bry-20250331

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, 2025


☐						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 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,” 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, 2025 77,596,202

Table of Contents


		Page
Part I – Financial Information
Item 1.	Financial Statements
	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	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 4.	Controls and Procedures	55

Part II – Other Information
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities	56
Item 5.	Other Information	57
Item 6.	Exhibits	58
	Glossary of Terms	59
	Signatures	66

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

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31, 2025		December 31, 2024
	(in thousands, except share amounts)
	Unaudited
ASSETS
Current assets:
Cash and cash equivalents	$	39,002	$	15,336
Restricted cash	260		14,700
Accounts receivable, net of allowance for doubtful accounts of $655 at March 31, 2025 and December 31, 2024	74,718		77,630
Derivative instruments	11,763		4,526

Other current assets	35,371		37,451
Total current assets	161,114		149,643
Noncurrent assets:
Oil and natural gas properties	2,004,639		1,975,456
Accumulated depletion and amortization	(918,083)		(735,304)
Total oil and natural gas properties, net	1,086,556		1,240,152
Other property and equipment	170,873		171,303
Accumulated depreciation	(103,718)		(91,075)
Total other property and equipment, net	67,155		80,228

Deferred income taxes	68,636		26,779
Derivative instruments	10,217		11,697
Other noncurrent assets	10,660		9,187
Total assets	$	1,404,338	$	1,517,686
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	131,348	$	133,809
Derivative instruments	982		7,703


Current portion of long-term debt, net	45,000		45,000
Income taxes payable	6,099		1,368
Total current liabilities	183,429		187,880
Noncurrent liabilities:
Long-term debt, net	374,478		384,633

Deferred income taxes	—		1,612
Asset retirement obligations	184,114		185,283
Other noncurrent liabilities	30,849		27,642
Commitments and Contingencies - Note 4
Stockholders' equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 89,600,013 and 88,942,805 shares issued; and 77,596,202 and 76,938,994 shares outstanding, at March 31, 2025 and December 31, 2024, respectively)	90		89
Additional paid-in-capital	785,464		787,953
Treasury stock, at cost (12,003,811 shares at March 31, 2025 and December 31, 2024, respectively)	(113,768)		(113,768)
(Accumulated deficit) retained earnings	(40,318)		56,362
Total stockholders' equity	631,468		730,636
Total liabilities and stockholders' equity	$	1,404,338	$	1,517,686

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,
	2025		2024
	(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	147,862	$	166,318
Services revenue	23,664		31,683
Electricity sales	4,967		4,243
Gains (losses) on oil and gas sales derivatives	5,475		(71,200)

Marketing and other revenues	683		5,036
Total revenues and other	182,651		136,080
Expenses and other:
Lease operating expenses	57,282		61,276
Costs of services	20,825		27,304
Electricity generation expenses	1,209		1,093
Transportation expenses	939		1,059
Marketing expenses	292		4,390
Acquisition costs	—		2,617
General and administrative expenses	20,305		20,234
Depreciation, depletion, and amortization	40,392		42,831
Impairment of oil and gas properties	157,910		—
Taxes, other than income taxes	9,240		15,689

(Gains) losses on natural gas purchase derivatives	(5,691)		4,481
Other operating expense (income)	401		(133)
Total expenses and other	303,104		180,841
Other (expenses) income:
Interest expense	(15,172)		(9,140)
Other, net	272		(83)
Total other expenses	(14,900)		(9,223)

Loss before income taxes	(135,353)		(53,984)
Income tax benefit	(38,673)		(13,900)
Net loss	$	(96,680)	$	(40,084)



Net loss per share:
Basic	$	(1.25)	$	(0.53)
Diluted	$	(1.25)	$	(0.53)

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, 2024
	Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Earnings		Total Stockholders’ Equity
	(in thousands)
December 31, 2023	$	88	$	819,157	$	(113,768)	$	52,499	$	757,976
Shares withheld for payment of taxes on equity awards and other	—		(5,257)		—		—		(5,257)
Stock-based compensation	—		616		—		—		616
Issuance of common stock	1		—		—		—		1


Dividends declared on common stock, $0.26/share	—		(24,408)		—		—		(24,408)
Net loss	—		—		—		(40,084)		(40,084)
March 31, 2024	$	89	$	790,108	$	(113,768)	$	12,415	$	688,844


	Three-Month Period Ended March 31, 2025
	Common Stock		Additional Paid-in Capital		Treasury Stock		(Accumulated Deficit) Retained Earnings		Total Stockholders’ Equity
	(in thousands)
December 31, 2024	$	89	$	787,953	$	(113,768)	$	56,362	$	730,636

Shares withheld for payment of taxes on equity awards and other	—		(1,322)		—		—		(1,322)
Stock-based compensation	—		2,571		—		—		2,571
Issuance of common stock	1		—		—		—		1

Dividends declared on common stock, $0.03/share	—		(3,738)		—		—		(3,738)
Net loss	—		—		—		(96,680)		(96,680)
March 31, 2025	$	90	$	785,464	$	(113,768)	$	(40,318)	$	631,468

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,
	2025		2024
	(in thousands)
Cash flows from operating activities:
Net loss	$	(96,680)	$	(40,084)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	40,392		42,831
Amortization of debt issuance costs	1,714		682
Impairment of oil and gas properties	157,910		—
Stock-based compensation expense	2,406		385
Deferred income taxes	(43,470)		(13,491)

Other operating expenses	92		113

Derivative activities:
Total (gains) losses	(11,166)		75,681
Cash settlements paid on derivatives	(1,312)		(9,094)

Changes in assets and liabilities:
Decrease (increase) in accounts receivable	2,921		(3,006)
Decrease (increase) in other assets	417		(1,746)
(Decrease) increase in accounts payable and accrued expenses	(6,582)		(27,341)
(Decrease) increase in other liabilities	(770)		2,343
Net cash provided by operating activities	45,872		27,273

Cash flows from investing activities:
Capital expenditures:
Capital expenditures	(28,389)		(16,936)


Changes in capital expenditures accruals	8,099		(957)

Acquisitions, net of cash received	—		(768)

Proceeds from sale of property and equipment and other	520		—

Net cash used in investing activities	(19,770)		(18,661)

Cash flows from financing activities:
Repayments on 2024 term loan	(11,250)		—
Borrowings under 2024 revolver	10,000		—
Repayments on 2024 revolver	(10,000)		—
Borrowings under former revolving credit facility	—		175,500
Repayments on former revolving credit facility	—		(155,500)




Dividends paid on common stock	(3,738)		(24,408)


Shares withheld for payment of taxes on equity awards and other	(1,322)		(5,257)

Debt issuance cost	(566)		(325)







Net cash used in financing activities	(16,876)		(9,990)
Net increase (decrease) in cash and cash equivalents	9,226		(1,378)
Cash, cash equivalents and restricted cash:
Beginning	30,036		4,835
Ending	$	39,262	$	3,457

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 Delaware limited liability company subsidiaries: (1) Berry Petroleum Company, LLC (“Berry LLC”), which owns Macpherson Energy, LLC and its subsidiaries (collectively, “Macpherson Energy”); (2) CJ Berry Well Services Management, LLC (“C&J Management”) and (3) C&J Well Services, LLC (“C&J,” and, together with C&J Management, “CJWS”). As the context may require, “Berry,” the “Company,” “we,” “our” or similar words in this report refer to Berry Corp., together with its and their subsidiaries, Berry LLC, C&J Management, and C&J.

Nature of Business

We are a value-driven western United States independent upstream energy company with a focus on onshore, low geologic risk, low decline, long-lived oil and gas reserves. We operate in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment services. Our E&P assets are located in California and Utah, are characterized by high oil content and are predominantly located in rural areas with low population. Our California assets are in the San Joaquin Basin (100% oil), and our Utah assets are in the Uinta Basin (65% oil). We provide our well servicing and abandonment services to third party operators in California and our California E&P operations through CJWS.

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. We eliminated all significant intercompany transactions and balances upon consolidation. For oil and gas E&P 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. 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 are not necessarily indicative of 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, 2024.

New Accounting Standards Issued, But Not Yet Adopted

In December 2023, the FASB issued rules to enhance the annual income tax disclosure to address investors’ request for more information regarding tax risks and opportunities present in an entity’s operations related to the effective tax rate reconciliation and income taxes paid. The guidance is effective for fiscal periods beginning after December 15, 2024, with early adoption permitted for annual financial statements. We expect that the adoption of these rules will only impact our disclosures and have no impact on our results of operations, cash flows and financial condition. This guidance will result in additional disclosures for the Company beginning with our 2025 annual reporting.

In November 2024, the FASB issued new disclosure requirements to enhance disclosure of certain costs and expenses. The rules are effective for fiscal years beginning after December 15, 2026 and interim periods beginning after December 15, 2027, with early adoption permitted. We expect that the adoption of these rules will only impact our disclosures and have no impact on our results of operations, cash flows and financial condition. This guidance will result in additional disclosures for the Company beginning with our 2027 annual reporting and interim periods beginning in 2028.

Table of Contents

BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Reclassifications

Certain reclassifications have been made to prior period amounts to conform with current period presentation. These reclassifications had no effect on the previously reported net loss, net loss per share, operating cash flows, or statement of financial position.

Note 2—Debt

The following table summarizes our outstanding debt:


	March 31, 2025		December 31, 2024		Interest Rate	Maturity	Security
	(in thousands)
2024 Revolver	$	—	$	—	8.83% (2025)(1) 9.03% (2024)(1)	December 24, 2027	Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets
2024 Term Loan	438,750		450,000		11.82% (2025) 11.84% (2024)	December 24, 2027	Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets









Less: Debt Issuance/Original Issue Discount Costs	(19,272)		(20,367)
Current Portion of Debt	(45,000)		(45,000)
Long-Term Debt, net	$	374,478	$	384,633

__________

(1) Rates at March 31, 2025 and December 31, 2024 represent borrowing rates using the SOFR one-month option.

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At March 31, 2025 and December 31, 2024, debt issuance costs, net of amortization, for the 2024 Revolver (defined below) reported in “other noncurrent assets” on the balance sheet were approximately $4 million. At March 31, 2025 and December 31, 2024, debt issuance costs, net of amortization, for the 2024 Term Loan (defined below) reported in “Long-Term Debt, net” on the balance sheet were approximately $19 million and $20 million, respectively.

For the three month periods ended March 31, 2025 and 2024, the amortization expense was approximately $2 million and $1 million, respectively. The amortization of debt issuance costs is presented in “interest expense” on the condensed consolidated statements of operations.

Fair Value

Our debt is recorded at the carrying amount on the balance sheets. The carrying amount of the 2024 Revolver approximates fair value because the interest rates are variable and reflect market rates. The fair value of the 2024 Term Loan was approximately $439 million and $450 million at March 31, 2025 and December 31, 2024, respectively. The 2024 Revolver and 2024 Term Loan are Level 2 in the fair value hierarchy.

2024 Term Loan

24, 2024 (the “Term Loan Amendment”) among the Company, as borrower, certain of the Company’s direct and indirect subsidiaries, as guarantors, the lenders party thereto and Breakwall Credit Management LLC, as administrative agent, which amended the Original Term Loan Agreement (the Original Term Loan Agreement, as amended by the Term Loan Amendment, the “2024 Term Loan”).

The 2024 Term Loan provides for (i) an initial term loan facility in the aggregate principal amount of $450 million (the “Initial Term Loan”) and (ii) a delayed draw term loan facility with commitments in an aggregate principal amount of up to $32 million (the “Delayed Draw Term Loan”) which is available for borrowing until December 24, 2026, subject to satisfaction of certain customary conditions precedent, as further set forth in the 2024 Term Loan. We borrowed $450 million under the Initial Term Loan on December 24, 2024 to fund the redemption or repayment, as applicable, of $403 million of outstanding debt; to fund a portion of the costs and expenses associated with the execution of the 2024 Revolver, 2024 Term Loan, and the termination of our former revolving debt facilities; and for other general corporate purposes. The commitments under the Delayed Draw Term Loan will be reduced, on a dollar-for-dollar basis, by any increase in the commitments under the 2024 Revolver. We had not borrowed any amounts under the Delayed Draw Term Loan as of March 31, 2025.

The 2024 Term Loan has an initial maturity date of December 24, 2027, unless terminated earlier in accordance with the terms of the 2024 Term Loan, which may be extended by up to two one-year increments subject to payment of extension fees and satisfaction of certain other customary conditions. The loans under the 2024 Term Loan are available to us for general corporate purposes, including working capital.

Loans under the 2024 Term Loan bear interest at a rate per annum equal to, at our option, either (a) a customary base rate (subject to a floor of 4.00%) plus an applicable margin of 6.50% or (b) a term SOFR reference rate (subject to a floor of 3.00%) plus an applicable margin of 7.50%. Interest on base rate borrowings is payable quarterly in arrears and interest on term SOFR borrowings accrues in respect of interest periods of one, three or six months, at the election of the borrower, 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 the end of such interest period). If an Event of Default (as defined in the 2024 Term Loan) exists and is continuing, upon the election of the Majority Lenders (as defined in the 2024 Term Loan) under the 2024 Term Loan, or automatically without such election, in the case of a bankruptcy, insolvency, or payment Event of Default, all amounts outstanding under the 2024 Term Loan will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto (it being understood that such Majority Lenders may elect for the application of default interest to commence on any date that is on or after the occurrence of such Event of Default while such Event of Default is continuing). Quarterly debt service payments of an amount equal to the sum of 2.50% of the sum of (a) the face value of the Initial Term Loan and (b) the aggregate amount of delayed draws made from the Delayed Draw Term Loan, which quarterly debt service payments had begun in March 2025. We have the right to repay any amounts borrowed prior to the maturity date of the 2024 Term Loan (i) without any premium for any optional prepayment made on or prior to December 24, 2026 and (ii) thereafter, subject to a concurrent premium payment of 2.75% of the principal amount being repaid.

The 2024 Term Loan contains certain financial covenants, including (a) a minimum liquidity of $25 million as of the last day of any calendar month, (b) a total net leverage ratio that may not exceed 2.5 to 1.0 as of the last day of any fiscal quarter and (c) an asset coverage ratio that may not be less than 1.3 to 1.0 as of the last day of any fiscal quarter, in each case, as more fully described in the 2024 Term Loan. We were in compliance with all applicable financial covenants under the 2024 Term Loan as of March 31, 2025.

The 2024 Term Loan also contains other restrictive covenants that limit the ability of the Company and its subsidiaries to, among other things, pay dividends or prepay other debt, make investments and loans, enter into mergers and acquisitions, sell assets, incur additional indebtedness, incur additional liens, enter into certain hedging transactions, engage in transactions with affiliates and make certain capital expenditures. The 2024 Term Loan permits us to pay dividends and repurchase equity interests up to an annual cap, subject to, among other things, pro forma compliance with our financial covenants.

In addition, the 2024 Term Loan is subject to customary events of default, including a change in control (which change of control event of default is subject to a carve-out for no decline in the Company’s corporate credit rating). If an event of default occurs and is continuing, subject to customary cure rights, the administrative agent or the majority lenders may accelerate any amounts outstanding, terminate lender commitments and/or exercise other remedies against any collateral.

In addition, the 2024 Term Loan is guaranteed by the Company and all of its wholly owned material subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and of its wholly owned material subsidiaries, subject to permitted liens. The 2024 Term Loan is also required to be guaranteed by, and secured with substantially all assets of, certain future wholly-owned material subsidiaries of the Company that we may form or acquire. The lenders under the 2024 Term Loan hold a mortgage lien on at least 90% of the present value of our proven oil and gas reserves.

As of March 31, 2025, we had approximately $439 million of borrowings outstanding under the 2024 Term Loan and $32 million of available commitments, but no borrowings outstanding, under the Delayed Draw Term Loan.

2024 Revolver

On December 24, 2024, the Company entered into a Senior Secured Revolving Credit Agreement (the “2024 Revolver”) among Berry Corp., certain subsidiaries of Berry Corp., as guarantors, the lenders from time to time party thereto and Texas Capital Bank, as administrative agent. The 2024 Revolver provides for a revolving credit facility of up to the least of (i) the maximum commitments of $500 million, (ii) the then-effective borrowing base, which was equal to $95 million as of March 31, 2025, and (iii) the aggregate elected commitment amount, which was equal to $63 million as of March 31, 2025. The aggregate commitments under the 2024 Revolver include a $30 million sublimit for the issuance of letters of credit (with borrowing availability being reduced by the face amount of any letters of credit issued under the subfacility). The borrowing base will be redetermined by the lenders at least semi-annually on or about May 1 and November 1 of each year, beginning May 2025. We may increase elected commitments under the 2024 Revolver to the amount of our borrowing base with applicable lender approval. Any such increase above the elected commitments in effect as of December 26, 2024 will result in a dollar-for-dollar reduction in commitments under the 2024 Term Loan.

The 2024 Revolver matures on December 24, 2027, unless terminated earlier in accordance with the terms of the 2024 Revolver. The loans under the 2024 Revolver are available to us for general corporate purposes, including working capital.

The outstanding borrowings under the 2024 Revolver bear interest at a rate per annum equal to, at our option, either (a) a customary base rate (subject to a floor of 1.00%) plus an applicable margin of 3.50% or (b) a term SOFR reference rate plus 0.10% (subject to a floor of 2.00%) plus an applicable margin of 4.50%. Interest on base rate borrowings is payable quarterly in arrears and interest on term SOFR borrowings accrues in respect of interest periods of one, three or six months, at the election of the borrower, 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 the end of such interest period). If an Event of Default (as defined in the 2024 Revolver) exists and is continuing, upon the election of the Majority Lenders (as defined in the 2024 Revolver) under the 2024 Revolver, or automatically without such election, in the case of a bankruptcy, insolvency, or payment default, all amounts outstanding under the 2024 Revolver will bear interest at 4.50% per annum above the rate and margin otherwise applicable thereto (it being understood that such Majority Lenders may elect for the application of default interest to commence on any date that is on or after the occurrence of such Event of Default while such Event of Default is continuing).

The 2024 Revolver contains certain financial covenants, including (a) minimum liquidity of $25 million as of the last day of any calendar month and (b) commencing with the fiscal quarter ending March 31, 2025, (i) a total net leverage ratio that may not exceed 2.5 to 1.0 as of the last day of any fiscal quarter and (ii) an asset coverage ratio that may not be less than 1.3 to 1.0 as of the last day of any fiscal quarter, in each case, as more fully described in the 2024 Revolver. We were in compliance with all applicable financial covenants under the 2024 Revolver as of March 31, 2025.

The amount we are able to borrow with respect to the borrowing base under the 2024 Revolver is subject to compliance with the financial covenants and other provisions of the 2024 Revolver, including that the Consolidated Cash Balance (as defined in the 2024 Revolver) does not exceed $35 million at the time of and after giving effect to such borrowing and the use of proceeds thereof. In addition, the 2024 Revolver provides that if there are any outstanding borrowings thereunder and the Consolidated Cash Balance exceeds $35 million at the end of the last business day of any calendar month, such excess amounts shall be used to prepay borrowings under the 2024 Revolver.

The 2024 Revolver contains other restrictive covenants that limit the ability of the Company and its subsidiaries to, among other things, pay dividends or prepay other debt, make investments and loans, enter into mergers and acquisitions, sell assets, incur additional indebtedness, incur additional liens, enter into certain hedging transactions, engage in transactions with affiliates and make certain capital expenditures. The 2024 Revolver permits us to pay dividends and repurchase equity interests up to an annual cap, subject to, among other things, pro forma compliance with our financial covenants.

In addition, the 2024 Revolver is subject to customary events of default, including a change in control (which change of control event of default is subject to a carve-out for no decline in the Company’s corporate credit rating). If an event of default occurs and is continuing, subject to customary cure rights, the administrative agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments and exercise remedies against any collateral.

The 2024 Revolver is guaranteed by the Company and all of its wholly owned material subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and of its wholly owned material subsidiaries, subject to permitted liens. The 2024 Revolver is also required to be guaranteed by, and secured with substantially all assets of, certain future wholly-owned material subsidiaries of the Company that we may form or acquire. The lenders under the 2024 Revolver hold a mortgage lien on at least 90% of the present value of our proven oil and gas reserves.

As of March 31, 2025, we had no borrowings outstanding, $14 million of letters of credit outstanding, and approximately $49 million of available borrowing capacity under the 2024 Revolver.

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 sales and gas purchase hedging requirements of the 2024 Term Loan and the 2024 Revolver, which specifies the volume and types of our hedges, we target covering a significant portion of our anticipated costs, with the oil sales hedges generally for a period of up to three years out and gas purchase hedges for a period of at least 18 months out. At times, we will hedge beyond these periods when strike prices appear to satisfy anticipated costs in those years. We have also entered into gas transportation contracts to help reduce the price fluctuation exposure of our gas purchases used in our steam operations; 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.

The 2024 Revolver and 2024 Term Loan each requires us to maintain commodity hedges which are Existing Swaps (as defined in the 2024 Term Loan), or are otherwise in the form of fixed price swaps (at market prices) or costless collars, on minimum notional volumes of (i) at least 75% of our reasonably projected production of crude

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(Unaudited)

oil from our PDP reserves, for each month during the twenty-four calendar month period immediately following December 24, 2024, and (ii) at least 50% of our reasonably projected production of crude oil from our PDP reserves, for each month during the twenty-fifth through thirty-sixth calendar month period following December 24, 2024. The 2024 Revolver and 2024 Term Loan each also requires us to maintain commodity hedges in the form of fixed price swaps (at market prices), costless collars, certain other collars or put options meeting conditions described in the 2024 Revolver and 2024 Term Loan, or, with respect to the Existing Swaps, in the form of the Existing Swaps as of the effective date of the 2024 Term Loan, on minimum notional volumes, of (i) at least 75% of our reasonably projected production of crude oil from our PDP reserves, for each month during a rolling period of twenty-four calendar months commencing with the end of the then next upcoming month from the relevant minimum hedging test date, and (ii) at least 50% of our reasonably projected production of crude oil from our PDP reserves, for each month during a rolling period of twelve months commencing with the end of the twenty-fifth month from the relevant minimum hedging test date. In addition, the 2024 Revolver and 2024 Term Loan each requires us to maintain hedges in respect of purchases of natural gas for fuel in respect of 40,000 mmbtu of natural gas for fuel for each day (a) during the 18 calendar month period immediately following the December 24, 2024 and (b) during the 18 months calendar month period commencing with the end of the next upcoming month after the applicable minimum hedging test date.

In addition to the minimum hedging requirements and other restrictions in respect of hedging described therein, each of the 2024 Revolver and 2024 Term Loan contains restrictions on our commodity hedging which prevent us from entering into hedging agreements (i) with a tenor exceeding 60 months or (ii) for notional volumes which (when netted and aggregated with other hedges then in effect) exceed, as of the date such hedging agreement is executed, 90% of our reasonably projected production of crude oil, natural gas and natural gas liquids, calculated separately, from our PDP reserves, for each month following the date such hedging agreement is entered into, provided that each of the 2024 Revolver and 2024 Term Loan provides that the Company may enter into additional commodity hedges pertaining to oil and gas properties to be acquired, subject to the requirements set forth in the 2024 Revolver and 2024 Term Loan.

Oil Sales Hedges

For fixed-price sales swaps, we are the seller, so we make settlement payments for prices above, and conversely collect settlement receipts for prices below, the indicated weighted-average price per bbl.

A Brent collar is used for the sale of crude production and is the combination of selling a call option and buying a put option. We would make settlement payments for prices above the weighted-average price of the call option and we would receive settlement payments for prices below the weighted-average price of the put option. No payment would be made or received for prices between the call and put’s weighted-average price per barrel, other than any applicable deferred premium.

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

Gas Purchase Hedges

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

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, 2025, we have net premium assets of approximately $4 million, which is reflected in the mark-to-market valuation and will be amortized over the life of the positions.

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(Unaudited)

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

As of March 31, 2025, we had the following crude oil production and gas purchases hedges.


	Q2 2025		Q3 2025		Q4 2025		FY 2026		FY 2027		FY 2028
Brent - Crude Oil production
Swaps
Hedged volume (bbls)	1,637,198		1,613,083		1,518,000		3,718,518		3,347,000		1,505,500
Hedged volume (mbbls) per day	18.0		17.5		16.5		10.2		9.2		4.1
Weighted-average price ($/bbl)	$	74.35	$	74.48	$	75.28	$	70.47	$	69.72	$	68.05

Collars
Hedged volume (bbls)	—		—		—		1,161,500		318,500		—
Hedged volume (mbbls) per day	—		—		—		3.2		0.9		—
Weighted-average ceiling ($/bbl)	$	—	$	—	$	—	$	85.76	$	80.03	$	—


Weighted-average floor ($/bbl)	$	—	$	—	$	—	$	60.00	$	65.00	$	—

Purchased Puts (net)
Hedged volume (bbls)	—		—		—		547,500		—		—
Hedged volume (mbbls) per day	—		—		—		1.5		—		—
Weighted-average price ($/bbl)	$	—	$	—	$	—	$	65.00	$	—	$	—















NWPL - Natural Gas purchases(1)
Swaps
Hedged volume (mmbtu)	3,640,000		3,680,000		3,680,000		12,160,000		—		—
Hedged volume (mmbtu) per day	40.0		40.0		40.0		33.3		—		—
Weighted-average price ($/mmbtu)	$	4.29	$	4.29	$	4.15	$	3.93	$	—	$	—

__________

(1) The term “NWPL” is defined as Northwest Rocky Mountain Pipeline and represents the index used for these gas purchase hedges.

In addition to the table above, in April 2025, we converted most of our collars and all purchased puts into swaps. We added the following sold oil swaps (Brent) for each of the following years: approximately 4.2 mbbl/d at $67.97 for 2026 and approximately 0.4 mbbl/d at $69.75 for 2027. We terminated collars of 2.7 mbbl/d for 2026 (calls at $86.57/bbl, puts at $60.00/bbl) and 0.4 mbbl/d for 2027 (calls at $80.07/bbl, puts at $65.00/bbl). We also terminated all purchased puts for 2026.

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(Unaudited)

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, 2025 and December 31, 2024:


	March 31, 2025
	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)
Assets:
Commodity Contracts	Current assets	$	23,818	$	(12,055)	$	11,763
Commodity Contracts	Non-current assets	21,289		(11,072)		10,217
Liabilities:
Commodity Contracts	Current liabilities	(13,946)		12,964		(982)
Commodity Contracts	Non-current liabilities	(10,163)		10,163		—
Total derivatives		$	20,998	$	—	$	20,998


	December 31, 2024
	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)
Assets:
Commodity Contracts	Current assets	$	14,691	$	(10,165)	$	4,526
Commodity Contracts	Non-current assets	25,435		(13,738)		11,697
Liabilities:
Commodity Contracts	Current liabilities	(17,868)		10,165		(7,703)
Commodity Contracts	Non-current liabilities	(13,738)		13,738		—
Total derivatives		$	8,520	$	—	$	8,520

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 2024 Term Loan and 2024 Revolver prevent us from entering into hedging arrangements that are secured, except with our lenders and their affiliates, or with a non-lender counterparty that does not have an A or A2 credit rating or better from Standard & 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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(Unaudited)

Gains (Losses) on Derivatives


	Three Months Ended March 31,
	2025		2024
	(in thousands)
Realized (losses) on commodity derivatives:
Realized gains (losses) on oil sales derivatives	$	164	$	(4,682)
Realized (losses) on natural gas purchase derivatives	(1,476)		(4,412)
Total realized (losses) on derivatives	$	(1,312)	$	(9,094)

Unrealized gains (losses) on commodity derivatives:
Unrealized gains (losses) on oil sales derivatives	$	5,311	$	(66,518)
Unrealized gains (losses) on natural gas purchase derivatives	7,167		(69)
Total unrealized gains (losses) on derivatives	$	12,478	$	(66,587)
Total gains (losses) on derivatives	$	11,166	$	(75,681)

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(Unaudited)

Note 4—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, false claims, 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, 2025 and December 31, 2024. 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, 2025, we are not aware of material indemnity claims pending or threatened against us.

Securities Litigation Matters

There have been no material updates to the securities litigation matters described in our Annual Report. See “Note 5, Commitments and Contingencies” in the notes to the consolidated financial statements in Part II—Item 8. “Financial Statements and Supplementary Data” in our Annual Report for details.

Commitments

We have entered into contracts to purchase GHG compliance instruments totaling $22 million, of which $11 million was delivered and paid in April 2025. The remaining amount of $11 million of these instruments will be delivered and paid in the third and fourth quarters of 2025.

Note 5—Stockholders’Equity

Cash Dividends

In the first quarter of 2025, our Board of Directors declared a cash dividend of $0.03 per share, which we paid in April 2025. On May 7, 2025, the Board of Directors declared a cash dividend of $0.03 per share, which is expected to be paid in May 2025.

The Company anticipates that it will continue to pay quarterly cash dividends in the future. However, the payment and amount of future dividends remain within the discretion of the Board of Directors and will depend upon the Company’s future earnings, financial condition, capital requirements, and other factors.

Stock Repurchase Program

The manner, timing and amount of any purchases of the Company’s common stock will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors. Purchases may be commenced or suspended at any time without notice and the share repurchase program 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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(Unaudited)

subject to market conditions and other factors, up to the aggregate amount authorized by the Board of Directors. The Board of Directors’ authorization has no expiration date.

The Company did not repurchase any shares during the three months ended March 31, 2025. As of March 31, 2025, the Company had repurchased a total of 11.9 million shares, cumulatively, under the stock repurchase program for approximately $114 million in aggregate.

ATM Program

On March 13, 2025, the Company entered into an Open Market Sale Agreement (the “Sales Agreement”) with Jefferies LLC and Johnson Rice & Company L.L.C. (the “Sales Agents”). Pursuant to the Sales Agreement, we may offer and sell common stock having an aggregate offering price of up to $50 million from time to time to or through the Sales Agents, subject to our compliance with applicable laws and applicable requirements of the Sales Agreement (the “ATM Program”). The timing of any sales and the number of shares sold, if any, will depend on a variety of factors to be determined and considered by us, and we are not obligated to sell any shares under the Sales Agreement.

Net proceeds from the ATM Program can be used for general corporate purposes, which may include, among other things, paying or refinancing indebtedness, and funding acquisitions, capital expenditures and working capital.

During the three months ended March 31, 2025, the Company did not sell any shares of common stock under the ATM Program.

Stock-Based Compensation

In March 2025, pursuant to the Company’s 2022 Omnibus Incentive Plan, the Company granted (i) approximately 1,386,000 restricted stock units (“RSUs”), which are scheduled to vest ratably on the first, second, and third anniversary of the grant date or, in the case of RSUs issued to the Company’s non-employee directors, in full on the first anniversary of the grant date, and (ii) a target number of approximately 414,000 performance-based restricted stock units (“PSUs”), which are scheduled to vest in full on the third anniversary of the grant date, and earned based on performance during the three-year performance period. The fair value of these RSU and PSU awards was approximately $7 million.

The RSUs awarded in March 2025 are solely time-based awards. The PSUs awarded in March 2025 are subject to both time and performance-based conditions, with performance based on on the Company’s absolute total stockholder return (“TSR”), defined as the capital gains per share of stock plus cumulative dividends, over a three year performance period. Depending on the results achieved during the three-year performance period, the actual number of shares of common stock that a grant recipient earns at the end of the performance period may range from 0% to 200% of the target number of PSUs granted.

The fair value of the RSUs was determined using the grant date stock price. The grant date fair value of the PSUs was determined using a Monte Carlo simulation to estimate the TSR ranking of the Company for the value of the absolute TSR award. The historical volatility was determined at the date of grant for the Company. 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 three-year performance measurement period.

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(Unaudited)

Note 6—Supplemental Disclosures to the Financial Statements

Supplemental Information on Balance Sheet

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


	March 31, 2025		December 31, 2024
	(in thousands)
Prepaid expenses	$	13,308	$	12,183
Materials and supplies	11,375		12,109

Deposits	6,399		8,701

Oil inventories	4,063		4,232
Other	226		226
Total other current assets	$	35,371	$	37,451

Noncurrent assets

Other noncurrent assets at March 31, 2025 was approximately $11 million, which included $5 million of operating lease right-of-use assets, net of amortization, $4 million of deferred financing costs, net of amortization and $2 million of collateral deposits. At December 31, 2024, other non-current assets was approximately $9 million, which included $5 million of operating lease right-of-use assets, net of amortization and $4 million of deferred financing costs, net of amortization.

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


	March 31, 2025		December 31, 2024
	(in thousands)
Accounts payable - trade	$	24,230	$	18,990

Accrued expenses	54,511		53,925
Royalties payable	17,369		26,256
Greenhouse gas liability - current portion	4,114		8,068
Taxes other than income tax liability	10,660		6,374
Accrued interest	1,536		1,160

Asset retirement obligations - current portion	17,000		17,000
Operating lease liability	1,928		2,036

Total accounts payable and accrued expenses	$	131,348	$	133,809

Noncurrent liabilities

The decrease of approximately $1 million in the long-term portion of the asset retirement obligations from $185 million at December 31, 2024 to $184 million at March 31, 2025 was due to $3 million of accretion expense, offset by $4 million of liabilities settled during the period.

Other noncurrent liabilities at March 31, 2025 was approximately $31 million, which included approximately $28 million of greenhouse gas liability, and $3 million of operating lease noncurrent liability. At December 31, 2024, other noncurrent liabilities was approximately $28 million and included approximately $24 million of greenhouse gas liability and $4 million of non-current operating lease liability.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Supplemental Cash Flow Information

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




	Three Months Ended March 31,
	2025		2024
	(in thousands)
Supplemental Disclosures of Significant Non-Cash Operating Activities:
Greenhouse gas liability - reclassification from current to long-term liability	$	3,954	$	—
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Deferred consideration payable for acquisition	$	—	$	19,500
Material inventory transfers to oil and natural gas properties	$	405	$	781
Supplemental Disclosures of Cash Payments:
Interest, net of amounts capitalized	$	13,459	$	15,256
Income taxes payments	$	66	$	—

Note 7—Acquisitions and Divestitures

In April 2024, we purchased a 21% working interest in four, two-to-three mile lateral wellbores that have been drilled and completed and were placed into production in the second quarter of 2024. These are adjacent to our existing operations in Utah, and the results from these wells are used to evaluate opportunities on our own acreage. The total purchase price was approximately $10 million, subject to customary purchase price adjustments, which was reported as capital expenditures.

Note 8—Earnings Per Share

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

The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the three months ended March 31, 2025 and 2024, no RSU or PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the “if converted” method.

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(Unaudited)




	Three Months Ended March 31,
	2025		2024
	(in thousands except per share amounts)
Basic EPS calculation
Net loss	$	(96,680)	$	(40,084)




Weighted-average shares of common stock outstanding	77,196		76,254
Basic loss per share	$	(1.25)	$	(0.53)
Diluted EPS calculation
Net loss	$	(96,680)	$	(40,084)




Weighted-average shares of common stock outstanding	77,196		76,254
Dilutive effect of potentially dilutive securities(1)	—		—
Weighted-average common shares outstanding - diluted	77,196		76,254
Diluted loss per share	$	(1.25)	$	(0.53)

__________

(1) We excluded approximately 0.2 million and 1.1 million of combined RSUs and PSUs from the dilutive weighted-average common shares outstanding for each of the three months ended March 31, 2025 and 2024, respectively, because their effect was anti-dilutive.

Note 9—Revenue Recognition

We derive revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with additional revenue generated from sales of electricity. Revenue from CJWS is generated from well servicing and abandonment services business.

The following table provides disaggregated revenue for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025		2024
	(in thousands)
Oil sales	$	143,990	$	162,752
Natural gas sales	2,820		2,719
Natural gas liquids sales	1,052		847
Service revenue(1)	23,664		31,683
Electricity sales	4,967		4,243

Marketing and other revenues	683		5,036
Revenues from contracts with customers	177,176		207,280
Gains (losses) gains on oil and gas sales derivatives	5,475		(71,200)
Total revenues and other	$	182,651	$	136,080

__________

(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $30 million and $35 million and the intercompany elimination was $6 million and $4 million for the three months ended March 31, 2025 and 2024, respectively.

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(Unaudited)

Note 10—Oil and Natural Gas Properties

We evaluate the impairment of our proved and unproved oil and natural gas properties whenever events or changes in circumstance indicate that a property’s carrying value may not be recoverable. If the carrying amount of the proved properties exceeds the estimated undiscounted future cash flows, we record an impairment charge to reduce the carrying values of proved properties to their estimated fair value.

For our unproved oil and gas properties, if exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions, regulatory constraints or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results.

At March 31, 2025, we identified an impairment indicator with respect to certain of our proved oil and gas properties as a result of changes in estimates of future reserve recoverability and the volatility in oil and gas prices. U.S. domestic policy shifts under the current administration have contributed to commodity price uncertainty. Recent executive actions aimed at expanding domestic drilling, rolling back environmental regulations, and renegotiating trade agreements have introduced mixed signals to the market. While these measures are intended to boost U.S. energy independence, they have also raised concerns about oversupply, regulatory instability, and global response. Futures forward curves for crude oil reflect this ongoing uncertainty, suggesting that price volatility may persist and affect our operations and financial outlook. Further, natural gas is a key cost of our oil production in California, and gas futures prices increased in the first quarter of 2025, impacting the expected margins. Additionally, lower than expected production data from the first quarter of 2025 resulted in negative revisions to our reserve estimates in one of our non-thermal diatomite California fields.

As a result of operating evaluations, market volatility and price declines we recorded a non-cash pre-tax asset impairment charge of $158 million ($113 million after-tax) on one of our non-thermal diatomite proved properties in California for the three months ended March 31, 2025. We believe our current plans and exploration and development efforts will allow us to realize the carrying value of our unproved property balance at March 31, 2025.

The fair value measurements used in this analysis were determined using inputs classified as Level 3 in the fair value hierarchy.

Note 11—Segment Information

We operate in two business segments: (i) E&P and (ii) well servicing and abandonment services. The E&P segment is engaged in the exploration and production of onshore, low geologic risk, long-lived oil and gas reserves located in California and Utah. The well servicing and abandonment services segment is operated by CJWS and provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics.

Net income (loss) before income taxes 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. This measure allows our management to effectively evaluate our operating performance by segment and compare the results between periods. The CODM is our Chief Executive Officer.

The well servicing and abandonment services segment occasionally provides services to our E&P segment, as such, we recorded an intercompany elimination in revenue and expense during consolidation for the three months ended March 31, 2025 and 2024, respectively.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)


	Three Months Ended March 31, 2025
	E&P		Well Servicing and Abandonment Services		Total Reportable Segments		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	147,862	$	—	$	147,862	$	—	$	147,862
Service revenue	$	—	$	29,747	$	29,747	$	(6,083)	$	23,664
Gains on oil and gas derivatives	$	5,475	$	—	$	5,475	$	—	$	5,475
Other revenue (1)	$	5,650	$	—	$	5,650	$	—	$	5,650
Total revenues and other	$	158,987	$	29,747	$	188,734	$	(6,083)	$	182,651

__________

(1) Other revenue generally consists of revenues related to electricity sales and marketing activities.


	Three Months Ended March 31, 2025
	E&P		Well Servicing and Abandonment Services		Total Reportable Segments		Corporate/Eliminations		Consolidated Company
	(in thousands)
Segment Operating Revenues	$	158,987	$	29,747	$	188,734	$	(6,083)	$	182,651
Less:
Lease operating expenses	57,282		—		57,282		—		57,282
(Gains) on natural gas purchase derivatives	(5,691)		—		(5,691)		—		(5,691)
Cost of services	—		26,908		26,908		(6,083)		20,825
Other operating expenses (1)	2,440		—		2,440		—		2,440
Taxes, other than income taxes	9,240		—		9,240		—		9,240
Other expenses (2)	197,133		4,550		201,683		17,325		219,008
Interest expense and other, net	—		—		—		14,900		14,900
Segment loss	(101,417)		(1,711)		(103,128)

Loss before income taxes									(135,353)

Capital expenditures	$	27,618	$	56	$	27,674	$	715	$	28,389
Total assets	$	1,385,674	$	52,392	$	1,438,066	$	(33,728)	$	1,404,338

__________

(1) Amounts for our E&P segment include electricity, transportation, and marketing costs.

(2) Amounts primarily include general and administrative expenses, depreciation, depletion, and amortization costs, E&P impairment, and other operating income (expenses).

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)


	Three Months Ended March 31, 2024
	E&P		Well Servicing and Abandonment Services		Total Reportable Segments		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	166,318	$	—	$	166,318	$	—	$	166,318
Service revenue	—		35,468		35,468		(3,785)		31,683
(Losses) on oil and gas derivatives	(71,200)		—		(71,200)		—		(71,200)
Other revenue (1)	9,279		—		9,279		—		9,279
Total revenues and other	$	104,397	$	35,468	$	139,865	$	(3,785)	$	136,080

__________

(1) Other revenue generally consists of revenues related to electricity sales and marketing activities.


	Three Months Ended March 31, 2024
	E&P		Well Servicing and Abandonment Services		Total Reportable Segments		Corporate/Eliminations		Consolidated Company
	(in thousands)
Segment Operating Revenues	$	104,397	$	35,468	$	139,865	$	(3,785)	$	136,080
Less:
Lease operating expenses	61,276		—		61,276		—		61,276
Losses on natural gas purchase derivatives	4,481		—		4,481		—		4,481
Cost of services	—		31,089		31,089		(3,785)		27,304
Other operating expenses (1)	6,542		—		6,542		—		6,542
Taxes, other than income taxes	15,689		—		15,689		—		15,689
Other expenses (2)	41,245		5,620		46,865		18,684		65,549
Interest expense and other, net	—		—		—		9,223		9,223
Segment loss	(24,836)		(1,241)		(26,077)

Loss before income taxes									$	(53,984)


Capital expenditures	$	15,417	$	1,332	$	16,749	$	187	$	16,936
Total assets	$	1,625,178	$	65,948	$	1,691,126	$	(115,610)	$	1,575,516

__________

(1) Amounts for our E&P segment include electricity, transportation, and marketing costs.

(2) Amounts primarily include general and administrative expenses, depreciation, depletion, and amortization costs, acquisition costs, and other operating income (expenses).

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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 condensed consolidated financial statements and the related notes thereto presented in this Quarterly Report on Form 10-Q (this “Quarterly Report”), 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, 2024 (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, Berry Corp., together with its subsidiaries, Berry LLC, C&J Management, and C&J.

Our Company

With respect to our E&P operations in Kern County, California, we focus on conventional, shallow oil reservoirs. The drilling and completion of wells in the San Joaquin Basin are relatively low-cost in contrast to unconventional resource plays. The California oil market is primarily tied to Brent-influenced pricing which has typically realized premium pricing relative to West Texas Intermediate (“WTI”). All of our California assets are located in 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 data generated over the basin’s long history of production, its reservoir characteristics and low geological risk opportunities are generally well understood.

Our 2025 capital program in California is comprised of drilling and completing sidetrack wells, the majority of which is expected to target our thermal diatomite assets. During the first quarter of 2025, we drilled 12 wells in California, 10 of which were thermal diatomite sidetracks. We expect to have incurred the substantial majority of our California capital expenditures by the end of the third quarter. Given the planned downtime incorporated into our schedule to complete these wells, we anticipate an increase in production in the second half of the year compared to the first half as these wells are brought online.

With respect to our E&P operations in Utah, we have historically focused on vertical well development from five reservoirs that produce oil and natural gas at depths ranging from 4,000 feet to 8,000 feet. As of March 31, 2025, we held approximately 100,000 net acres in the Uinta Basin, and with a high working interest and the majority of acreage held by production, we have high operational control of our existing acreage, which provides significant upside for additional development and recompletions.

Over the last year, the Uinta Basin has experienced an increase in activity by new and existing operators, driven by successful results from horizontal drilling across the basin, which we believe indicates significant new development potential for our existing acreage. In April 2024, we acquired a 21% working interest in four, two-to-three mile lateral wells in the Uteland Butte reservoir, adjacent to our existing operations, which were put on production in the second quarter of 2024. The initial production rates from those four wells exceeded our initial expectations. In November 2024, we executed an agreement to exchange, on an equal value basis, certain of our oil, gas, and mineral leasehold interests in Duchesne County, Utah, for that of another operator’s, also located in Duchesne County, Utah. We received an approximately 17% working interest in three, three-mile Drilling Spacing Units (DSUs) in exchange for an approximately 75% working interest in one, two-mile DSU. Like the first four horizontal wells that we farmed-in, these wells are adjacent to our existing operations, and the results from all of these farmed-in horizontal wells will be useful to evaluating opportunities on our own acreage. We believe

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horizontal well development of our own acreage could yield substantial returns, with low break-even economics and a potentially significant runway of future development opportunities.

Our 2025 capital program includes the drilling and completion of an operated, four-well horizontal pad in the Uteland Butte reservoir of the Uinta Basin with depths ranging from 6,000 to 6,500 feet. In the first quarter of 2025, we drilled the first two horizontal wells and commenced drilling the third well. In the second quarter, we finished drilling the third and fourth wells and we currently expect all four wells to be brought online in the third quarter of 2025. This activity marks our first operated horizontal pad on our Uinta Basin acreage, and the results will inform our plans for further horizontal development across our acreage. Similar to our 2025 capital program in California, we expect that a substantial majority of our capital expenditures for our Utah program will be incurred by the end of the third quarter.

C&J Well Services is one of the largest upstream well servicing and abandonment services businesses in California, providing a suite of services to third-party oil and natural gas production companies and to our E&P operations, including well servicing and workover, water logistics, and plugging and abandonment (P&A) services on wells at the end of their productive life. We believe CJWS has upside opportunity based on the significant inventory of idle wells within California, coupled with existing and new regulations that will increase the annual idle well management obligations of operators. With extensive experience operating in California and a best-in-class safety record, CJWS provides a competitive advantage to Berry by providing access and control over an important part of our supply chain. Additionally, CJWS supports our commitment to be a responsible operator and reduce fugitive GHG emissions —including methane and carbon dioxide—through the plugging and abandonment of idle wells.

How We Plan and Evaluate Operations

We use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA; (b) Free Cash Flow; (c) production from our E&P business; (d) E&P operating costs; (e) HSE results; (f) general and administrative expenses; and (g) the performance of our well servicing and abandonment services operations based on activity levels, pricing and relative performance for each service provided.

Adjusted EBITDA

Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor our operating performance. We also use Adjusted EBITDA in planning our capital expenditure allocation to maintain production levels year-over-year and determining our strategic hedging needs aside from the hedging requirements of the 2024 Term Loan and the 2024 Revolver. 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 for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items. See “—Non-GAAP Financial Measures” for a reconciliation of net income (loss) and net cash provided (used) by operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP, to the non-GAAP financial measure of Adjusted EBITDA. 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.

Free Cash Flow

Free Cash Flow is a non-GAAP measure defined as cash flow from operations less capital expenditures. We use Free Cash Flow as the primary metric to measure our ability to pay dividends, pay down debt, repurchase stock, and make strategic growth and bolt-on acquisitions. 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 Free Cash Flow is available for dividends, debt pay down, share repurchases, bolt-on acquisitions or other growth opportunities, or other discretionary expenditures, since we have non-discretionary expenditures that are not deducted from this measure. Free Cash Flow is a non-GAAP financial measure. See “Non-GAAP Financial Measures” for a reconciliation of cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP, to the non-GAAP financial measure of Free Cash Flow.

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Production

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

E&P Operating Costs

Overall, management assesses the efficiency of our E&P operations by considering core E&P operating costs. A substantial majority of such costs are our lease operating expenses (“LOE”) which includes fuel gas, purchased power, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. A core component of our E&P operations in California is steam, which we use to lift heavy oil to the surface. The most significant cost component of generating steam is the fuel gas purchased to operate traditional steam generators and our cogeneration facilities. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural gas purchase hedges. Consequently, the efficiency of our E&P 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.

Health, Safety & Environmental

Like other companies in the oil and gas industry, the operations of both our E&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 “—Regulatory Matters” in this Quarterly Report as well as Part I, Items 1 and 2. “Business and Properties—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 HSE matters, may have upon our business, operations, capital expenditures, earnings and competitive position.

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

General and Administrative Expenses

We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities. 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.

Well Servicing and Abandonment Services Operational Performance

We monitor our well servicing and abandonment services’ operational performance by analyzing the pre-tax income, revenue and cost by customer, and Adjusted EBITDA generated by 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, including differentials, which have and may continue to fluctuate significantly as a result of numerous market-related variables, including global geopolitical and economic conditions, and local and regional market factors and dislocations. Average oil prices were relatively flat for the first quarter of 2025 compared to fourth quarter of 2024; however, they have subsequently declined in the second quarter of 2025 due to the circumstances described below, extending the downward trend that began in the second half of 2024. Natural gas prices for the first quarter of 2025 increased slightly relative to the fourth quarter of 2024, but declined in early second quarter of 2025. Oil and natural gas prices have been, and may remain, volatile. As a net gas purchaser, our operating costs are generally expected to be more impacted by the volatility of natural gas prices than our gas sales. To reduce our exposure to oil and gas price volatility and in accordance with the covenants of our debt agreements, our strategy includes maintaining an active hedging program covering a significant portion of our forecasted production to help us achieve more predictable cash flows. For more information regarding our hedging program, see “Liquidity and Capital Resources—Hedging.”

Our well servicing and abandonment services business is dependent on expenditures of oil and gas companies, which can in part reflect the volatility of commodity prices, as well as the impact from changes in the regulatory environment. Existing oil and natural gas wells require ongoing spending to maintain production, necessitating expenditures by oil and gas companies for the maintenance of existing wells, which can moderate the impact of a volatile price environment. Additionally, our customers’ requirements to plug and abandon wells are largely driven by regulatory requirements that are less dependent on commodity prices.

The price of oil is impacted by the actions of OPEC+ and since 2022 they have implemented production cuts to address imbalances in global supply levels. In December 2024, OPEC+ extended the reduced production quotas of 3.65 mmbbl/d through the end of 2026 and extended the 2.2 mmbbl/d voluntary cuts through the end of March 2025. In April and May 2025, OPEC+ began a phased rollback of the 2.2 million voluntary cuts initially announced in November 2023, and the broader 22-member OPEC+ alliance has 3.65 mmbbl/d of separate cuts that are scheduled to remain in place until the end of 2026.

In addition, since being sworn into office, President Trump has issued numerous executive orders aimed at increasing oil production and decreasing commodity prices, among other matters, and has separately instituted tariffs that could cause inflation, slow economic growth, and intensify trade disputes. Collectively, these actions have created uncertainty in the market which has contributed to recent oil price declines. In early April 2025, the administration announced a substantial number of trade tariffs, including a new universal baseline tariff of 10%, plus additional country-specific tariffs for select trading partners, on almost all U.S. imports. The additional country-specific tariffs have been paused for 90 days (until July 8, 2025), other than China, which was further increased. While imports of oil, gas and refined products were given exemptions from the tariffs, concerns that the measures could cause inflation, slow economic growth and intensify trade disputes has also placed downward pressure on oil prices. With negotiations and countermeasures ongoing, the situation is fluid, and we cannot predict when prices will stabilize or improve. In addition, tariffs have the potential to significantly increase our operating and capital costs; however, we do not expect any material impact through at least 2025 based on current inventory levels and purchasing needs. We continue to monitor the economic effects of U.S. trade policy as well as opportunities to mitigate their impacts on costs and prices, though the ultimate policy and its effect remains uncertain.

Futures forward curves for crude oil reflect this ongoing uncertainty, suggesting that price volatility may persist and affect our operations and financial outlook. As a result of operating evaluations, market volatility and price declines we recorded a non-cash pre-tax asset impairment charge of $158 million ($113 million after-tax) on one of our non-thermal diatomite proved properties in California in the first quarter of 2025.

Oil and natural gas prices could fluctuate further with any changes in demand due to, among other things, the ongoing conflict in Ukraine, the ongoing conflict in the Middle East, international sanctions, speculation as to future actions by OPEC+, higher gas prices, high interest rates, tariffs, inflation and government efforts to reduce inflation,

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and possible changes in the overall health of the global economy, including increased volatility in financial and credit markets or a prolonged recession.

Commodity Pricing and Differentials

Our cash flow, 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.

Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. We use derivatives to hedge a portion of our forecasted oil and gas production and gas purchases to reduce our exposure to fluctuations in oil and natural gas prices. The following table sets forth certain average benchmark prices, average realized prices and price realizations as a percentage of average benchmark prices for our products for the periods indicated below.


	Three Months Ended
	March 31, 2025			December 31, 2024			March 31, 2024
	Average Price		Realization(1)	Average Price		Realization(1)	Average Price		Realization(1)
Sales of Crude Oil (per bbl):
Brent	$	74.98		$	74.01		$	81.76

Realized price without derivative settlements	$	69.48	93%	$	69.08	93%	$	75.31	92%
Effects of derivative settlements	0.08			1.64			(2.17)
Realized price with derivative settlements	$	69.56	93%	$	70.72	96%	$	73.14	89%

WTI	$	71.51		$	70.33		$	77.02

Realized price without derivative settlements	$	69.48	97%	$	69.08	98%	$	75.31	98%




Purchased Natural Gas (per mmbtu)
Average Monthly Settled Price - NWPL	$	3.88		$	3.09		$	3.41

Realized price without derivative settlements	$	4.35	112%	$	3.76	122%	$	4.11	121%
Effects of derivative settlements	0.35			0.62			0.92
Realized price with derivative settlements	$	4.70	121%	$	4.38	142%	$	5.03	148%

__________

(1) Represents the percentage of our realized prices compared to the indicated index.

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Oil Prices

California oil prices are Brent-influenced as California refiners import approximately 77% of the state’s demand from OPEC+ countries and other waterborne sources. We believe that receiving Brent-influenced pricing contributes to our ability to continue realizing strong cash margins in California. Though the California market generally receives Brent-influenced pricing, California oil prices are also determined by local supply and demand dynamics, including third-party transportation and infrastructure capacity. In the first quarter of 2025, the average oil price was generally flat relative to the fourth quarter of 2024 and decreased relative to the first quarter of 2024. Oil prices (at spot) declined towards the end of the first quarter of 2025, with further declines into the second quarter of 2025. Spot oil price declines in the latter part of the first quarter also drove deterioration in the oil forward prices at March 31, 2025.

In October 2024, Phillips 66 announced plans to close its Wilmington refinery in Los Angeles in late 2025. Additionally, in April 2025, Valero announced plans to close its Benicia refinery in the San Francisco Bay Area by April 2026. Following the closure of these refineries, we expect California to have approximately 1.3 million barrels per day of remaining refining capacity, which is over four times the amount of crude oil produced in California in 2024. As a result, we do not currently expect the pending refinery closures to negatively impact our price realizations; however, additional refinery closures may could have an adverse impact on our ability to market our crude production in California.

Utah oil prices have historically traded at a discount to WTI. The oil is sold to local refineries that are designed for the oil's unique characteristics and transported via rail to other refiners, primarily in the Gulf Coast. We have high operational control of our existing acreage, which provides significant upside for additional vertical and/or horizontal development wells and recompletions. For the three months ended March 31, 2025, December 31, 2024, and March 31, 2024, Utah had an average realized oil price of $56.20, $57.25 and $65.79, respectively, compared to an average Brent oil price of $74.98, $74.01 and $81.76 for the same periods.

Gas Prices

For our California steam operations, the price we pay for fuel gas purchases is generally based on the Northwest, Rocky Mountains index for purchases made in the Rockies and the SoCal Gas city-gate index for 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. The price from the Northwest, Rocky Mountain index was as high as $4.42 per mmbtu and as low as $3.36 per mmbtu in the first quarter of 2025. The price from the SoCal Gas city-gate index was as high as $4.96 per mmbtu and as low as $4.09 per mmbtu in the first quarter of 2025. Overall, on an unhedged basis, we paid an average of $4.35 per mmbtu in the first quarter of 2025 for our gas purchases which includes transportation costs. When including the hedging effects in our gas purchases, we paid $4.70, $4.38 and $5.03 per mmbtu in the first quarter of 2025, the fourth quarter of 2024, and the first quarter of 2024, respectively.

The price of our gas sales is generally based on the Northwest, Rocky Mountains index, as selling at the same index as fuel gas purchases provides a natural hedge for gas purchases. In the first quarter of 2025, our Utah operations had an average realized gas price of $3.95, compared to an average Northwest, Rocky Mountains gas price of $3.88, which was a 102% realization. In the three months ended December 31, 2024 and March 31, 2024, Utah had an average realized gas price of $3.47, and $3.76, compared to an average Northwest, Rocky Mountains gas price of $3.09, or 112% realization, and $3.41, or 110% realization, respectively.

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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. We purchase most of our gas in the Rockies and transport it to our California operations using our Kern River pipeline capacity. Beginning in 2025, we purchased approximately 43,000 mmbtu/d in the Rockies (48,000 mmbtu/d prior to this change), with the remaining volumes purchased in California markets. Gas volumes purchased in California fluctuate and averaged 4,000 mmbtu/d in the first quarter of 2025, 3,000 mmbtu/d in the fourth quarter of 2024 and 5,000 mmbtu/d in the first quarter of 2024. The natural gas we purchase in the Rockies is shipped to our operations in California to help limit our exposure to California fuel gas purchase price fluctuations. We strive to further minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of our gas purchases. 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. The Kern River pipeline capacity allows us to purchase and sell natural gas at the same pricing indices.

We seek to mitigate a substantial portion of the gas purchase price exposure for our cogeneration plants by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. 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. Gas prices increased in the first quarter of 2025 compared to the fourth quarter of 2024. Our hedging strategy coupled with our midstream access to gas from the Rockies helps us mitigate the impact of high natural gas prices on our cost structure.

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 December 2025 and November 2026. The most significant input and cost of the cogeneration facilities is natural gas.

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.

Regulatory Matters

Like other companies in the oil and gas industry, our business is 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. Federal, state and local agencies may assert overlapping authority to regulate in these areas. 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.

Permitting Update

Over the last few years, a number of developments at both the California state and local levels have resulted in significant delays in the issuance of permits to drill new oil and gas wells in Kern County, where all of our California assets are located. We have secured all of the permits necessary to execute our 2025 operating plan, as well as to support drilling and workover activity into 2026. It is possible that future permitting delays could adversely impact our plans in 2026 and beyond, and the inability to secure the permits and other approvals (on a timely basis or at all) required to develop our assets could adversely impact our business and results of operations. For additional information regarding well permitting with respect to our California operations, see Part I, Item 1 “Regulatory Matters” in our Annual Report.

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Executive Orders Relating to Energy Production

Since being sworn into office, President Trump has issued numerous Executive Orders aimed to increase oil production and decrease commodity prices. For example, President Trump declared a “national energy emergency” in early January 2025, and gave the executive branch more power to expedite approvals for energy resource infrastructure (including oil and gas). Additionally, President Trump’s “Unleashing American Energy” Executive Order incorporated numerous provisions aimed at unburdening and removing impediments to the development of various domestic energy resources, such as oil and gas. More recently, in April 2025, President Trump signed an Executive Order that, among other matters, directed the U.S. Attorney General to investigate certain state laws that may adversely impact the development of energy resources, including state laws relating to climate change, environmental, social and governance initiatives, and funds collecting carbon penalties and/or taxes. We cannot predict what impact this Executive Order or others may ultimately have on our operations or state and local laws and regulations relating to oil and gas and climate change.

Inflation

The Company, similar to other companies in our industry, has experienced inflationary pressures on our costs over the past few years which has resulted in increases to the costs of our goods, services and personnel, which in turn, have caused our capital expenditures and operating costs to rise since 2021. During the first quarter of 2025, inflation rates continued to stabilize and decrease following a trend of increasing inflation that began in the middle of 2023; however, there are concerns that the implementation of tariffs, if sustained, may cause additional inflationary pressure. We are unable to predict if such inflationary pressures and contributing factors will continue through the remainder of 2025. We will continue to monitor cost trends that could have an impact on our capital expenditures and operating costs.

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Our Capital Program

For the three months ended March 31, 2025, our total capital expenditures were approximately $28 million, including capitalized overhead and interest and excluding acquisitions and asset retirement spending. E&P and corporate expenditures were approximately $28 million and for the three months ended March 31, 2025 (which excludes well servicing and abandonment services capital of less than $1 million). Approximately 60% and 40% of these capital expenditures were directed to California and Utah operations, respectively. During the first three months of 2025 we drilled 12 wells in California and two horizontal wells in Utah, and commenced drilling a third horizontal well in Utah. We completed drilling the third and a fourth horizontal well in Utah during the second quarter of 2025, and all four horizontal wells are expected to be brought online in the third quarter of 2025.

Our 2025 capital expenditure budget for E&P operations, CJWS and corporate activities is expected to be between $110 to $120 million. Total capital expenditures were approximately $102 million in 2024. We intend for our total 2025 production volume to be generally consistent with 2024, and we currently anticipate approximately 93% of our production will be oil, consistent with 2024. Our 2025 E&P capital program proportionally allocates more capital to our Utah development opportunities than in prior years, as we are investing in opportunities to de-risk increased horizontal development in our Uinta Basin assets. We currently plan to direct approximately 40% of our 2025 planned capital expenditures (excluding CJWS) to Utah, compared to 25% in 2024. Our 2025 California drilling campaign is expected to be comprised of sidetracks (primarily in our thermal diatomite assets), and in Utah our plans are focused on drilling a four-well horizontal pad (the drilling of which was completed in the second quarter of 2025, with first production expected in the third quarter of 2025). We also may participate in non-operated horizontal wells on properties adjacent to ours. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund the remainder of our 2025 capital program from cash flow from operations. Please see “—Regulatory Matters” in this Quarterly Report, as well as in our Annual Report, for additional discussion of the laws and regulations that impact our ability to drill and develop our assets.

Exclusive of the capital expenditures noted above, for the full year 2025, we currently expect to spend approximately $14 million to $20 million on plugging and abandonment activities, most of which is planned to meet our annual requirements under California’s idle well regulations. In 2024, we spent approximately $15 million on plugging and abandonment activities, most of which was to meet our annual requirements under California idle well regulations. We spent approximately $5 million for plugging and abandonment activities in the three months ended March 31, 2025.

For information about the potential risks related to our capital program, see Part I, Item IA. “Risk Factors” in our Annual Report.

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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
	March 31, 2025		December 31, 2024		March 31, 2024
Average daily production:(1)
Oil (mbbl/d)	23.0		24.3		23.8
Natural Gas (mmcf/d)	7.9		8.4		7.9
NGL (mbbl/d)	0.4		0.4		0.3
Total (mboe/d)(2)	24.7		26.1		25.4
Total Production:
Oil (mbbl)	2,072		2,230		2,161
Natural gas (mmcf)	713		775		723
NGLs (mbbl)	34		41		28
Total (mboe)(2)	2,225		2,400		2,310
Weighted-average realized sales prices:
Oil without hedges ($/bbl)	$	69.48	$	69.08	$	75.31
Effects of scheduled derivative settlements ($/bbl)	$	0.08	$	1.64	$	(2.17)
Oil with hedges ($/bbl)	$	69.56	$	70.72	$	73.14
Natural gas ($/mcf)	$	3.95	$	3.47	$	3.76
NGL ($/bbl)	$	30.56	$	29.67	$	29.60
Average Benchmark prices:
Oil (bbl) – Brent	$	74.98	$	74.01	$	81.76
Oil (bbl) – WTI	$	71.51	$	70.33	$	77.02
Natural gas (mmbtu) – SoCal Gas city-gate(3)	$	4.50	$	3.57	$	4.21
Natural gas (mmbtu) – Northwest, Rocky Mountains(4)	$	3.88	$	3.09	$	3.41
Natural gas (mmbtu) – Henry Hub(4)	$	4.14	$	2.44	$	2.15

__________

(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, 2025, the average prices of Brent oil and Henry Hub natural gas were $74.98 per bbl and $4.14 per mmbtu.

(3) 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. SoCal Gas city-gate Index is the relevant index used only for the portion of gas purchases in California. In May 2022, we began purchasing a majority of our fuel gas in the Rockies using the Northwest, Rocky Mountains index.

(4) Most of our gas purchases and gas sales in the Rockies are predicated on the Northwest, Rocky Mountains index, and to a lesser extent based on Henry Hub.

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


	Three Months Ended
	March 31, 2025	December 31, 2024	March 31, 2024
Average daily production (mboe/d):(1)
California	20.4	21.8	21.3
Utah	4.3	4.3	4.1


Total average daily production	24.7	26.1	25.4

__________

(1) Production represents volumes sold during the period.

Our average daily production decreased 5%, or 1.4 mboe/d, for the three months ended March 31, 2025, compared to the three months ended December 31, 2024. Our California production was 20.4 mboe/d for the first quarter of 2025, a decrease of 6% or 1.4 mboe/d from the fourth quarter of 2024, mostly due to the impact from our sidetrack drilling activity that required temporary production curtailment in certain of our thermal diatomite properties. Utah production was consistent quarter-over-quarter at 4.3 mboe/d.

Our average daily production decreased 3%, or 0.7 mboe/d, for the three months ended March 31, 2025, compared to the three months ended March 31, 2024. California production was 20.4 mboe/d for the first quarter of 2025, 0.9 mboe/d lower than the first quarter of 2024 mostly due to the impact from our sidetrack drilling activity as discussed above, and to a lesser extent lower than expected recovery from one of our non-thermal diatomite California fields, partially offset by 0.3 mboe/d higher production from Round Mountain. Utah production increased 0.2 mboe/d with our non-operated horizontal wells higher by 0.5 mboe/d compared to the first quarter in 2024, partially offset by natural decline of our operated Uinta wells.

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Results of Operations

Three Months Ended March 31, 2025 compared to Three Months Ended December 31, 2024.


	Three Months Ended
	March 31, 2025		December 31, 2024		$ Change		% Change
	(in thousands)
Revenues and other:
Oil, natural gas and NGL sales	$	147,862	$	157,957	$	(10,095)	(6)	%
Service revenue(1)	23,664		23,554		110		—	%
Electricity sales	4,967		3,262		1,705		52	%
Gains (losses) on oil and gas sales derivatives	5,475		(5,730)		11,205		n/a
Marketing and other revenues	683		36		647		>100%

Total revenues and other	$	182,651	$	179,079	$	3,572	2	%

__________

(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $30 million and $29 million and the intercompany elimination was $6 million for the quarters ended March 31, 2025 and December 31, 2024, respectively.

Revenues and Other

Oil, natural gas and NGL sales decreased by $10 million, or 6%, to approximately $148 million for the three months ended March 31, 2025, compared to the three months ended December 31, 2024. The decrease included $11 million lower oil volumes impacted by temporary curtailment in certain of our thermal diatomite properties and was partially offset by a $1 million increase in oil prices during the first half of the first quarter.

Service revenue consisted entirely of revenue from the well servicing and abandonment services business, excluding intercompany amounts. Service revenue was flat at $24 million for the three months ended March 31, 2025, compared to the three months ended December 31, 2024.

Electricity sales represent sales to utilities and increased $2 million to $5 million for the three months ended March 31, 2025, compared to the three months ended December 31, 2024, due to higher operating rates and higher resource adequacy payments for our cogeneration facilities.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement gains for the three months ended March 31, 2025 and December 31, 2024 were less than $1 million and $7 million, respectively. This quarter-over-quarter decrease in settlement gains was primarily due to lower fixed prices relative to settlement prices in the first quarter 2025. The mark-to-market non-cash gain for the three months ended March 31, 2025, was $5 million compared to a loss of $13 million for the three months ended December 31, 2024. 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).

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	Three Months Ended				$ Change		% Change
	March 31, 2025		December 31, 2024
	(in thousands)
Expenses and other:
Lease operating expenses	$	57,282	$	55,763	$	1,519	3	%
Costs of services(1)	20,825		20,907		(82)		—	%
Electricity generation expenses	1,209		1,523		(314)		(21)	%
Transportation expenses	939		1,122		(183)		(16)	%
Marketing expenses	292		—		292		100	%

General and administrative expenses	20,305		18,389		1,916		10	%
Depreciation, depletion and amortization	40,392		43,579		(3,187)		(7)	%
Impairment of oil and gas properties	157,910		—		157,910		100	%
Taxes, other than income taxes	9,240		8,498		742		9	%

(Gains) losses on natural gas purchase derivatives	(5,691)		7,883		(13,574)		n/a
Other operating expense (income)	401		3,763		(3,362)		89	%
Losses on debt retirement	—		7,066		(7,066)		100	%
Total expenses and other	303,104		168,493		134,611		80	%
Other expenses:
Interest expense	(15,172)		(10,859)		(4,313)		40	%
Other, net	272		136		136		100	%

Total other expenses	(14,900)		(10,723)		(4,177)		39	%
Loss before income taxes	(135,353)		(137)		(135,216)		>100%
Income tax (benefit) expense	(38,673)		1,622		(40,295)		n/a
Net loss	$	(96,680)	$	(1,759)	$	(94,921)	>100%
Adjusted EBITDA(2)	$	68,450	$	81,780	$	(13,330)	(16)	%
Adjusted Net Income(2)	$	9,370	$	16,531	$	(7,161)	(43)	%

__________

(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $27 million and $26 million and the intercompany elimination was $6 million and $5 million for the three months ended March 31, 2025 and December 31, 2024, respectively.

(2) 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 “—Non-GAAP Financial Measures”.

Expenses

Lease operating expenses, which do not include the effects of gas purchase hedges, increased 3% or $2 million to $57 million in the first quarter of 2025 when compared to the fourth quarter of 2024, primarily due to higher well servicing activity. Natural gas (fuel) costs for our California steam generation facilities were flat compared to the fourth quarter of 2024 as higher prices were offset by fewer volumes purchased.

Costs of services consisted entirely of costs from the well servicing and abandonment services business, excluding intercompany amounts. Cost of services were $21 million in both the first quarter of 2025 and the fourth quarter of 2024.

Electricity generation expenses were lower by less than $1 million in the three months ended March 31, 2025 compared to the three months ended December 31, 2024.

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Natural gas purchase derivatives for the three months ended March 31, 2025, resulted in a gain of $6 million, mostly due to $7 million mark-to-market valuation gains, partially offset by $1 million of settlement losses. Natural gas derivatives in the fourth quarter of 2024 resulted in a $8 million loss, which included a $5 million mark-to-market valuation loss and a $3 million settlement loss. Quarter-over-quarter settlement losses decreased due to higher average settlement prices in the March quarter compared to those in the December quarter.

General and administrative expenses were $20 million for the three months ended March 31, 2025, compared to $18 million for the three months ended December 31, 2024. Amounts in each of these periods included $2 million in non-cash stock compensation.

Adjusted General and Administrative Expenses, which exclude non-cash stock compensation expense and non-recurring costs, increased $2 million primarily due to higher employee-related expenses and professional services in the three months ended March 31, 2025, compared to the three months ended December 31, 2024. See “—Non-GAAP Financial Measures” for a reconciliation of general and administrative expenses, the most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted General and Administrative Expenses.

DD&A decreased $3 million for the three months ended March 31, 2025, compared to the three months ended December 31, 2024 primarily due to lower production.

Impairment of Oil and Gas Properties

As a result of operating evaluations, market volatility and price declines we recorded a non-cash pre-tax asset impairment charge of $158 million ($113 million after-tax) on one of our non-thermal diatomite proved properties in California for the three months ended March 31, 2025. For information regarding Impairment of Oil and Gas Properties, see “Note 10—Oil and Natural Gas Properties” in the notes to condensed consolidated financial statements in Part I, Item 1. “Financial Statements” in this Quarterly Report.

Taxes, Other Than Income Taxes



	Three Months Ended				$ Change		% Change
	March 31, 2025		December 31, 2024
	(per boe)
Severance taxes	$	2.13	$	1.62	$	0.51	31	%
Ad valorem and property taxes	2.14		1.15		0.99		86	%
Greenhouse gas allowances and other emission costs	(0.12)		0.77		(0.89)		>100%

Total taxes other than income taxes	$	4.15	$	3.54	$	0.61	17	%

Taxes, other than income taxes, increased in the three months ended March 31, 2025 by $0.61 per boe, or 17%, to $4.15. The increase included higher ad valorem and severance taxes driven by supplemental taxes, partially offset by lower GHG cost due to lower mark-to-market prices.

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Other Operating (Income) Expenses

For the three months ended March 31, 2025, other operating income was less than $1 million and included a sale of assets. For the three months ended December 31, 2024, other operating expense was approximately $4 million and included approximately $3 million of prior period insurance true-ups in the fourth quarter of 2024.

Loss on Debt Retirement

For the three months ended March 31, 2025, we had no loss on debt retirement. For the three months ended December 31, 2024, loss on debt retirement was $7 million and includes expenses related to the retirement of our former debt facilities, as well as financing activities we terminated upon successful completion of the 2024 Term Loan and the 2024 revolver.

Interest Expense

Interest expense increased $4 million for the three months ended March 31, 2025, compared to the three months ended December 31, 2024, due to a higher interest rate associated with our borrowings and increased amortization of deferred financing costs.

Income Taxes

Our effective tax rate was 29% for the three months ended March 31, 2025, compared to approximately 31% for the year ended December 31, 2024. The rate in both periods included the impact of tax credits generated and the impact of nondeductible compensation and other permanent items.

Three Months Ended March 31, 2025 compared to Three Months Ended March 31, 2024.



	Three Months Ended March 31,				$ Change		% Change
	2025		2024
	(in thousands)
Revenues and other:
Oil, natural gas and NGL sales	$	147,862	$	166,318	$	(18,456)	(11)	%
Service revenue(1)	23,664		31,683		(8,019)		(25)	%
Electricity sales	4,967		4,243		724		17	%
Gains (losses) on oil and gas sales derivatives	5,475		(71,200)		76,675		n/a
Marketing and other revenues	683		5,036		(4,353)		(86)	%
Total revenues and other	$	182,651	$	136,080	$	46,571	34	%

__________

(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $30 million and $35 million and the intercompany elimination was $6 million and $4 million for the quarters ended March 31, 2025 and 2024, respectively.

Revenues and Other

Oil, natural gas and NGL sales decreased $18 million, or 11%, to approximately $148 million for the three months ended March 31, 2025, when compared to the three months ended March 31, 2024. The decrease in revenue was driven by $12 million lower oil prices and $6 million lower oil volumes that were impacted by temporary curtailment in certain of our thermal diatomite properties due to our sidetrack drilling activity, and to a less extent lower than expected recovery from one of our non-thermal diatomite California fields.

Service revenue (excluding intercompany amounts) decreased by $8 million, or 25%, to $24 million for the three months ended March 31, 2025, compared to the three months ended March 31, 2024, due to decreases in activity and rates in the first quarter of 2025.

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Electricity sales represent sales to utilities and were slightly higher at $5 million for the three months ended March 31, 2025, primarily due to higher operating volumes and resource adequacy payments when compared to the three months ended March 31, 2024.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Settlement gains for the three months ended March 31, 2025 were less than $1 million compared to losses of $5 million for the three months ended March 31, 2024. Settlement gains in the first quarter of 2025 were driven by a higher average fixed price relative to average settlement prices. Notional volumes were 15 mbbl/d in the first quarter of 2025 compared to 17 mbbl/d in the first quarter of 2024. The mark-to-market non-cash gains for the three months ended March 31, 2025 were $5 million compared to $67 million losses for the three months ended March 31, 2024. 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, which typically includes third-party gas marketing and processing revenue as well as revenue from gas we purchased in the Rockies and sold into the California market, was less than $1 million in the three months ended March 31, 2025, $4 million lower than the same period in 2024 due to less gas marketing activity.


	Three Months Ended March 31,				$ Change		% Change
	2025		2024
	(in thousands)
Expenses and other:
Lease operating expenses	$	57,282	$	61,276	$	(3,994)	(7)	%
Costs of services(1)	20,825		27,304		(6,479)		(24)	%
Electricity generation expenses	1,209		1,093		116		11	%
Transportation expenses	939		1,059		(120)		(11)	%
Marketing expenses	292		4,390		(4,098)		(93)	%
Acquisition costs(2)	—		2,617		(2,617)		(100)	%
General and administrative expenses	20,305		20,234		71		—	%
Depreciation, depletion and amortization	40,392		42,831		(2,439)		(6)	%
Impairment of oil and gas properties	157,910		—		157,910		100	%
Taxes, other than income taxes	9,240		15,689		(6,449)		(41)	%

(Gains) losses on natural gas purchase derivatives	(5,691)		4,481		(10,172)		n/a
Other operating expense (income)	401		(133)		534		>100%
Total expenses and other	303,104		180,841		122,263		68	%
Other expenses:
Interest expense	(15,172)		(9,140)		(6,032)		66	%
Other, net	272		(83)		355		>100%

Total other expenses	(14,900)		(9,223)		(5,677)		62	%
Loss before income taxes	(135,353)		(53,984)		(81,369)		>100%
Income tax benefit	(38,673)		(13,900)		(24,773)		n/a
Net loss	$	(96,680)	$	(40,084)	$	(56,596)	>100%


Adjusted EBITDA(3)	$	68,450	$	68,534	$	(84)	—	%
Adjusted Net Income(3)	$	9,370	$	10,910	$	(1,540)	(14)	%

__________

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(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $27 million and $31 million and the intercompany elimination was $6 million and $4 million for the quarters ended March 31, 2025 and March 31, 2024, respectively.

(2) Includes legal and other professional expenses related to various transactions activities.

(3) 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 “—Non-GAAP Financial Measures”.

Expenses

Lease operating expenses, which do not include the effects of gas purchase hedges, decreased 7% or $4 million to $57 million for the first quarter of 2025 when compared to the first quarter of 2024. Non-fuel lease operating expense decreased $2 million in the first quarter of 2025 due to lower outside services and power costs. Additionally, there was a $2 million decrease in natural gas (fuel) costs for our California steam generation facilities, which includes a $6 million dollar decrease in volumes purchased as a result of our cost savings initiatives to reduce steam, partially offset by a $4 million increase in fuel prices.

Cost of services (excluding intercompany amounts) decreased $6 million, or 24%, to $21 million for the first quarter of 2025 compared to the same period in 2024 primarily due to cost savings in response to lower activity.

Natural gas purchase derivatives in the three months ended March 31, 2025, resulted in a gain of $6 million, mostly due to $7 million mark-to-market valuation gains, partially offset by $1 million of settlement losses. Natural gas purchase derivatives in the same period of 2024 consisted primarily of $4 million settlement losses, which resulted from lower average settlement price than the average fixed price of settled positions.

Marketing expenses, which typically includes third-party gas marketing and processing revenue as well as revenue from gas we purchased in the Rockies and sold into the California market, was less than $1 million in the three months ended March 31, 2025, $4 million lower than the same period in 2024 due to less gas marketing activity.

There were no acquisition costs for the three months ended March 31, 2025, compared to $3 million in the three months ended March 31, 2024, which included legal and other professional expenses related to various transaction activities.

General and administrative expenses were $20 million for each of the three months ended March 31, 2025, and 2024. For the three months ended March 31, 2025, general and administrative expenses had $2 million in non-cash stock compensation expense compared to less than $1 million for March 31, 2024. We had no non-recurring costs for the three months ended March 31, 2025, and $1 million in the three months ended March 31, 2024.

Adjusted General and Administrative Expenses, which exclude non-cash stock compensation expense and non-recurring costs were flat for the three months ended March 31, 2025 compared to the three months ended March 31, 2024. See “—Non-GAAP Financial Measures” for a reconciliation of general and administrative expenses, the most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted General and Administrative Expenses.

DD&A decreased $2 million, or 6%, to $40 million in the three months ended March 31, 2025, primarily due to lower production when compared to the three months ended March 31, 2024.

Impairment of Oil and Gas Properties

As a result of operating evaluations, market volatility and price declines we recorded a non-cash pre-tax asset impairment charge of $158 million ($113 million after-tax) on one of our non-thermal diatomite proved properties in California for the three months ended March 31, 2025. For information regarding Impairment of Oil and Gas Properties, see “Note 10—Oil and Natural Gas Properties” in the notes to condensed consolidated financial statements in Part I, Item 1. “Financial Statements” in this Quarterly Report.

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Taxes, Other Than Income Taxes



	Three Months Ended March 31,				$ Change		% Change
	2025		2024
	(per boe)
Severance taxes	$	2.13	$	1.67	$	0.46	28	%
Ad valorem and property taxes	2.14		2.51		(0.37)		(15)	%
Greenhouse gas allowances and other emission costs	(0.12)		2.61		(2.73)		>100%
Total taxes other than income taxes	$	4.15	$	6.79	$	(2.64)	(39)	%

Taxes, other than income taxes decreased in the three months ended March 31, 2025, by 39% to $4.15 per boe primarily due to GHG allowance expense driven by lower mark-to-market prices in the first quarter of 2025 compared to the same period in 2024.

Other Operating (Income) Expenses

Other income was not material for the three months ended March 31, 2025 and 2024.

Interest Expense

Interest expense increased $6 million in the three months ended March 31, 2025, when compared to the three months ended March 31, 2024, to a higher interest rate associated with our borrowings and increased amortization of deferred financing costs.

Income Taxes

Our effective tax rate was approximately 29% for the three months ended March 31, 2025 compared to approximately 26% for the three months ended March 31, 2024. The rate in both periods included the impact of tax credits generated and the impact of nondeductible compensation and other permanent items.

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Non-GAAP Financial Measures

Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), Adjusted General and Administrative Expenses and E&P Operating Costs

Adjusted EBITDA is not a measure of either net income (loss) or cash flow, Free Cash Flow is not a measure of cash flow, Adjusted Net Income (Loss) is not a measure of net income (loss), and Adjusted General and Administrative Expenses is not a measure of general and administrative expenses, in all cases, as determined by GAAP. Rather, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and 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. 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. We also use Adjusted EBITDA in planning our capital expenditure allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2024 Term Loan and 2024 Revolver.

We define Free Cash Flow as cash flow from operations less capital expenditures. We use Free Cash Flow as the primary metric to measure our ability to pay dividends, pay down debt, repurchase stock, and make strategic growth and bolt-on acquisitions. Management believes Free Cash Flow may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base after capital expenditures and to fund such activities. 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 Free Cash Flow is available for dividends, debt repayment, share repurchases, strategic acquisitions or other growth opportunities, 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 Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our 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 believe Adjusted Net Income (Loss) 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 investors to compare our period-to-period results with our peers.

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, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and 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

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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, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

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



	Three Months Ended
	March 31, 2025		December 31, 2024		March 31, 2024
	(in thousands)
Adjusted EBITDA reconciliation:
Net loss	$	(96,680)	$	(1,759)	$	(40,084)
Add (Subtract):
Interest expense	15,172		10,859		9,140
Income tax (benefit) expense	(38,673)		1,622		(13,900)
Depreciation, depletion and amortization	40,392		43,579		42,831
Impairment of oil and gas properties	157,910		—		—

(Gains) losses on derivatives	(11,166)		13,613		75,681
Net cash (paid) received for scheduled derivative settlements	(1,312)		722		(9,094)
Other operating expense (income)	401		3,763		(133)
Stock compensation expense	2,406		2,315		385
Acquisition costs(1)	—		—		2,617
Non-recurring costs(2)	—		—		1,091
Losses on debt retirement(3)	—		7,066		—

Adjusted EBITDA	$	68,450	$	81,780	$	68,534

__________

(1) Includes legal and other professional expenses related to various transaction activities.

(2) Non-recurring costs included cost savings initiatives.

(3) Includes expenses related to the retirement of our former debt facilities, as well as financing activities we terminated upon successful completion of the 2024 Term Loan and 2024 Revolver.

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	Three Months Ended
	March 31, 2025		December 31, 2024		March 31, 2024
	(in thousands)
Adjusted EBITDA reconciliation:
Net cash provided by operating activities	$	45,872	$	41,361	$	27,273
Add (Subtract):
Cash interest payments	13,459		14,129		15,256
Cash income tax payments	66		651		—

Acquisition costs(1)	—		—		2,617
Non-recurring costs(2)	—		—		1,091

Changes in operating assets and liabilities - working capital(3)	9,265		13,535		22,543
Other operating (income) expenses - cash portion(4)	(212)		7,664		(246)
Losses on debt retirement - cash portion(5)	—		4,440		—

Adjusted EBITDA	$	68,450	$	81,780	$	68,534

__________

(1) Includes legal and other professional expenses related to various transaction activities.

(2) Non-recurring costs included cost savings initiatives.

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

(4) Represents the cash portion of other operating (income) expenses from the income statement, net of the non-cash portion in the cash flow statement.

(5) Includes expenses related to the financing activities we terminated upon successful completion of the 2024 Term Loan and the 2024 Revolver.

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


	Three Months Ended
	March 31, 2025		December 31, 2024		March 31, 2024
	(in thousands)
Free Cash Flow reconciliation:
Net cash provided by operating activities	$	45,872	$	41,361	$	27,273

Capital expenditures	(28,389)		(17,217)		(16,936)

Free Cash Flow	$	17,483	$	24,144	$	10,337

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The following table presents a reconciliation of the GAAP financial measures of net income (loss) and net income (loss) per share — diluted to the non-GAAP financial measures of Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share — diluted for each of the periods indicated.


	Three Months Ended
	March 31, 2025				December 31, 2024				March 31, 2024
	(in thousands)		per share - diluted		(in thousands)		per share - diluted		(in thousands)		per share - diluted
Adjusted Net Income (Loss) reconciliation:
Net loss	$	(96,680)	$	(1.25)	$	(1,759)	$	(0.02)	$	(40,084)	$	(0.52)

Add (Subtract):
(Gains) losses on derivatives	(11,166)		(0.14)		13,613		0.18		75,681		0.98
Net cash (paid) received for scheduled derivative settlements	(1,312)		(0.02)		722		0.01		(9,094)		(0.12)
Other operating expenses (income)	401		—		3,763		0.04		(133)		—
Impairment of oil and gas properties	157,910		2.04		—		—		—		—
Acquisition costs(1)	—		—		—		—		2,617		0.03
Non-recurring costs(2)	—		—		—		—		1,091		0.02
Losses on debt retirement(3)	—		—		7,066		0.09		—		—

Total additions, net	145,833		1.88		25,164		0.32		70,162		0.91
Income tax (expense) of adjustments(4)	(39,783)		(0.51)		(6,874)		(0.09)		(19,168)		(0.25)
Adjusted Net Income	$	9,370	$	0.12	$	16,531	$	0.21	$	10,910	$	0.14

Basic EPS on Adjusted Net Income	$	0.12			$	0.21			$	0.14
Diluted EPS on Adjusted Net Income	$	0.12			$	0.21			$	0.14

Weighted average shares of common stock outstanding - basic	77,196				76,939				76,254
Weighted average shares of common stock outstanding - diluted	77,371				77,213				77,373

__________

(1) Includes legal and other professional expenses related to various transaction activities.

(2) Non-recurring costs included cost savings initiatives.

(3) Includes expenses related to the retirement of our former debt facilities, as well as financing activities we terminated upon successful completion of the 2024 Term Loan and the 2024 Revolver.

(4) The federal and state statutory rates were utilized for all periods presented.

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

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	Three Months Ended
	March 31, 2025		December 31, 2024		March 31, 2024
	(in thousands)
Adjusted General and Administrative Expense reconciliation:
General and administrative expenses	$	20,305	$	18,389	$	20,234
Subtract:
Non-cash stock compensation expense (G&A portion)	(2,005)		(2,064)		(200)

Non-recurring costs(1)	—		—		(1,091)
Adjusted general and administrative expenses	$	18,300	$	16,325	$	18,943

Well servicing and abandonment services segment	$	2,300	$	2,015	$	2,929

E&P segment, and corporate	$	16,000	$	14,310	$	16,014
E&P segment, and corporate ($/boe)	$	7.19	$	5.96	$	6.93

Total mboe	2,225		2,400		2,310

__________

(1) Non-recurring costs included cost savings initiatives.

Overall, management assesses the efficiency of our E&P operations by considering core E&P operating costs. The substantial majority of such costs are our lease operating expenses (“LOE”) which includes fuel gas, purchased power, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. A core component of our E&P operations in California is steam, which we use to lift heavy oil to the surface. The most significant cost component of generating steam is the fuel gas purchased to operate traditional steam generators and our cogeneration facilities.

The following table includes key components of our LOE as well as the gas purchase hedge effect of the fuel used in our steam generation. Energy LOE consists of the costs to generate the steam and electricity we produce and use in our operations and the power we purchase for our E&P operations. Non-energy LOE consists of all remaining LOE costs. Energy LOE - hedged includes the realized (cash settled) hedge effects on the fuel gas we purchase. LOE - hedged includes the realized (cash settled) hedge effects on our total LOE.

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	Three months ended
	March 31, 2025		December 31, 2024		March 31, 2024
	(in thousands)
Energy LOE - unhedged	$	26,323	$	27,597	$	30,090
Non-energy LOE	30,959		28,166		31,186
Lease operating expenses(1)	57,282		55,763		61,276

Gas purchase hedges - realized	1,476		3,184		4,412

Lease operating expenses - hedged	$	58,758	$	58,947	$	65,688



Energy LOE - unhedged	$	26,323	$	27,597	$	30,090
Gas purchase hedges - realized	1,476		3,184		4,412
Energy LOE - hedged	$	27,799	$	30,781	$	34,502


		Three months ended
		March 31, 2025		December 31, 2024		March 31, 2024
	(per boe)
Energy LOE - unhedged		$	11.83	$	11.50	$	13.03
Non-energy LOE		13.91		11.74		13.50
Lease operating expenses(1)		25.74		23.24		26.53

Gas purchase hedges - realized		0.66		1.33		1.91

Lease operating expenses - hedged		$	26.40	$	24.57	$	28.44



Energy LOE - unhedged		$	11.83	$	11.50	$	13.03
Gas purchase hedges - realized		0.66		1.33		1.91
Energy LOE - hedged		$	12.49	$	12.83	$	14.94

__________

(1) Lease operating expenses (“LOE”) is also referred to as LOE - unhedged.

Energy LOE - hedged and LOE - hedged are not complete measures of our operating costs. These 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. Our management believes Energy LOE - hedged and LOE - hedged provide useful information in assessing our operating costs and results of operations and are used by the industry and the investment community. These measures also allow our management to more effectively evaluate our operating performance and compare the results between periods.

While Energy LOE - hedged and LOE - hedged are non-GAAP measures, the amounts included in the calculation of these measures were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, operating costs in accordance with GAAP and should not be considered as an alternative to, or more meaningful than cost measures calculated in accordance with GAAP. Our computations of Energy LOE - hedged and LOE - hedged may not be comparable to other similarly titled measures used by other companies. Energy LOE - hedged and LOE - hedged should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

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Liquidity and Capital Resources

As of March 31, 2025, we had liquidity of $120 million consisting of $39 million of cash, $49 million of available borrowing capacity and no borrowings outstanding under the 2024 Revolver, and approximately $32 million of available commitments with no borrowings outstanding under the Delayed Draw Term Loan (defined below) provided under the 2024 Term Loan (as defined below). We also had $439 million in borrowings outstanding on our 2024 Term Loan at the end of the first quarter 2025.

We review the allocations of our Free Cash Flow from time to time based on then existing conditions and circumstances, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors. Our capital allocation approach prioritizes debt reduction in alignment with the covenants contained in the 2024 Term Loan and facilitates our operating strategy and business plans while enabling investment in development opportunities.

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 Free Cash Flow is available for dividends, debt or share repurchases, strategic acquisitions or other growth opportunities, or other discretionary expenditures, since we have non-discretionary expenditures that are not deducted from this measure. Free Cash Flow is a non-GAAP financial measure. See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for a reconciliation of the GAAP financial measure of operating cash flow, our most directly comparable financial measure calculated and presented in accordance with GAAP, to the non-GAAP financial measure of Free Cash Flow.

We currently believe that our liquidity, capital resources and cash will be sufficient to conduct our business and operations and meet our obligations for at least the next 12 months. Based on current commodity prices and our development success rate to date, we expect to be able to fund the remainder of our 2025 capital program from cash flow from operations. 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 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 I, Item 1A. “Risk Factors” in our Annual Report 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.

2024 Term Loan

On November 6, 2024, the Company entered into a Senior Secured Term Loan Credit Agreement (the “Original Term Loan Agreement”) among Berry Corp., as borrower, certain subsidiaries of Berry Corp., as guarantors, Breakwall Credit Management LLC, as administrative agent, and the lenders from time to time party thereto. On December 24, 2024, the parties entered into the First Amendment to the Original Term Loan Agreement (the “Term Loan Amendment”), which aligned certain terms with the 2024 Revolver. The Original Term Loan Agreement, as amended by the Term Loan Amendment, is referred to as the “2024 Term Loan.”

The 2024 Term Loan provides for (i) an initial term loan facility in aggregate principal amount of $450 million (the “Initial Term Loan”) and (ii) a delayed draw term loan facility with commitments in aggregate principal amount of up to $32 million (the “Delayed Draw Term Loan”) which is available for borrowing until December 24, 2026, subject to satisfaction of certain customary conditions precedent, as further set forth in the 2024 Term Loan. We borrowed $450 million under the Initial Term Loan on December 24, 2024, in part, to fund the redemption or repayment, as applicable, of $403 million of outstanding debt, to fund a portion of the costs and expenses associated with the execution of the 2024 Revolver and 2024 Term Loan, the termination of our former revolving debt facilities, and for other general corporate purposes. The commitments under the Delayed Draw Term Loan will be reduced, on a dollar-for-dollar basis, by any increase in the commitments under the 2024 Revolver.

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As of March 31, 2025, we had $439 million of borrowings outstanding under the 2024 Term Loan and $32 million of available commitments and no borrowings outstanding under the Delayed Draw Term Loan. For additional information regarding the 2024 Term Loan and Delayed Draw Term Loan, see “Note 2—Debt” in the notes to condensed consolidated financial statements in Part I, Item 1. “Financial Statements” in this Quarterly Report.

2024 Revolver

As of March 31, 2025, we had approximately $49 million of available borrowing capacity under the 2024 Revolver with $14 million of letters of credit and no borrowings outstanding. For additional information regarding the 2024 Revolver, see “Note 2—Debt” in the notes to condensed consolidated financial statements in Part I, Item 1. “Financial Statements” in this Quarterly Report..

Hedging

We have protected a significant portion of our anticipated cash flows through 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 gas purchases to protect against price increases. We have also entered into gas transportation contracts in the Rockies to help reduce the price fluctuation exposure; however these do not qualify as hedges.

The 2024 Revolver and 2024 Term Loan each requires us to maintain commodity hedges as described in “Note 3—Derivatives” in the notes to condensed consolidated financial statements in Part I, Item 1. “Financial Statements” in this Quarterly Report.

Our generally low-decline production base 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 Part I—Item 1A. “Risk Factors—Risks Related to Our Operations and Industry” in our Annual Report.

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As of May 2, 2025, we had the following crude oil production and gas purchases hedges.


	Q2 2025		Q3 2025		Q4 2025		FY 2026		FY 2027		FY 2028
Brent - Crude Oil production
Swaps
Hedged volume (bbls)	1,637,198		1,613,083		1,518,000		5,247,518		3,483,500		1,505,500
Hedged volume (mbbls) per day	18.0		17.5		16.5		14.4		9.5		4.1
Weighted-average price ($/bbl)	$	74.35	$	74.48	$	75.28	$	69.74	$	69.72	$	68.05
Collars
Hedged volume (bbls)	—		—		—		180,000		182,000		—
Hedged volume (mbbls) per day	—		—		—		0.5		0.5		—
Weighted-average ceiling ($/bbl)	$	—	$	—	$	—	$	81.36	$	80.00	$	—





Weighted-average floor ($/bbl)	$	—	$	—	$	—	$	60.00	$	65.00	$	—











NWPL - Natural Gas purchases(1)
Swaps
Hedged volume (mmbtu)	3,640,000		3,680,000		3,680,000		12,160,000		—		—
Hedged volume (mbbtu) per day	40.0		40.0		40.0		33.3		—		—
Weighted-average price ($/mmbtu)	$	4.29	$	4.29	$	4.15	$	3.93	$	—	$	—

__________

(1) The term “NWPL” is defined as Northwest Rocky Mountain Pipeline and represents the index used for these gas purchase hedges.

Gains (losses) on Derivatives

A summary of gains and losses on the derivatives included on the statements of operations is presented below:


	Three Months Ended
	March 31, 2025		December 31, 2024		March 31, 2024
	(in thousands)
Realized (losses) gains on commodity derivatives:
Realized gains (losses) on oil sales derivatives	$	164	$	7,173	$	(4,682)
Realized (losses) on natural gas purchase derivatives	(1,476)		(3,184)		(4,412)
Total realized (losses) gains on derivatives	$	(1,312)	$	3,989	$	(9,094)

Unrealized gains (losses) on commodity derivatives:
Unrealized gains (losses) on oil sales derivatives	$	5,311	$	(12,903)	$	(66,518)
Unrealized gains (losses) on natural gas purchase derivatives	7,167		(4,699)		(69)
Total unrealized gains (losses) on derivatives	$	12,478	$	(17,602)	$	(66,587)
Total gains (losses) on derivatives	$	11,166	$	(13,613)	$	(75,681)

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



	Three Months Ended
	March 31, 2025		December 31, 2024		March 31, 2024
Crude Oil (per bbl):
Realized sales price, before the effects of derivative settlements	$	69.48	$	69.08	$	75.31
Effects of derivative settlements	0.08		1.64		(2.17)
Realized sales price, after the effects of derivative settlements	$	69.56	$	70.72	$	73.14
Purchased Natural Gas (per mmbtu):
Purchase price, before the effects of derivative settlements	$	4.35	$	3.76	$	4.11
Effects of derivative settlements	0.35		0.62		0.92
Purchase price, after the effects of derivatives settlements	$	4.70	$	4.38	$	5.03

Cash Dividends

Stock Repurchase Program

As of March 31, 2025, the Company’s remaining total share repurchase authority approved by the Board of Directors was $190 million. The Board of Directors’ authorization permits the Company to make purchases of its common stock from time to time in the open market and in privately negotiated transactions or by other means, subject to market conditions and other factors, up to the aggregate amount authorized by the Board of Directors. The Board of Directors’ authorization has no expiration date.

ATM Program

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During the three months ended March 31, 2025, the Company did not sell any shares of common stock under the ATM Program.

Statements of Cash Flows

The following is a comparative cash flow summary:



	Three Months Ended March 31,
	2025		2024
	(in thousands)
Net cash:
Provided by operating activities	$	45,872	$	27,273
Used in investing activities	(19,770)		(18,661)
Used in financing activities	(16,876)		(9,990)
Net increase (decrease) in cash and cash equivalents	$	9,226	$	(1,378)

Operating Activities

Cash provided by operating activities increased for the three months ended March 31, 2025 by approximately $19 million when compared to the three months ended March 31, 2024. The increase was primarily related to a decrease in derivative settlements paid, lower taxes, other than income taxes (specifically GHG), and a decrease in lease operating expenses, partially offset by a decrease in revenue from lower oil prices and lower volumes, and a decrease in net margin from CJWS.

Investing Activities

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



	Three Months Ended March 31,
	2025		2024
	(in thousands)
Capital expenditures:
Capital expenditures	$	(28,389)	$	(16,936)

Changes in capital expenditures accruals	8,099		(957)
Acquisitions, net of cash received	—		(768)
Proceeds from sale of property and equipment and other	520		—

Net cash used in investing activities	$	(19,770)	$	(18,661)

Cash used in investing activities increased $1 million for the three months ended March 31, 2025 when compared to the same period in 2024, primarily due to increased capital expenditures mainly from drilling activity, partially offset by an increase in capital expenditure accruals.

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Financing Activities

Cash used in financing activities increased approximately $7 million for the three months ended March 31, 2025 when compared to the three months ended March 31, 2024. Cash used for the three months ended March 31, 2025 included the first quarterly debt service payment on our 2024 Term Loan, fixed dividend payment, and shares withheld for payment of taxes on equity awards. Cash used for the three months ended March 31, 2024 included payments for the fixed and variable dividends and shares withheld for payment of taxes on equity awards, offset by borrowings on our credit facility.

Balance Sheet Analysis

The changes in our balance sheet from December 31, 2024 to March 31, 2025 are discussed below.



	March 31, 2025		December 31, 2024
	(in thousands)
Cash and cash equivalents	$	39,002	$	15,336
Restricted Cash	$	260	$	14,700
Accounts receivable, net	$	74,718	$	77,630
Derivative instruments assets - current and long-term	$	21,980	$	16,223

Other current assets	$	35,371	$	37,451
Property, plant & equipment, net	$	1,153,711	$	1,320,380
Deferred income taxes asset - long-term	$	68,636	$	26,779
Other noncurrent assets	$	10,660	$	9,187
Accounts payable and accrued expenses	$	131,348	$	133,809
Derivative instruments liabilities - current and long-term	$	982	$	7,703
Current portion of long-term debt, net	$	45,000	$	45,000
Income taxes payable	$	6,099	$	1,368
Long-term debt, net	$	374,478	$	384,633
Deferred income taxes liability - long-term	$	—	$	1,612
Asset retirement obligations - long-term	$	184,114	$	185,283
Other noncurrent liabilities	$	30,849	$	27,642
Stockholders’ equity	$	631,468	$	730,636

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

The $14 million decrease in restricted cash was due to the return of cash collateral for letters of credit which were replaced during the first quarter of 2025.

The $3 million decrease in accounts receivable was primarily due to decreased oil and gas sales between the two ending periods.

The $12 million increase in net derivative assets, which includes the derivative liability, is due to change in the derivative values and positions at the end of each period. 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 $2 million decrease in other current assets was primarily due to $2 million of collateral reclassified to other non-current assets and $1 million in material inventory reductions, offset by $1 million increase in prepaid expenses.

The $167 million decrease in property, plant and equipment was primarily due to $158 million in impairment, and year-to-date changes in accumulated depreciation of $38 million, offset by $28 million in capital investments.

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The $43 million increase in net deferred income taxes assets - long term, which includes the deferred tax liability, was primarily due to the tax effect of the year-to-date book loss and the utilization of credit carryforwards.

The $2 million decrease in accounts payable and accrued expenses includes an annual royalty payment of $9 million and a $4 million reclass of GHG purchase obligations to noncurrent liabilities offset by an increase of $6 million in trade payables and accrued expenses compared to year end as well as an increase of $4 million in payables for taxes, other than income taxes.

The $5 million increase in income taxes payable was primarily due to the tax effect of the year-to-date taxable income for federal and state purposes.

The $10 million decrease in long-term debt, net largely reflects the payment of $11 million on our 2024 term loan offset by $1 million in amortization of the debt issuance costs.

The $1 million decrease in the long-term portion of the asset retirement obligations from $185 million at December 31, 2024 to $184 million at March 31, 2025 was due to $4 million of liabilities settled during the period offset by $3 million of accretion expense.

The $3 million increase in other noncurrent liabilities is mainly the reclassification of GHG purchase obligations from accounts payable and accrued expenses due to the timing of when these are due.

The $99 million decrease in stockholders’ equity was due to a net loss of $97 million, $4 million of common stock dividends, and $1 million of shares withheld for payment of taxes on equity awards, offset by $3 million of stock-based compensation.

Lawsuits, Claims, Commitments, and Contingencies

Securities Litigation Matters

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Contractual Obligations

The following is a summary of our commitments and contractual obligations as of March 31, 2025:


	Payments Due
	Total		Less Than 1 Year		1-3 Years		3-5 Years		Thereafter
	(in thousands)
Debt obligations:
2024 Revolver	$	—	$	—	$	—	$	—	$	—
2024 Term Loan(1)	438,750		45,000		393,750		—		—
2024 Term Loan Interest(2)	132,336		49,210		83,126		—		—
Other:
Leases	5,420		2,184		2,947		289		—
Asset retirement obligations(3)	201,114		17,000		—		—		184,114
Off-Balance Sheet arrangements:(4)
Transportation and processing contracts(5)	76,557		12,090		21,473		17,631		25,363
GHG compliance purchase contracts(6)	21,843		21,843		—		—		—
Other purchase obligations(7)	17,100		8,400		8,700		—		—
Total contractual obligations	$	893,120	$	155,727	$	509,996	$	17,920	$	209,477

__________

(1) Represents principal repayments on the 2024 Term Loan.

(2) Represents estimated interest related to the 2024 Term Loan, assuming the same interest rate as of March 31, 2025 and expected outstanding balance throughout the term.

(3) Represents the estimated future asset retirement obligations on a discounted basis. We do not show the long-term asset retirement obligations by year as we are not able to precisely predict the timing of these amounts. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgements that are subject to revisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See “Note 1—Basis of Presentation” in the notes to consolidated financial statements in Part II—Item 8. “Financial Statements and Supplementary Data” in our Annual Report for more information.

(4) These commitments and contractual obligations are expected to be funded by our cash flow from operations.

(5) 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. Processing contracts consist of $1.6 million due over the course of the next year, with $0.3 million due in the subsequent one to three year period.

(6) We have entered into contracts to purchase GHG compliance instruments totaling $22 million.

(7) As of March 31, 2025, we have a total drilling commitment in California of $17.1 million. We are required to drill 57 wells consisting of 28 wells by December 2025 and the remaining 29 wells by December 2026.

Critical Accounting Policies and Estimates

There have been no significant changes to our critical accounting policies and estimates from those disclosed in our Annual Report. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report.

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Cautionary Note Regarding Forward-Looking Statements

The information in this Quarterly Report includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. 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,” “outlook,” “plan,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will” and similar words that reflect the prospective nature of events or outcomes. All statements other than statements of historical fact included in this Quarterly Report that address plans, activities, events, objectives, goals, strategies or developments that we expect, believe or anticipate will or may occur in the future, such as those regarding our financial position, liquidity, cash flows, 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, 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. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. 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 in Part I, Item 1A. “Risk Factors” in our Annual Report and other filings with the Securities and Exchange Commission.

Factors that could cause actual results to differ from those expressed or implied in our forward-looking statements 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, GHGs or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;

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

•inflation levels and government efforts to reduce inflation, including related interest rate determinations;

•overall domestic and global political and economic trends, geopolitical risks and general economic and industry conditions, such as inflation, high interest rates, increased volatility in financial and credit markets, global supply chain disruptions, government interventions into the financial markets and economy and volatility related to recent and upcoming elections in the United States and other major economies;

•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, the ongoing conflict in the Middle East, or a prolonged recession, among other factors;

•asset impairments from commodity price declines, regulatory changes, permitting delays or other factors;

•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;

•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;

•concerns about climate change and air quality issues;

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

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•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;

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

•competition and consolidation in the oil and gas E&P industry;

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

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

•information technology failures or cyberattacks;

•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;

•our ability to satisfy our debt obligations and comply with all covenants, agreements and conditions under our 2024 Term Loan and our 2024 Revolver;

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

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

•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;

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

•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;

•uncertainties and liabilities associated with acquired and divested assets;

•risks related to acquisitions, including the risk that we may fail to successfully integrate the assets into our operations, identify risks or liabilities associated with the acquired entity, its operations or assets, or realize any anticipated benefits or growth;

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

•geographical concentration of our operations;

•impact of derivatives legislation affecting our ability to hedge;

•failure of risk management and ineffectiveness of internal controls;

•catastrophic events, including wildfires, earthquakes, floods, and epidemics or pandemics, including the effects of related public health concerns and the impact of actions that may be taken by governmental authorities and other third parties in response to a pandemic;

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

•potential liability resulting from pending or future litigation; and

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

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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 correct or update any forward-looking statements, 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, 2025, there have been no material changes in the information required to be provided under Item 305 of Regulation S-K included in Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” in our 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 and emission allowances required by California’s cap-and-trade program 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, 2025, the fair value of our hedge positions was a net asset of approximately $21 million. A 10% increase in the oil and natural gas index prices above the March 31, 2025 prices would result in a net liability of approximately $66 million; conversely, a 10% decrease in the oil and natural gas index prices below the March 31, 2025 prices would result in a net asset of approximately $108 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. “Financial Statements” of this Quarterly Report.

At March 31, 2025, the fair value of our emission allowances required by California’s cap-and-trade program was $5 million. A 10% increase or decrease in the market price would result in a change in expense by less than $1 million.

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 Chief Executive Officer and our Vice President, Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange 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, 2025.

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 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 2025 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

There have been no material changes in the information required to be provided under Item 103 of Regulation S-K included in Part I, Item 3. “Legal Proceedings” in our Annual Report.

Other Matters

On August 5, 2024, the Company received a Notice of Violation (“NOV”) from the United States Environmental Protection Agency (“EPA”) and the Utah Department of Environmental Quality’s Division of Air Quality (“UDAQ”) alleging violations of the U.S. Clean Air Act and the Utah Air Conservation Act with respect to the standards of performance for stationary spark ignition internal combustion engines. We have engaged with the EPA and the UDAQ regarding this matter, and we are currently negotiating a Consent Agreement and Final Order to settle the matter. At this time, the Company is unable to reasonably estimate the amount of any civil penalty or the timing of the resolution of this matter, but we do not believe any civil penalty will have a material impact on our results of operations, financial position or cash flows.

For additional information regarding legal proceedings, see “Note 4—Commitments and Contingencies” in the notes to condensed consolidated financial statements in Part I, Item 1. “Financial Statements” in this Quarterly Report and “Note 5—Commitments and Contingencies” in the notes to consolidated financial statements in Part II, Item 8. “Financial Statements and Supplementary Data” in our 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 Annual Report.

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

Stock Repurchase Program

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. Purchases may be commenced or suspended at any time without notice and the share repurchase program 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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Item 5. Other Information

During the quarter ended March 31, 2025, no director or Section 16 officer adopted, modified or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (in each case, as defined in Item 408(a) of Regulation S-K).

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Item 6. Exhibits


Exhibit Number						Description
1.1						Open Market Sales Agreement, dated as of March 13, 2025 by and among Berry Corporation (bry) and Jefferies LLC and Johnson Rice & Company L.L.C., as sales agents and/or principals (incorporated by reference to Exhibit 1.1 to the Company’s Annual Report on Form 10-K filed March 13, 2025)
3.1						Second Amended and Restated Certificate of Incorporation of Berry Petroleum Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed February 19, 2020)
3.2						Fourth Amended and Restated Bylaws of Berry Corporation (bry) (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed January 31, 2023)
10.1†						Key Employee Agreement by and between Berry Corporation (bry) and Jeff Magids, effective January 21, 2025 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 22, 2025)
10.2†*						Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Restricted Stock Unit Award Agreement for Non-Employee Directors
10.3†*						Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Restricted Stock Unit Award Agreement for Executives (2025 and later)
10.4†*						Berry Corporation (bry) 2022 Omnibus Incentive Plan - Form of Performance-Based Restricted Stock Unit Award Agreement for Executives (2025 and later )
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.

(**) Furnished herewith.

(†) Indicates a management contract or compensatory plan or arrangement.

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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:

“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 unusual and infrequent items.

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

“AROs” means 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.

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

“boe/d” means boe per day.

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

“btu” 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.

“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.

“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” 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 services business segment in California.

“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.

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

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

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

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

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

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

“HSE” is an abbreviation for Health, Safety, and Environmental.

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

“EPS” is an abbreviation for earnings per share.

“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.

“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.

“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.

“Free Cash Flow” is a non-GAAP financial measure which is defined as cash flow from operations, less capital expenditures.

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

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

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

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

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

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

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

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“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.

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

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

“IOR” means improved oil recovery.

“IPO” is an abbreviation for initial public offering.

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

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

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

“mbbl/d” means mbbl per day.

“mboe” means one thousand barrels of oil equivalent.

“mboe/d” means mboe per day.

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

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

“mmboe” means one million barrels of oil equivalent.

“mmbtu” means one million btus.

“mmbtu/d” means mmbtu per day.

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

“mmcf/d” means mmcf per day.

“MW” means megawatt.

“MWHs” means megawatt hours.

“NASDAQ” means Nasdaq Global Select Market.

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

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

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“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.

“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.

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

“PPA” is an abbreviation for power purchase agreement.

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

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

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

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

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

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

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“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

“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.

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

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

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

“Relative TSR” means relative total stockholder return.

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

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“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.

“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.

“SOFR” is an abbreviation for Secured Overnight Financing Rate.

“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.

“Steamflood” means cyclic or continuous steam injection.

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

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

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

“Superfund” is a commonly known term for CERCLA.

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

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

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“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.

“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 8, 2025	/s/ Michael S. Helm
		Michael S. Helm
		Vice President, Chief Accounting Officer
		(Principal Accounting Officer)