hub

Henry Hub - Natural Gas purchases												Henry Hub - Natural Gas purchases
Consumer Collars	Consumer Collars											Consumer Collars
Hedged volume (mmbtu)												Hedged volume (mmbtu)	1,820,000		—		—		—		—		—
Weighted-average price ($/mmbtu)												Weighted-average price ($/mmbtu)	$4.00/ $2.75		$	—	$	—	$	—	$	—	$	—
NWPL - Natural Gas purchases												NWPL - Natural Gas purchases
Swaps												Swaps
Hedged volume (mmbtu)												Hedged volume (mmbtu)	3,640,000		3,680,000		3,680,000		10,980,000		6,080,000		—
Weighted-average price ($/mmbtu)												Weighted-average price ($/mmbtu)	$	5.34	$	5.34	$	5.34	$	4.21	$	4.27	$	—
Gas Basis Differentials												Gas Basis Differentials
NWPL/HH - Natural Gas Purchases												NWPL/HH - Natural Gas Purchases
Hedged volume (mmbtu)	Hedged volume (mmbtu)	3,030,000		3,680,000		3,680,000		5,430,000		—		Hedged volume (mmbtu)	—		—		610,000		—		—		—
Weighted-average price ($/mmbtu)	Weighted-average price ($/mmbtu)	$4.00/$2.75		$4.00/$2.75		$4.00/$2.75		$4.00/$2.75		$	—	Weighted-average price ($/mmbtu)	$	—	$	—	$	1.12	$	—	$	—	$	—

__________

(1) Purchase puts and sold puts with the same strike price have been presented on a net basis.

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


		Three Months Ended						Three Months Ended
		March 31, 2022		December 31, 2021		March 31, 2021				March 31, 2023		December 31, 2022		March 31, 2022
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	$	92.25	$	75.11	$	56.89		Realized sales price, before the effects of derivative settlements	$	74.69	$	80.61	$	92.25
Effects of derivative settlements	Effects of derivative settlements	$	(15.38)	$	(20.50)	$	(12.08)		Effects of derivative settlements	$	(3.65)	$	(7.22)	$	(15.38)
Oil with hedges ($/bbl)		$	76.87	$	54.61	$	44.81
Realized sales price, after the effects of derivatives									Realized sales price, after the effects of derivatives	$	71.04	$	73.39	$	76.87
Purchased Natural Gas (per mmbtu):	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	$	6.30	$	6.66	$	6.93		Purchase price, before the effects of derivative settlements	$	20.74	$	9.62	$	6.30
Effects of derivative settlements	Effects of derivative settlements	$	(0.29)	$	(1.51)	$	(4.51)		Effects of derivative settlements	$	(11.86)	$	(2.28)	$	(0.29)
Purchased Natural Gas with hedges		$	6.01	$	5.15	$	2.42
Purchase price, after the effects of derivatives settlements									Purchase price, after the effects of derivatives settlements	$	8.88	$	7.34	$	6.01

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Cash Dividends

The ~~Board of Directors approved a $0.13 per share variable dividend~~following table represents the regular fixed cash dividends on our common stock and variable dividends approved by our Board of Directors.




	First Quarter
Fixed Dividends	$	0.12
Variable Dividends(1)	—
Total	$	0.12

__________

(1) Variable Dividends are declared the quarter following the period of results (the period used to determine the variable divided based on ~~our first quarter results,~~the shareholder return model). The table notes total dividends earned in each quarter. There is no variable dividend for Q1 2023.

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~~which is expected~~The Company anticipates that it will continue to ~~be paid in June 2022. As of April 30, 2022, the Company has paid approximately $86 million in~~pay quarterly cash dividends ~~since the inception of our dividend program~~ in the ~~third quarter~~future. However, the payment and amount of ~~2018. When combined with~~future dividends remain within the ~~$52 million in stock repurchases, this represents a 125% return~~discretion of the Board and will depend upon the Company’s future earnings, financial condition, capital ~~on our IPO net proceeds.~~requirements and other factors.

Stock Repurchase Program

We did not repurchase any shares during the three months ended March 31, 2023. As of March 31, 2023, the Company had repurchased a total of 10,528,704 shares under the stock repurchase program for approximately $104 million in aggregate, which is 14% of outstanding shares. As previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company intends to allocate a portion of Adjusted Free Cash Flow to opportunistic share repurchases.

~~Debt Repurchase Program~~

~~In February 2020, our Board~~

Table 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 do not obligate Berry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any notes under this program.Contents

Statements of Cash Flows

The following is a comparative cash flow summary:

Three Months Ended
March 31,
2022 2021
(in thousands)
Net cash:
Provided by operating activities $ 48,530 $ 38,430
Used in investing activities (36,560) (19,937)
Used in financing activities (9,293) (1,688)
Net increase in cash and cash equivalents $ 2,677 $ 16,805

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	Three Months Ended March 31,
	2023		2022
	(in thousands)
Net cash:
Provided by operating activities	$	1,781	$	48,530
Used in investing activities	(30,460)		(36,560)
Used in financing activities	(3,454)		(9,293)
Net (decrease) increase in cash and cash equivalents	$	(32,133)	$	2,677

Operating Activities

Cash provided by operating activities ~~increased~~decreased for the three months ended March 31, ~~2022~~2023 by approximately ~~$10~~$47 million when compared to the three months ended March 31, ~~2021, and the most significant increases were sales~~2022, primarily due to an increase in operating expenses of $70 million ~~and~~(excluding CJWS), a decrease in revenue of $6$44 million, an increase in ~~unhedged operating~~general and administrative expenses of $8 million (excluding CJWS and including an increase in non-recurring expenses of $7 million), a decrease in working capital of $7 million and an increases in taxes, other than income taxes of $4 million, partially offset by an increase ~~of $33 million~~ in derivative settlements ~~paid, a decrease~~received of ~~$27~~$80 million, ~~in working capital and other changes and~~ an increase of $6$2 million related to net margin for CJWS, and a decrease in ~~general and administrative~~other operating expenses ~~most~~ of ~~which was the impact from well servicing and abandonment operations acquired in late 2021.~~

~~Investing Activities~~$4 million.

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


		Three Months Ended March 31,						Three Months Ended March 31,
		2022		2021				2023		2022
		(in thousands)				(in thousands)
Capital expenditures:	Capital expenditures:						Capital expenditures:
Capital expenditures	Capital expenditures	$	(27,669)	$	(23,569)		Capital expenditures	$	(20,633)	$	(27,620)

Changes in capital expenditures accruals	Changes in capital expenditures accruals	9,992		3,508			Changes in capital expenditures accruals	(6,170)		9,992

Acquisitions, net of cash received	Acquisitions, net of cash received	(18,932)		—			Acquisitions, net of cash received	(3,657)		(18,932)
Proceeds from sale of properties and equipment and other		—		124

Cash used in investing activities	Cash used in investing activities	$	(36,609)	$	(19,937)		Cash used in investing activities	$	(30,460)	$	(36,560)

Cash used in investing activities ~~increased $17~~decreased $6 million for the three months ended March 31, ~~2022~~2023 when compared to the same period in ~~2021,~~2022, primarily due to a decrease in cash used for acquisitions of $15 million, partially offset by an increase in cash used for ~~acquisitions when compared to the same period in 2021.~~capital expenditures and related accruals of $9 million.

Financing Activities

Cash used byin financing activities for the three months ended March 31, 2023 was primarily for dividends paid of $40 million and for taxes on equity awards of $4 million, offset by net borrowings under the RBL credit facility of $41 million. Cash used in financing activities in the same period in 2022 was primarily for dividends paid of $5 million and for taxes on equity awards of $4 million. ~~In 2021, the cash used was primarily for taxes on equity awards of $1 million.~~

~~Guarantor Financial Information~~

~~The 2026 Notes and 2021 RBL Facility were issued by Berry LLC (“Issuer”) and are guaranteed by Berry Corp (“Parent Guarantor”). See Note 3~~—Debt in the 2021 Annual Report for further information. The Issuer is 100% owned by the Parent Guarantor. The Parent Guarantor has no independent assets or operations and is subject to a passive holding company covenant under the 2021 RBL Facility. Any guarantees of potential future registered debt securities by Berry Corp. or Berry LLC would be full and unconditional. 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 restrictions under the 2021 RBL Facility. None of the assets of Berry Corp. or Berry LLC represent restricted net assets.

For cash management purposes, the Company transfers cash between the Parent Guarantor, Issuer and non-guarantors through intercompany receivables and payables. While the non-guarantor subsidiaries do not guarantee the Issuer's obligations under our outstanding debt, the transfer of cash under these activities facilitates the ability of the recipient to make specified third-party payments for principal and interest on the 2026 Notes and 2021 RBL Facility.

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The summarized financial information of the Guarantor and Issuer is presented below on a combined basis after the elimination of: (i) intercompany transactions among such entities and (ii) equity in earnings from and investments in the non-guarantor subsidiaries. Transactions with, and amounts due to or from, non-guarantor subsidiaries are separately disclosed.


	~~Three Months Ended~~
	~~March 31, 2022~~
	~~(in thousands)~~
	~~(unaudited)~~
~~Total revenue to third parties~~	$	~~216,104~~
~~Total expenses~~	$	~~135,487~~



~~Net loss~~	$	~~(56,524)~~

As of March 31, 2022 As of December 31, 2021
(in thousands)
(unaudited)
Receivables from non-guarantor subsidiaries $ 4,698 $ 16,792
Other current assets 136,070 114,983
Total current assets $ 140,768 $ 131,775
Noncurrent assets $ 1,339,053 $ 1,317,241
Other current liabilities $ 231,366 $ 179,691
Other noncurrent liabilities $ 617,745 $ 576,681

Balance Sheet Analysis

The changes in our balance sheet from December 31, ~~2021~~2022 to March 31, ~~2022~~2023 are discussed below.


		March 31, 2022		December 31, 2021			March 31, 2023		December 31, 2022
		(in thousands)					(in thousands)
Cash and cash equivalents	Cash and cash equivalents	$	17,960	$	15,283	Cash and cash equivalents	$	14,117	$	46,250
Accounts receivable, net	Accounts receivable, net	$	111,961	$	86,269	Accounts receivable, net	$	83,113	$	101,713
Derivative instruments assets - current and long-term	Derivative instruments assets - current and long-term	$	—	$	1,070	Derivative instruments assets - current and long-term	$	6,355	$	36,443

Other current assets	Other current assets	$	36,567	$	45,946	Other current assets	$	34,885	$	33,725
Property, plant & equipment, net	Property, plant & equipment, net	$	1,323,028	$	1,301,349	Property, plant & equipment, net	$	1,346,882	$	1,359,813
Deferred income taxes asset - long-term	Deferred income taxes asset - long-term	$	171	$	—	Deferred income taxes asset - long-term	$	45,371	$	42,844
Other noncurrent assets	Other noncurrent assets	$	5,040	$	6,562	Other noncurrent assets	$	9,518	$	10,242
Accounts payable and accrued expenses	Accounts payable and accrued expenses	$	154,084	$	157,524	Accounts payable and accrued expenses	$	141,063	$	203,101
Derivative instruments liabilities - current and long-term	Derivative instruments liabilities - current and long-term	$	148,680	$	48,202	Derivative instruments liabilities - current and long-term	$	23,031	$	44,748

Long-term debt	Long-term debt	$	394,846	$	394,566	Long-term debt	$	437,036	$	395,735
Deferred income taxes liability - long-term		$	—	$	1,831

Asset retirement obligations - long-term	Asset retirement obligations - long-term	$	142,999	$	143,926	Asset retirement obligations - long-term	$	156,411	$	158,491
Other noncurrent liabilities	Other noncurrent liabilities	$	23,692	$	17,782	Other noncurrent liabilities	$	29,764	$	28,470
Stockholders’ equity	Stockholders’ equity	$	630,426	$	692,648	Stockholders’ equity	$	752,936	$	800,485

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

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The ~~$26~~$19 million ~~increase~~decrease in accounts receivable was ~~driven by $23~~primarily attributable to lower sales volumes and prices in the E&P segment.

The $1 million ~~higher sales period-over-period,~~increase in other current assets is primarily due to ~~higher crude prices. Another $3 million of the increase is attributable to higher sales from the well servicing and abandonment segment.~~

~~The $102~~a $2 million increase in materials and oil inventories partially offset by a $1 million decrease in prepaid expenses.

The $13 million decrease in property, plant and equipment was primarily due to year to date depreciation of $37 million offset by $20 million in capital investments and $4 million in acquisitions.

The $3 million increase in deferred income taxes - long term was primarily due to the increase in the net operating loss carryforward for the first quarter loss.

The $1 million decrease in other noncurrent assets was primarily due to the amortization of deferred financing costs.

The $62 million decrease in accounts payable and accrued expenses included decreases of $31 million in accrued expenses mostly for fuel gas purchases, $22 million in royalties payable primarily due to an annual payment in the first quarter of 2023, $9 million in trade accounts payable, and $7 million in accrued interest partially offset by an increase of $5 million in taxes other than income taxes and $2 million in dividends payable.

The $8 million increase in net derivative liabilities, which includes the derivative assets, is due to the change from a net liability of ~~$47~~$8 million at December 31, ~~2021~~2022 to a net liability of ~~$149~~$17 million as of March 31, ~~2022.~~2023. Changes to mark-to-market derivative values at the end of each period result from differences in the forward curve prices relative to the contract fixed prices, changes in positions held and settlements received and paid throughout the periods.

The $9$41 million decrease in other current assets was primarily due to a $3 million refund of prepaid permitting fees, $3 million for adjustments related to transition services provided for recent divestitures, $3 million refund of letter of credit collateral, $4 million expensing of prepaid expenses, mostly insurance, for the well servicing and abandonment segment, partially offset by an increase of $3 million in prepaid property taxes and other fees.

~~The $22 million~~ increase in property, plant and equipment was primarily due to $33 million in capital investments, $19 million of acquisitions primarily Antelope Creek oil and gas properties in Utah, as well as $8 million for operating leases basedlong-term debt reflects borrowings on ~~the adoption of new lease accounting rule ASC 842 in the quarter, offset by year to date depreciation of $37 million.~~

~~The $2 million decrease in other noncurrent assets was primarily due to an adjustment to the provisional amounts preliminarily assigned as intangibles for the CJWS acquisition as of December 31, 2021.~~

~~The $3 million decrease in accounts payable and accrued expenses included $7 million in lower interest accrual due to the semi-annual interest payment~~our 2021 RBL Facility made in the first quarter ~~2022, $6 million in lower royalties payable due to the annual payment made in the first quarter 2022, $2 million in other accrued expenses including greenhouse gas, partially offset by increases~~ of ~~$5 million in well servicing~~2023 and ~~abandonment segment payables,~~outstanding as ~~well as $3 million in taxes, other than income taxes, $2 million in trade payables and $2 million for the current portion~~ of ~~lease liability based on the adoption of ASC 842 in the quarter.~~March 31.

The $2 million ~~decrease in the deferred income tax liability - long-term is due to a decrease in deferred DD&A and the impact of the Piceance assets divestiture.~~

~~The $1 million~~ decrease in the long-term portion of the asset ~~retirements~~retirement obligations from ~~$144~~$158 million at December 31, ~~2021~~2022 to ~~$143~~$156 million at March 31, ~~2022~~2023 was due to $5 million of liabilities settled during the period ~~and $1 million reduction due to property sales~~

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offset by $3 million of accretion ~~expense and $2 million of liabilities incurred.~~expense.

The $6$1 million increase in other noncurrent liabilities was ~~primarily~~ due ~~to $7 million for the long term portion of lease liability based on the adoption of ASC 842 in the quarter, offset by $1 million lower~~to non-current greenhouse gas liabilities ~~compared to year end.~~incurred.

The ~~$62~~$48 million decrease in stockholders’ equity was due to ~~the net loss of $57 million, $5~~$42 million of common stock dividends declared, a $6 million net loss and $4 million of shares withheld for payment of taxes on equity ~~awards. These decreases were partially~~awards, offset by $4$5 million of stock-based equity awards, net of taxes.

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Lawsuits, Claims, Commitments, and Contingencies

Securities Litigation ~~Matter~~Matters

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On October 20, 2022, a shareholder derivative lawsuit was filed in the United States District Court for the Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that piggy-backs on the securities class action referenced above and which is currently pending before the same Court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27, 2023, the court granted the parties’ joint stipulated request to stay the derivative action pending resolution of the related securities class action. On January 20, 2023, a second shareholder derivative lawsuit was filed, this time in the United States District Court for the District of Delaware, by putative stockholder Molly Karp allegedly on behalf of the Company, again piggy-backing on the securities class action referenced above. This complaint, similar to the first derivative complaint, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the securities violations alleged in the securities class action. In addition, the complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry’s 2022 Proxy Statement was false and misleading in that it suggested the Company’s internal controls were sufficient and the board of directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case. The defendants believe the claims in the shareholder derivative actions are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to this matter.

Contractual Obligations

The following is a summary of our commitments and contractual obligations as of March 31, ~~2022:~~2023:


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

Off-Balance Sheet arrangements:	Off-Balance Sheet arrangements:											Off-Balance Sheet arrangements:
Processing and transportation contracts(1)		$	94,762	$	10,301	$	18,685	$	16,165	$	49,611
Lease obligations		10,154		2,374		3,828		3,361		591
Transportation contracts(1)												Transportation contracts(1)	$	85,405	$	10,471	$	17,241	$	16,165	$	41,528

Other purchase obligations(2)	Other purchase obligations(2)	17,100		14,700		2,400		—		—		Other purchase obligations(2)	17,100		8,400		8,700		—		—
Total contractual obligations	Total contractual obligations	$	122,016	$	27,375	$	24,913	$	19,526	$	50,202	Total contractual obligations	$	102,505	$	18,871	$	25,941	$	16,165	$	41,528

__________

(1) 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 pipeline transportation of natural gas to market and between markets, as well as gathering and processing of natural gas.

(2) Amounts include a drilling commitment in California, for which we are required to drill 57 wells with ~~an estimated total cost and~~a minimum commitment of $17.1 million by ~~April 2023. 49~~June 2024. In November 2022, the drilling commitment was revised to require 28 of those wells ~~are estimated at $14.7 million and are required~~ to be drilled ~~within one year.~~by October 2023, with a minimum commitment of $8.4 million.

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 and~~ Part II, Item 7 “Critical Accounting Policies and Estimates” in ~~the~~our most recent Annual Report.

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Cautionary Note Regarding Forward-Looking Statements

The information included or incorporated by reference in this Quarterly Report includes forward-looking statements within the meaning of Section 27A of the Securities Act ~~of 1933~~ and Section 21E of the ~~Securities~~ Exchange ~~Act of 1934.~~Act. All statements other than statements of historical facts included in this Quarterly Report that address plans, activities, events, objectives, goals, strategies, or developments that the Company expects, believes or anticipates will or may occur in the future, such as those regarding our financial position, liquidity, cash flows (including, but not limited to, ~~Discretionary~~Adjusted Free Cash Flow), financial and operating results, capital program and development and production plans, operations and business strategy, potential acquisition and other strategic opportunities, reserves, hedging activities, capital expenditures, return of capital, our ~~new~~ shareholder return model and the payment of future dividends, future repurchases of stock or debt, capital investments, our ESG strategy and the initiation of new projects or business in connection therewith, recovery factors, and other guidance, are forward-looking statements. These statements are based upon various assumptions, many of which are based, in turn, upon further assumptions. Although we believe that these assumptions were reasonable when made, these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control. Therefore, such forward-looking statements involve significant risks and uncertainties that could materially affect our expected financial position, financial and operating results, liquidity, cash flows (including, but not limited to, ~~Discretionary~~Adjusted Free Cash Flow), and business prospects. 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, 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” in our most recent Annual Report 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 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;

•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 permitting, 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;

•inflation levels, particularly the recent rise to historically high ~~levels;~~levels, and government efforts to reduce inflation, including increased interest rates;

•the length, scope and severity of the ongoing COVID-19 pandemic or the emergence of a new 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, global supply chain disruptions and labor constraints;

•global economic trends, geopolitical risks and general economic and industry conditions, such as the economic impact from the COVID-19 pandemic, including the global supply chain disruptions and the government interventions into the financial markets and economy, among other factors;

•overall domestic and global political and economic conditions, including the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions, including the ongoing conflict in ~~Ukraine;~~Ukraine, or a prolonged recession;

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•those resulting from the COVID-19 ~~pandemic and from~~ pandemic;

•the actions of foreign producers, importantly including OPEC+ and ~~change~~changes in OPEC+'s production levels;

•volatility of oil, natural gas and NGL prices, including as a result of political instability, armed conflict or economic sanctions;

•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, including due to the actions of foreign producers, importantly including OPEC+ and change in OPEC+'s production levels;;

•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;

•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;

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

•drilling and production results, 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;

•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;

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•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 cyberattacks; and.

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

Any forward-looking statement speaks only as of the date on which such statement is made. Except as required by law, we undertake no responsibility to to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise except as required by applicable law.

All forward-looking statements, expressed or implied, included in this Quarterly Report 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.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

As of March 31, ~~2022,~~2023, there 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~~(incorporating Item 7A)- Quantitative and Qualitative Disclosures About Market Risk, in the ~~2021~~2022 Annual Report, except as discussed below.

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 significant decline.

We have historically hedged a large portion of our expected crude oil and our natural gas production, as well as our natural gas purchase requirements to reduce exposure to fluctuations in commodity prices. We use derivatives such as swaps, calls, puts and collars to hedge. We do not enter into derivative contracts for speculative trading purposes and we have not accounted for our 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 March 31, ~~2022,~~2023, the fair value of our hedge positions was a net liability of approximately ~~$149~~$17 million. A 10% increase in the oil and natural gas index prices above the March 31, ~~2022~~2023 prices would result in a net liability of approximately ~~$225~~$76 million; conversely, a 10% decrease in the oil and natural gas index prices below the March 31, ~~2022~~2023 prices would result in a net ~~liability~~asset of approximately ~~$54~~$47 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. Additionally, we cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our 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, Chief Financial Officer and Chief ~~Financial~~Accounting 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)~~Act) 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 March 31, ~~2022.~~2023.

The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC. The Company’s disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the Chief Executive Officer and the Vice President, Chief Financial Officer and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting during the first quarter of ~~2022~~2023 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

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not the case. The defendants believe the claims in the shareholder derivative actions are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to this matter.

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, ~~2021~~2022 included in the Annual Report.

Item 1A. Risk Factors

We are subject to 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.

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

Stock Repurchase Program

We did not repurchase any shares during the three months ended March 31, 2023. As of March 31, 2023, the Company had repurchased a total of 10,528,704 shares under the stock repurchase program for approximately $104 million in aggregate, which is 14% of outstanding shares. As previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company intends to allocate a portion of Adjusted Free Cash Flow to opportunistic share repurchases.

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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~~Fourth Amended and Restated Bylaws of Berry Corporation (bry) (incorporated by reference to Exhibit ~~3.2~~3.1 of Form 8-K filed ~~February 19, 2020)~~January 31, 2023)
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*						~~Berry Corporation (bry) 2022 Omnibus Incentive Plan,~~Amendment to Revolving Loan and Security Agreement, dated March ~~1, 2022~~
10.2*						~~Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock Unit Award Agreement with Total Shareholder Return Performance Criteria~~
10.3*						~~Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock Unit Award Agreement with CROIC Performance Criteria~~
10.4*						~~Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock Unit Award Agreement with~~14, 2023, between C&J Well Services, ~~ROCI Performance Criteria (Executive Employment Agreement)~~
10.5*						LLC and CJ Berry ~~Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock Unit Award Agreement with C&J~~ Well Services ~~ROCI Performance Criteria~~
10.6*						~~Second Amendment to Credit Agreement, dated May 2, 2022, by and among Berry Petroleum Company,~~Management, LLC, as borrower, ~~Berry Corporation (bry),~~and Tri Counties Bank, as ~~guarantor, JP Morgan Chase Bank, N.A., as administrative agent and the lenders parties thereto~~lender
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.

5760

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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 and infrequent items.

“Adjusted ~~G&A~~Free Cash Flow” or which is defined as cash flow from operations less regular fixed dividends and maintenance capital.

“Adjusted General and Administrative Expenses” is a non-GAAP financial measure defined as general and administrative expenses adjusted for non-cash stock compensation expense ~~as well as~~and 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 and infrequent items, and the income tax expense or benefit of these adjustments using our effective tax rate.

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

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

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

“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.

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

“b~~oe/~~boe/d” means 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.

“b~~btu~~tu” 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~~”CalGEM” is an abbreviation for the California Geologic Energy Management Division.

“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.

~~Table of~~ ~~Contents~~

“~~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”).~~

“~~CEQA~~”CEQA” is an abbreviation for the California Environmental Quality Act which, among other things, requires certain governmental agencies to conduct environmental review of projects for which the agency is issuing a permit.

“~~CJWS~~”CJWS” refers to C&J Well Services, LLC and CJ Berry Well Services Management, LLC, the two entities that

constitute our upstream well servicing and abandonment business segment in California.

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“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.

~~“Discretionary Free Cash Flow” is a non-GAAP financial measure defined as cash flow from operations less regular fixed dividends and the capital needed to hold production flat.~~

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

“D&P” means our development and production business segment, which is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah.

“~~EH&S~~”HSE” 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.~~

~~Table of~~ ~~Contents~~

Safety, and Environmental.

“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.

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

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

“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.

“~~Fugitive Emissions” means accidental emissions of vapors or gases from pressurized containment, either due to faulty equipment, leakage or other unforeseen mishaps.~~

“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.

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

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

“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.

~~Table of~~ ~~Contents~~

“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.

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

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

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

“mb~~mbbl/~~bl/d” means mbbl per day.

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

“mboe~~mboe/~~/d” means mboe per day.

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

“mmbmmbblbl” means one million barrels of oil, condensate or NGLs.

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

“mmb~~mmbtu~~tu” means one million btus.

“mmb~~mmbtu/~~tu/d” means mmbtu per day.

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

“mm~~mmcf/~~cf/d” means 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.

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“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.

~~Table of~~ ~~Contents~~

“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.

“Oil” means crude oil or condensate.

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

“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.

~~Table of~~ ~~Contents~~

“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.

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“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.

“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).

~~Table of~~ ~~Contents~~

“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

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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.

“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.

~~Table of~~ ~~Contents~~

“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.~~CERCLA.

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

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“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 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.

“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.

~~“Well servicing and abandonment” means the CJWS business segment.~~

“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:	May ~~4, 2022~~3, 2023	/s/ ~~Cary Baetz~~Fernando Araujo
		~~Cary Baetz~~Fernando Araujo
		Chief Executive ~~Vice President and~~Officer
		~~Chief Financial Officer~~(Principal Executive Officer)
		~~(Principal Financial Officer)~~


Date:	May ~~4, 2022~~3, 2023	/s/ M. S. Helm
		Michael S. Helm
		Vice President, Chief Financial Officer and Chief Accounting Officer
		(Principal Financial Officer and 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	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2019
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5456
Item 4.	Controls and Procedures	5457

Part II – Other Information
Item 1.	Legal Proceedings	5558
Item 1A.	Risk Factors	5559
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities	5659
Item 6.	Exhibits	5760
	Glossary of Terms	5861
	Signatures	6668



	Three-Month Period Ended March 31, 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


	Three Months Ended March 31, 2022
	Development & Production		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)









Revenues - excluding hedges	$	216,104	$	39,836	$	—	$	255,940


Net loss before income taxes	$	(34,291)	$	(284)	$	(25,586)	$	(60,161)

Adjusted EBITDA	$	105,649	$	3,300	$	(13,237)	$	95,712
Capital expenditures	$	26,437	$	628	$	555	$	27,620

Total assets	$	1,471,358	$	73,887	$	(50,518)	$	1,494,727


	As of March 31, 2022
	Operating Leases
	(in thousands)
2022	$	1,779
2023	1,903
2024	1,603
2025	1,551
2026	1,555
Thereafter	1,213
Total lease payments	9,604
Less imputed interest	(1,033)
Total lease obligations	8,571
Less current obligations	(1,779)
Long-term lease obligations	$	6,792


	Utah (Uinta basin)									Colorado (Piceance basin)(4)
	Three Months Ended									Three Months Ended
	March 31, 2022			December 31, 2021			March 31, 2021			March 31, 2022			December 31, 2021			March 31, 2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales	$	23,038		$	19,762		$	15,889		$	1,056		$	3,294		$	6,194
Operating income(1)	$	11,173		$	8,713		$	7,433		$	610		$	3,050		$	5,039
Depreciation, depletion, and amortization (DD&A)	$	803		$	597		$	554		$	9		$	38		$	38

Average daily production (mboe/d)	4.1			4.2			4.0			0.4			1.0			1.2
Production (oil % of total)	53		%	51		%	49		%	—		%	1		%	2		%
Realized sales prices:
Oil (per bbl)	$	83.02		$	66.56		$	52.08		$	89.41		$	84.38		$	25.80
NGLs (per bbl)	$	47.03		$	47.45		$	26.81		$	—		$	—		$	—
Gas (per mcf)	$	5.93		$	5.63		$	6.65		$	5.12		$	5.54		$	9.83
Capital expenditures(2)	$	9,752		$	1,007		$	392		$	—		$	—		$	1


	As of March 31, 2022		As of December 31, 2021
	(in thousands)
	(unaudited)
Receivables from non-guarantor subsidiaries	$	4,698	$	16,792
Other current assets	136,070		114,983
Total current assets	$	140,768	$	131,775
Noncurrent assets	$	1,339,053	$	1,317,241


Other current liabilities	$	231,366	$	179,691


Other noncurrent liabilities	$	617,745	$	576,681