Berry Corporation

11/05/2025 | Press release | Distributed by Public on 11/05/2025 13:21

Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2025
OR
☐ 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 October 31, 2025 77,607,094
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
5
Notes to Condensed Consolidated Financial Statements
6
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
25
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
71
Item 4.
Controls and Procedures
72
Part II - Other Information
Item 1.
Legal Proceedings
73
Item 1A.
Risk Factors
74
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities
79
Item 5.
Other Information
79
Item 6.
Exhibits
80
Glossary of Terms
81
Signatures
88
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
September 30, 2025 December 31, 2024
(in thousands, except share amounts)
Unaudited
ASSETS
Current assets:
Cash and cash equivalents $ 13,364 $ 15,336
Restricted cash
250 14,700
Accounts receivable, net of allowance for doubtful accounts of $655 at September 30, 2025 and December 31, 2024
68,565 77,630
Derivative instruments 25,687 4,526
Other current assets 35,914 37,451
Total current assets 143,780 149,643
Noncurrent assets:
Oil and natural gas properties 2,073,474 1,975,456
Accumulated depletion and amortization (979,831) (735,304)
Total oil and natural gas properties, net 1,093,643 1,240,152
Other property and equipment 173,854 171,303
Accumulated depreciation (109,901) (91,075)
Total other property and equipment, net 63,953 80,228
Deferred income taxes 57,647 26,779
Derivative instruments 18,898 11,697
Other noncurrent assets 9,077 9,187
Total assets $ 1,386,998 $ 1,517,686
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 133,214 $ 133,809
Derivative instruments - 7,703
Current portion of long-term debt, net
45,000 45,000
Income taxes payable
- 1,368
Total current liabilities 178,214 187,880
Noncurrent liabilities:
Long-term debt, net
354,469 384,633
Deferred income taxes - 1,612
Asset retirement obligations 177,585 185,283
Other noncurrent liabilities 37,748 27,642
Commitments and Contingencies - Note 4
Stockholders' equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 89,605,653 and 88,942,805 shares issued; and 77,601,842 and 76,938,994 shares outstanding, at September 30, 2025 and December 31, 2024, respectively)
90 89
Additional paid-in-capital 785,391 787,953
Treasury stock, at cost (12,003,811 shares at September 30, 2025 and December 31, 2024, respectively)
(113,768) (113,768)
(Accumulated deficit) retained earnings
(32,731) 56,362
Total stockholders' equity 638,982 730,636
Total liabilities and stockholders' equity $ 1,386,998 $ 1,517,686
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
Table of Contents
BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales
$ 128,489 $ 154,438 $ 401,988 $ 489,537
Services revenue 20,762 25,465 67,250 88,303
Electricity sales 5,314 4,410 15,167 12,344
(Losses) gains on oil and gas sales derivatives
(4,666) 75,434 57,232 (1,610)
Marketing and other revenues 1,243 1,961 2,234 8,848
Total revenues and other 151,142 261,708 543,871 597,422
Expenses and other:
Lease operating expenses 58,137 54,900 168,612 170,061
Costs of services 18,410 22,911 58,236 75,236
Electricity generation expenses 838 1,245 2,671 2,924
Transportation expenses 1,337 1,332 3,501 3,430
Marketing expenses 1,651 1,825 2,288 8,100
Acquisition and other transaction costs
3,286 971 3,596 4,982
General and administrative expenses 20,242 19,111 60,817 58,226
Depreciation, depletion, and amortization 38,514 42,749 114,200 128,423
Impairment of oil and gas properties - - 157,910 43,980
Taxes, other than income taxes 14,056 10,351 36,253 38,714
Losses (gains) on natural gas purchase derivatives
16,049 7,775 13,488 14,898
Other operating income
(2,314) (4,687) (548) (8,024)
Total expenses and other 170,206 158,483 621,024 540,950
Other expenses
Interest expense (16,430) (8,986) (47,115) (28,176)
Other, net (2) 56 211 (80)
Total other expenses (16,432) (8,930) (46,904) (28,256)
(Loss) income before income taxes
(35,496) 94,295 (124,057) 28,216
Income tax expense (benefit)
(9,479) 24,432 (34,964) 7,206
Net (loss) income
$ (26,017) $ 69,863 $ (89,093) $ 21,010
Net (loss) income per share:
Basic
$ (0.34) $ 0.91 $ (1.15) $ 0.27
Diluted
$ (0.34) $ 0.91 $ (1.15) $ 0.27
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
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BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
Nine-Month Period Ended September 30, 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
Stock-based compensation - 2,118 - - 2,118
Dividends declared on common stock, $0.12/share
- (9,233) - - (9,233)
Net loss
- - - (8,769) (8,769)
June 30, 2024 $ 89 $ 782,993 $ (113,768) $ 3,646 $ 672,960
Stock based compensation - 2,466 - - 2,466
Dividends declared on common stock, $0.14/share
- - - (13,080) (13,080)
Net income
- - - 69,863 69,863
September 30, 2024 $ 89 $ 785,459 $ (113,768) $ 60,429 $ 732,209
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BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
Nine-Month Period Ended September 30, 2025
Common Stock Additional Paid-in Capital Treasury Stock
Retained Earnings
(Accumulated Deficit)
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
Stock-based compensation - 2,197 - - 2,197
Dividends declared on common stock, $0.03/share
- (2,328) - - (2,328)
Net income
- - - 33,604 33,604
June 30, 2025 90 785,333 (113,768) (6,714) 664,941
Shares withheld for payment of taxes on equity awards and other - (3) - - (3)
Stock based compensation
- 2,397 - - 2,397
Dividends declared on common stock, $0.03/share
- (2,336) - - (2,336)
Net loss
- - - (26,017) (26,017)
September 30, 2025 $ 90 $ 785,391 $ (113,768) $ (32,731) $ 638,982
The accompanying notes are an integral part of these condensed consolidated financial statements.
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BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
2025 2024
(in thousands)
Cash flows from operating activities:
Net (loss) income
$ (89,093) $ 21,010
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization 114,200 128,423
Amortization of debt issuance costs 6,060 2,126
Impairment of oil and gas properties 157,910 43,980
Stock-based compensation expense 6,679 4,676
Deferred income taxes (32,480) 4,850
Other operating expenses
2,271 (2,135)
Derivative activities:
Total (gains) losses
(43,744) 16,508
Cash settlements received (paid) on derivatives
7,678 (38,606)
Changes in assets and liabilities:
Decrease in accounts receivable
9,097 12,414
Decrease in other assets
759 7,072
Increase (decrease) in accounts payable and accrued expenses
1,599 (48,819)
(Decrease) increase in other liabilities
(11,015) 17,360
Net cash provided by operating activities 129,921 168,859
Cash flows from investing activities:
Capital expenditures:
Capital expenditures (99,659) (85,135)
Changes in capital expenditures accruals (1,992) 1,219
Acquisitions, net of cash received - (9,188)
Proceeds from sale of property and equipment and other 520 7,455
Net cash used in investing activities (101,131) (85,649)
Cash flows from financing activities:
Repayments on 2024 term loan
(33,750) -
Borrowings under 2024 revolver
148,000 -
Repayments on 2024 revolver
(148,000) -
Borrowings under former revolving credit facility
- 502,500
Repayments on former revolving credit facility
- (506,000)
Dividends paid on common stock (8,402) (46,721)
Payment of deferred acquisition payable
- (20,000)
Shares withheld for payment of taxes on equity awards and other (1,325) (5,257)
Debt issuance cost
(1,735) (3,096)
Net cash used in financing activities (45,212) (78,574)
Net (decrease) increase in cash and cash equivalents
(16,422) 4,636
Cash, cash equivalents and restricted cash:
Beginning 30,036 4,835
Ending $ 13,614 $ 9,471
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 (70% oil). We provide our well servicing and abandonment services to third party operators in California and our California E&P operations through CJWS.
Pending Merger of Berry Corp. with California Resources Corporation
On September 14, 2025, Berry Corp. entered into an Agreement and Plan of Merger (the "Merger Agreement") by and among Berry Corp., California Resources Corporation, a Delaware corporation ("CRC"), and Dornoch Merger Sub, LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of CRC ("Merger Sub"). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Sub will merge with and into Berry Corp. (the "Merger"), with Berry Corp. surviving the Merger as a direct, wholly-owned subsidiary of CRC. Under the terms of the Merger Agreement, at the effective time of the Merger (the "Effective Time"), each share of Berry Corp. common stock issued and outstanding immediately prior to the Effective Time (other than Excluded Shares, as defined in the Merger Agreement), will be converted into, and become exchangeable for, 0.0718 (the "Exchange Ratio") shares of common stock of CRC, with cash to be paid in lieu of fractional shares (the "Merger Consideration"). The Merger Agreement also contains certain termination rights of each of Berry Corp. and CRC, and under certain circumstances, a termination fee would be payable by us. The Merger is expected to close in the first quarter of 2026, subject to shareholder and regulatory approvals and other customary closing conditions; however, no assurance can be given as to when, or if, the Merger will occur. See "Item 1A. Risk Factors" for a discussion of the risks related to the Merger and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional details relating to the Merger.
In connection with the Merger, we have incurred approximately $3 million of transaction costs recorded as "Acquisition and other transaction costs" in the consolidated statements of operations for the three and nine months ended September 30, 2025, and expect to incur additional costs prior to completion of the Merger. Transaction costs consist primarily of third party legal and professional fees.
The above description of the Merger Agreement and the transactions contemplated thereby, including certain referenced terms, is a summary of certain principal terms and conditions contained in the Merger Agreement.
6
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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.
In July 2025, the FASB issued an accounting standards update which creates a new optional practical expedient related to the estimation of future expected credit losses on accounts receivable. The rules are effective for annual periods beginning after December 15, 2025, and for interim periods within those periods and early adoption is permitted. We are studying the impact the accounting standard update will have on our results of operations, cash flows, financial condition and disclosures This guidance will be effective for the Company beginning with our 2026 interim and annual reporting periods.
Income Taxes
On July 4, 2025, the One Big Beautiful Bill Act ("OBBBA") was enacted into law in the United States. The OBBBA includes significant provisions, including favorable changes to bonus depreciation and the business interest limitation. The impact of the new legislation is expected to result in increased tax deductions and credits and reduced federal tax payments.
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 income (loss), net income (loss) per share, operating cash flows, or statement of financial position.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 2-Debt
The following table summarizes our outstanding debt:
September 30,
2025 		December 31,
2024 		Interest Rate Maturity Security
(in thousands)
2024 Revolver
$ - $ -
8.81% (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
416,250 450,000
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
(16,781) (20,367)
Current Portion of Debt (45,000) (45,000)
Long-Term Debt, net $ 354,469 $ 384,633
__________
(1) Rates at September 30, 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 September 30, 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 $3 million and $4 million, respectively. At September 30, 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 $17 million and $20 million, respectively.
For the three month periods ended September 30, 2025 and 2024, the amortization expense was approximately $2 million and $1 million, respectively. For the nine month periods ended September 30, 2025 and 2024, the amortization expense was approximately $6 million and $2 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 $409 million and $450 million at September 30, 2025 and December 31, 2024, respectively. The 2024 Revolver and 2024 Term Loan are Level 2 in the fair value hierarchy.
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, which aligned certain terms with the 2024 Revolver (defined below). The Original Term Loan Agreement, as amended to date, is referred to as 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 and 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 September 30, 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, threeor sixmonths, 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 began 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 September 30, 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 September 30, 2025, we had approximately $416 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 (as amended to date, 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 September 30, 2025, and (iii) the aggregate elected commitment amount, which was equal to $63 million as of September 30, 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. On October 30, 2025, the Company entered into a consent to postpone the periodic redetermination of the 2024 Revolver from November 2025 to February 15, 2026 (or as promptly thereafter as reasonably practicable). 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, threeor sixmonths, 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, (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 Revolver. We were in compliance with all applicable financial covenants under the 2024 Revolver as of September 30, 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 September 30, 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. Under the terms of the Merger Agreement, the Company is permitted to borrow under our 2024 Revolver in the ordinary course of business, but in no event exceeding $30 million of incremental borrowings in the aggregate outstanding at any given time.
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 at least 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 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
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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-fourcalendar 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 December 24, 2024 and (b) during the 18 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.
Other Hedge Information
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 September 30, 2025, we have no net premium assets.
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.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
As of September 30, 2025, we had the following crude oil production and gas purchase hedges.
Q4 2025
FY 2026
FY 2027
FY 2028
Brent - Crude Oil production
Swaps
Hedged volume (bbls) 1,610,000 5,382,518 3,915,500 2,045,000
Hedged volume (mbbls) per day
17.5 14.7 10.7 5.6
Weighted-average price ($/bbl) $ 74.69 $ 69.71 $ 69.27 $ 67.59
Collars
Hedged volume (bbls) 46,000 455,000 774,250 428,000
Hedged volume (mbbls) per day
0.5 1.2 2.1 1.2
Weighted-average ceiling ($/bbl)
$ 74.25 $ 73.61 $ 71.26 $ 70.48
Weighted-average floor ($/bbl)
$ 60.00 $ 60.00 $ 61.18 $ 60.00
NWPL - Natural Gas purchases(1)
Swaps
Hedged volume (mmbtu) 3,680,000 14,600,000 12,160,000 -
Hedged volume (mmbtu) per day
40.0 40.0 33.3 -
Weighted-average price ($/mmbtu) $ 4.15 $ 3.97 $ 4.18 $ -
__________
(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 October 2025, we added collars of 171 bbl/d for 2025 (calls at $69.40/bbl, puts at $60.00/bbl), 19 bbl/d for 2026 (calls at $68.75/bbl, puts at $60.00/bbl), 343 bbl/d for 2027 (calls at $69.82/bbl, puts at $60.00/bbl), and 365 bbl/d for 2028 (calls at $70.96/bbl, puts at $60.00/bbl).
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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 September 30, 2025 and December 31, 2024:
September 30, 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 $ 37,053 $ (11,366) $ 25,687
Commodity Contracts Non-current assets 36,877 (17,979) 18,898
Liabilities:
Commodity Contracts Current liabilities (11,366) 11,366 -
Commodity Contracts Non-current liabilities (17,979) 17,979 -
Total derivatives $ 44,585 $ - $ 44,585
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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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
(Losses) gains on Derivatives
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands)
Realized gains (losses) on commodity derivatives:
Realized gains (losses) on oil sales derivatives
$ 10,282 $ (2,907) $ 19,039 $ (17,390)
Realized losses on natural gas purchase derivatives
(6,200) (7,490) (15,374) (21,216)
Total realized gains (losses) on derivatives
$ 4,082 $ (10,397) $ 3,665 $ (38,606)
Unrealized (losses) gains on commodity derivatives:
Unrealized (losses) gains on oil sales derivatives
$ (14,948) $ 78,341 $ 38,193 $ 15,780
Unrealized (losses) gains on natural gas purchase derivatives
(9,849) (285) 1,886 6,318
Total unrealized (losses) gains on derivatives
$ (24,797) $ 78,056 $ 40,079 $ 22,098
Total (losses) gains on derivatives
$ (20,715) $ 67,659 $ 43,744 $ (16,508)
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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 reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances for these items at September 30, 2025 and December 31, 2024 were not material to our consolidated financial position or results of operations as of such dates. 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 September 30, 2025, we are not aware of material indemnity claims pending or threatened against us.
Securities Litigation Matters
On October 20, 2022, a shareholder derivative lawsuit (the "Assad Lawsuit") was filed in the United States District Court for the Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that alleges certain current and former Berry directors and officers breached their fiduciary duties by causing or failing to prevent Berry from making allegedly false and misleading statements between the IPO and November 3, 2020, and in the IPO offering materials, about the Company's permits and permitting processes allegedly in violation of the Securities Act of 1933 and the Exchange Act of 1934. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act.
On January 20, 2023, a second shareholder derivative lawsuit (the "Karp Lawsuit," together with the Assad Lawsuit, the "Shareholder Derivative Actions") was filed, this time in the United States District Court for the District of Delaware, by putative stockholder Molly Karp, allegedly on behalf of the Company. The Karp Lawsuit, similar to the Assad Lawsuit, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the same alleged securities violations at issue in the Assad Lawsuit. In addition, the Karp Lawsuit complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry's 2022 proxy statement was false and misleading in that it suggested the Company's internal controls were sufficient and the Board of Directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case.
In addition, on or around April 17, 2023, the Company received a stockholder litigation demand that the Board of Directors investigate and commence legal proceedings against certain current and former officers and directors based ostensibly on the same claims asserted in the Shareholder Derivative Actions. The Board of Directors appointed a Demand Review Committee for the purpose of reviewing the demand.
On September 24, 2025, all parties in the Karp Lawsuit filed a joint motion to stay the case pending the closing of the Merger, which the court granted. On October 1, 2025, all parties in the Assad Lawsuit filed a similar joint motion to stay that case, which was granted. On October 6, 2025, counsel for the Demand Review Committee notified the demanding shareholder of the court-ordered stays of the Shareholder Derivative Actions and informed the demanding shareholder that the Demand Review Committee was similarly pausing its work pending the closing of the Merger.
As of September 30, 2025, we are currently unable to estimate the probability of the outcome of these matters or the range of reasonably possible loss that may be related to these matters.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Commitments
As of September 30, 2025, we have entered into contracts to purchase GHG compliance instruments totaling $6 million which will be delivered and paid in December 2025.
Note 5-Stockholders' Equity
Cash Dividends
In March 2025, our Board of Directors declared a cash dividend of $0.03 per share, which was paid in April 2025. In May 2025, the Board of Directors declared a cash dividend of $0.03 per share, which was paid in May 2025. In August 2025, the Board of Directors approved a cash dividend of $0.03 per share, which was paid in August 2025. In November 2025, the Board of Directors approved a fixed cash dividend of $0.03 which is expected to be paid in December 2025.
Pursuant to the terms of the Merger Agreement, the Company may declare regular quarterly cash dividends, in an amount not to exceed $0.03 per share of common stock, with declaration and payment dates consistent with the Company's historical practice.
Stock Repurchase Program
Our Board of Directors has authorized a stock repurchase program; however, under the terms of the Merger Agreement, subject to certain limited exceptions, we are restricted in our ability to redeem, repurchase or otherwise acquire our common stock, including pursuant to our stock repurchase program.
As of September 30, 2025, the Company's remaining total share repurchase authority approved by the Board of Directors was $190 million. .
The Company did not repurchase any shares during the nine months ended September 30, 2025. As of September 30, 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"). 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. Pursuant to the terms of the Merger Agreement, the Company has agreed to certain customary restrictions on its ability to issue shares of its common stock, subject to certain limited exceptions, which do not permit any sales of common stock pursuant to the ATM Program while the Merger Agreement is in effect.
During the nine months ended September 30, 2025, the Company did not sell any shares of common stock under the ATM Program.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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 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.
In accordance with the terms of the Merger Agreement, at the Effective Time, each outstanding RSU that will accelerate at the Effective Time in accordance with its terms will be cancelled in exchange for a cash payment. All other RSUs will be converted into a restricted stock unit denominated in shares of CRC common stock ("CRC RSU") and will continue to be governed by the same terms and conditions (including vesting terms) as were applicable immediately prior to the Effective Time.
Any vesting conditions applicable to each outstanding PSU that will accelerate at the Effective Time in accordance with its terms will accelerate and be cancelled in exchange for a cash payment based on the greater of target performance and actual performance. All other PSUs will be converted into a CRC RSU based on the greater of target performance and actual performance, will have a time-based vesting schedule of the same length of the performance period under the applicable PSU, and will continue to be governed by the same terms and conditions as were applicable immediately prior to the Effective Time.
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:
September 30, 2025 December 31, 2024
(in thousands)
Prepaid expenses $ 8,576 $ 12,183
Materials and supplies 12,369 12,109
Deposits 4,250 8,701
Oil inventories 3,896 4,232
Tax receivable
6,598 -
Other 225 226
Total other current assets $ 35,914 $ 37,451
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Noncurrent assets
Other noncurrent assets at September 30, 2025 was approximately $9 million, which included $4 million of operating lease right-of-use assets, net of amortization, approximately $3 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:
September 30, 2025 December 31, 2024
(in thousands)
Accounts payable - trade $ 31,678 $ 18,990
Accrued expenses 51,024 53,925
Royalties payable 19,566 26,256
Greenhouse gas liability - current portion
- 8,068
Taxes other than income tax liability 10,052 6,374
Accrued interest 1,995 1,160
Asset retirement obligations - current portion 17,000 17,000
Operating lease liability 1,899 2,036
Total accounts payable and accrued expenses $ 133,214 $ 133,809
Noncurrent liabilities
The decrease of approximately $8 million in the long-term portion of the asset retirement obligations from $185 million at December 31, 2024 to $178 million at September 30, 2025 was due to $17 million of liabilities settled during the period, offset by $9 million of accretion expense.
Other noncurrent liabilities at September 30, 2025 was approximately $38 million, which included approximately $36 million of greenhouse gas liability and $2 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.
Supplemental Information on the Statement of Operations
For the three months ended September 30, 2025, other operating income was $2 million, which was related to development permit refunds and property tax refunds. For the three months ended September 30, 2024, other operating income was $5 million and mainly consisted of a gain on CJWS property sold of approximately $5 million in addition to a loss on material and equipment sales of approximately $1 million.
For the nine months ended September 30, 2025, other operating income was $1 million, which was related to development permit refunds and property tax refunds. For the nine months ended September 30, 2024, other operating income was $8 million and mainly consisted of a gain on property sold for CJWS for approximately $5 million and prior period royalty receipts and property tax refunds of approximately $2 million. The gains were offset by a loss on material inventory sales for approximately $2 million.
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BERRY CORPORATION (bry)
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:
Nine Months Ended
September 30,
2025 2024
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties $ 736 $ 3,937
Supplemental Disclosures of Cash Payments:
Interest, net of amounts capitalized $ 41,878 $ 32,825
Income taxes payments $ 5,482 $ 2,777
Note 7-Acquisitions and Divestitures
Acquisitions in 2025
In the second quarter of 2025, we executed another farm-in agreement for a 30% working interest on a horizontal well targeting the Castle Peak reservoir of the Uinta Basin, which was brought online in October 2025. Our portion of the capital expenditures for this well is expected to be approximately $3 million.
Acquisitions in 2024
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.
During the second quarter of 2024, we purchased additional working interests in our Round Mountain field for approximately $4 million.
In July 2024, we completed the sale of CJWS' storage facility in Ventura, California for approximately $8 million.
During the first three quarters of 2024, we also acquired various oil and gas properties in Kern County, California for approximately $6 million in aggregate.
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 interests, also located in Duchesne County, Utah. We received an approximate 17% working interest in three, three-mile Drilling Spacing Units (DSUs) in exchange for an approximate 75% working interest in one, two-mile DSU.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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 and nine months ended September 30, 2025, no incremental RSU and PSU shares were included in the diluted EPS calculation, as their effect was anti-dilutive under the "if converted" method. For the three and nine months ended September 30, 2024, 121,000 and 191,000 RSU or PSU shares were included in the diluted EPS calculation, respectively.
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands except per share amounts)
Basic EPS calculation
Net (loss) income
$ (26,017) $ 69,863 $ (89,093) $ 21,010
Weighted-average shares of common stock outstanding 77,602 76,939 77,466 76,712
Basic (loss) earnings per share
$ (0.34) $ 0.91 $ (1.15) $ 0.27
Diluted EPS calculation
Net (loss) income
$ (26,017) $ 69,863 $ (89,093) $ 21,010
Weighted-average shares of common stock outstanding 77,602 76,939 77,466 76,712
Dilutive effect of potentially dilutive securities(1)
- 121 - 191
Weighted-average common shares outstanding - diluted 77,602 77,060 77,466 76,903
Diluted (loss) earnings per share
$ (0.34) $ 0.91 $ (1.15) $ 0.27
__________
(1) We excluded approximately 0.2 million and 0.2 million of combined RSUs and PSUs from the dilutive weighted-average common shares outstanding for the three and nine months ended September 30, 2025, because their effect was anti-dilutive.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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 and commodity marketing activity. Revenue from CJWS is generated from well servicing and abandonment services business.
The following table provides disaggregated revenue for the three and nine months ended September 30, 2025 and 2024:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands)
Oil sales $ 124,892 $ 151,735 $ 391,765 $ 480,953
Natural gas sales 2,515 1,751 7,232 5,910
Natural gas liquids sales 1,082 952 2,991 2,674
Service revenue(1)
20,762 25,465 67,250 88,303
Electricity sales 5,314 4,410 15,167 12,344
Marketing and other revenues
1,243 1,961 2,234 8,848
Revenues from contracts with customers 155,808 186,274 486,639 599,032
(Losses) gains on oil and gas sales derivatives
(4,666) 75,434 57,232 (1,610)
Total revenues and other $ 151,142 $ 261,708 $ 543,871 $ 597,422
__________
(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $29 million and $31 million and the intercompany elimination was $8 million and $5 million for the three months ended September 30, 2025 and 2024, respectively. Prior to the intercompany elimination, service revenue was approximately $90 million and $103 million and the intercompany elimination was $22 million and $15 million for thenine months ended September 30, 2025 and 2024, respectively.
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.
In the first quarter of 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.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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.
During the first quarter of 2025, 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.
Additional impairment charges may be required in the future if oil and natural gas prices remain low or decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and natural gas properties otherwise exceeds the present value of estimated future net cash flows
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 provides services to our E&P segment, as such, we recorded an intercompany elimination in revenue and expense during consolidation for the three and nine months ended September 30, 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.
Three Months Ended
September 30, 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
$ 128,489 $ - $ 128,489 $ - $ 128,489
Service revenue
$ - $ 28,695 $ 28,695 $ (7,933) $ 20,762
Gains on oil and gas derivatives
$ (4,666) $ - $ (4,666) $ - $ (4,666)
Other revenue (1)
$ 6,557 $ - $ 6,557 $ - $ 6,557
Total revenues and other
$ 130,380 $ 28,695 $ 159,075 $ (7,933) $ 151,142
__________
(1) Other revenue generally consists of revenues related to electricity sales and marketing activities.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Three Months Ended
September 30, 2025
E&P
Well Servicing and Abandonment Services
Total Reportable Segments
Corporate/Eliminations Consolidated Company
(in thousands)
Segment Operating Revenues
$ 130,380 $ 28,695 $ 159,075 $ (7,933) $ 151,142
Less:
Lease operating expenses
58,137 - 58,137 - 58,137
Loss on natural gas purchase derivatives
16,049 - 16,049 - 16,049
Cost of services
- 26,343 26,343 (7,933) 18,410
Other operating expenses (1)
3,826 - 3,826 - 3,826
Taxes, other than income taxes
14,056 - 14,056 - 14,056
Other expenses (2)
35,019 4,310 39,329 20,399 59,728
Interest expense and other, net
- - - 16,432 16,432
Segment profit (loss)
3,293 (1,958) 1,335
Income before income taxes
(35,496)
Capital expenditures
$ 16,161 $ 508 $ 16,669 $ 352 $ 17,021
Total assets
$ 1,380,803 $ 41,874 $ 1,422,677 $ (35,679) $ 1,386,998
__________
(1) Amounts for our E&P segment include electricity, transportation, and marketing costs.
(2) Includes depreciation, depletion, and amortization expenses of approximately $36 million and $2 million for our E&P and Well Servicing and Abandonment Services segments. Also includes corporate depreciation, depletion, and amortization expenses of approximately $1 million. Other expenses for each reportable segment and corporate also primarily include general and administrative expenses, acquisition and other transaction costs, and other operating income (expenses).
Three Months Ended
September 30, 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
$ 154,438 $ - $ 154,438 $ - $ 154,438
Service revenue
$ - $ 30,836 $ 30,836 $ (5,371) $ 25,465
Losses on oil and gas derivatives
$ 75,434 $ - $ 75,434 $ - $ 75,434
Other revenue (1)
$ 6,371 $ - $ 6,371 $ - $ 6,371
Total revenues and other
$ 236,243 $ 30,836 $ 267,079 $ (5,371) $ 261,708
__________
(1) Other revenue generally consists of revenues related to electricity sales and marketing activities.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Three Months Ended
September 30, 2024
E&P
Well Servicing and Abandonment Services
Total Reportable Segments
Corporate/Eliminations Consolidated Company
(in thousands)
Segment Operating Revenues
$ 236,243 $ 30,836 $ 267,079 $ (5,371) $ 261,708
Less:
Lease operating expenses
54,900 - 54,900 - 54,900
Losses on natural gas purchase derivatives
7,775 - 7,775 - 7,775
Cost of services
- 28,282 28,282 (5,371) 22,911
Other operating expenses (1)
4,402 - 4,402 - 4,402
Taxes, other than income taxes
10,351 - 10,351 - 10,351
Other expenses (2)
40,544 (177) 40,367 17,777 58,144
Interest expense and other, net
- - - 8,930 8,930
Segment profit
118,271 2,731 121,002
Loss before income taxes
94,295
Capital expenditures
$ 24,793 $ 498 $ 25,291 $ 583 $ 25,874
Total assets
$ 1,545,517 $ 56,528 $ 1,602,045 $ (84,897) $ 1,517,148
__________
(1) Amounts for our E&P segment include electricity, transportation, and marketing costs.
(2) Includes depreciation, depletion, and amortization expenses of approximately $39 million and $3 million for our E&P and Well Servicing and Abandonment Services segments. Also includes corporate depreciation, depletion, and amortization expenses of approximately $1 million.Other expenses for each reportable segment and corporate also primarily include general and administrative expenses, acquisition and other transaction costs, and other operating income (expenses).
Nine Months Ended
September 30, 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
$ 401,988 $ - $ 401,988 $ - $ 401,988
Service revenue
- 89,524 89,524 (22,274) 67,250
Gains on oil and gas derivatives
57,232 - 57,232 - 57,232
Other revenue (1)
17,401 - 17,401 - 17,401
Total revenues and other
$ 476,621 $ 89,524 $ 566,145 $ (22,274) $ 543,871
__________
(1) Other revenue generally consists of revenues related to electricity sales and marketing activities.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Nine Months Ended
September 30, 2025
E&P
Well Servicing and Abandonment Services
Total Reportable Segments
Corporate/Eliminations Consolidated Company
(in thousands)
Segment Operating Revenues
$ 476,621 $ 89,524 $ 566,145 $ (22,274) $ 543,871
Less:
Lease operating expenses
168,612 - 168,612 - 168,612
Losses gains on natural gas purchase derivatives
13,488 - 13,488 - 13,488
Cost of services
- 80,510 80,510 (22,274) 58,236
Other operating expenses (1)
8,460 - 8,460 - 8,460
Taxes, other than income taxes
36,253 - 36,253 - 36,253
Other expenses (2)
266,931 12,979 279,910 56,065 335,975
Interest expense and other, net
- - - 46,904 46,904
Segment loss
(17,123) (3,965) (21,088)
Loss before income taxes
$ (124,057)
Capital expenditures $ 97,129 $ 897 $ 98,026 $ 1,633 $ 99,659
Total assets $ 1,380,803 $ 41,874 $ 1,422,677 $ (35,679) $ 1,386,998
__________
(1) Amounts for our E&P segment include electricity, transportation, and marketing costs.
(2) Includes depreciation, depletion, and amortization expenses of approximately $107 million and $5 million for our E&P and Well Servicing and Abandonment Services segments. Also includes corporate depreciation, depletion, and amortization expenses of approximately $1 million. Our E&P segment recorded a pretax impairment charge of $158 million in the first quarter of 2025. Other expenses for each reportable segment and corporate also primarily include general and administrative expenses, acquisition and other transaction costs, and other operating income (expenses).
Nine Months Ended
September 30, 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
$ 489,537 $ - $ 489,537 $ - $ 489,537
Service revenue
- 102,984 102,984 (14,681) 88,303
(Losses) on oil and gas derivatives
(1,610) - (1,610) - (1,610)
Other revenue (1)
21,192 - 21,192 - 21,192
Total revenues and other
$ 509,119 $ 102,984 $ 612,103 $ (14,681) $ 597,422
__________
(1) Other revenue generally consists of revenues related to electricity sales and marketing activities.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Nine Months Ended
September 30, 2024
E&P
Well Servicing and Abandonment Services
Total Reportable Segments
Corporate/Eliminations Consolidated Company
(in thousands)
Segment Operating Revenues
$ 509,119 $ 102,984 $ 612,103 $ (14,681) $ 597,422
Less:
Lease operating expenses
170,061 - 170,061 - $ 170,061
Losses on natural gas purchase derivatives
14,898 - 14,898 - $ 14,898
Cost of services
- 89,917 89,917 (14,681) $ 75,236
Other operating expenses (1)
14,454 - 14,454 - $ 14,454
Taxes, other than income taxes
38,714 - 38,714 - $ 38,714
Other expenses (2)
163,697 10,460 174,157 53,430 $ 227,587
Interest expense and other, net
- - - 28,256 $ 28,256
Segment loss
107,295 2,607 109,902
Loss before income taxes
$ 28,216
Capital expenditures $ 81,945 $ 2,298 $ 84,243 $ 892 $ 85,135
Total assets $ 1,545,517 $ 56,528 $ 1,602,045 $ (84,897) $ 1,517,148
__________
(1) Amounts for our E&P segment include electricity, transportation, and marketing costs.
(2) Includes depreciation, depletion, and amortization expenses of approximately $118 million and $8 million for our E&P and Well Servicing and Abandonment Services segments. Also includes corporate depreciation, depletion, and amortization expenses of approximately $2 million. Our E&P segment recorded a pretax impairment charge of $44 million in the second quarter of 2024. Other expenses for each reportable segment and corporate also primarily include general and administrative expenses, acquisition and other transaction 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
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 (70% oil). We provide our well servicing and abandonment services to third party operators in California and our California E&P operations through C&J Well Services (CJWS).
Pending Merger with California Resources Corporation
On September 14, 2025, Berry Corp. entered into an Agreement and Plan of Merger (the "Merger Agreement") by and among the Berry Corp., California Resources Corporation, a Delaware corporation ("CRC"), and Dornoch Merger Sub, LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of CRC ("Merger Sub"). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Sub will merge with and into Berry Corp. (the "Merger"), with Berry Corp. surviving the Merger as a direct, wholly-owned subsidiary of CRC. Under the terms of the Merger Agreement, at the effective time of the Merger (the "Effective Time"), each share of Berry Corp. common stock issued and outstanding immediately prior to the Effective Time (other than Excluded Shares, as defined in the Merger Agreement), will be converted into, and become exchangeable for, 0.0718 (the "Exchange Ratio") shares of common stock of CRC, with cash to be paid in lieu of fractional shares (the "Merger Consideration"). The Merger Agreement also contains certain termination rights of each of Berry Corp. and CRC, and under certain circumstances, a termination fee would be payable by us. The Merger is expected to close in the first quarter of 2026, subject to shareholder and regulatory approvals and other customary closing conditions; however, no assurance can be given as to when, or if, the Merger will occur. See "Item 1A. Risk Factors" for a discussion of the risks related to the Merger and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional details relating to the Merger.
In connection with the Merger, we have incurred approximately $3 million of transaction costs recorded as "Acquisition and other transaction costs" in the consolidated statements of operations for the three and nine months ended September 30, 2025, and expect to incur additional costs prior to completion of the Merger. Transaction costs consist primarily of third party legal and professional fees.
If the Merger is consummated, Berry Corp.'s common stock will be delisted from NASDAQ and deregistered under the Exchange Act, and Berry Corp. will cease to be a publicly traded company.
Additionally, the Merger Agreement imposes restrictions on our business and operations during the pendency of the Merger. While we do not believe those restrictions are unduly burdensome, they may delay or prevent us from taking actions we could otherwise take. Accordingly, our results of operations from before the Merger Agreement may not be comparable to results of operations since we entered into the Merger Agreement. See Note 1 to the consolidated financial statements for additional information on the Merger and "Part II, Item 1A. Risk Factors" for a discussion of risks related to the Merger.
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Our Operations
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 targets our thermal diatomite assets. During the first three quarters of 2025, we drilled and completed 31 wells in California, 27 of which were thermal diatomite sidetracks. We incurred the substantial majority of our annual California capital expenditures by the end of the third quarter. Due to the nature of the reservoir, completing the thermal diatomite sidetrack wells required planned downtime of nearby wells. Extended downtime in a portion of the thermal diatomite occurred during the third quarter due to a steam-to-surface event at one well; however, we began bringing these wells back online late in the third quarter and finished in the fourth quarter.
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 September 30, 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 few years, the Uinta Basin has experienced an increase in activity by new and existing operators, driven by acquisition and divestiture activity and 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. In the second quarter of 2025, we executed another farm-in agreement for a 30% working interest on a horizontal well targeting the Castle Peak reservoir of the Uinta Basin, which was brought online in October 2025.
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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. These wells were drilled in the first half of 2025 and we finished the completion activity for these wells in the second and third quarters of 2025. We began flowback on these four wells in August 2025 and the initial production rates are in-line with our expectations. This activity marks the development of our first operated horizontal pad on our Uinta Basin acreage, and the results will inform our plans for further horizontal development across our acreage in Utah. Similar to our 2025 capital program in California, we incurred the majority of our 2025 capital expenditures for our Utah program 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 growth opportunities 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 is 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 slightly higher for the third quarter of 2025 compared to the second quarter of 2025. Increased geopolitical risk largely balanced downward pricing pressure from OPEC+ announcements to increase production in the third quarter. Natural gas prices for the third quarter of 2025 increased slightly relative to the 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+. OPEC+ has, since 2022, implemented a series of groupwide and voluntary production cuts to address market imbalances. Combined reductions reached a peak of roughly 5.85 mmbbl/d. Beginning in the second quarter of 2025, members of OPEC+ started to phase out portions of the voluntary production cuts, though remaining production cuts are expected to extend into 2026, subject to market condition.
In addition, President Trump has issued numerous executive orders aimed at increasing oil production and decreasing commodity prices, among other matters, and has in the past 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. 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 price 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. Further impairment charges may be required in the future if oil and natural gas prices remain low or decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and natural gas properties otherwise exceeds the present value of estimated future net cash flows.
Oil and natural gas prices could fluctuate further with any changes in demand due to, among other things, the ongoing conflicts in Ukraine and 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, 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.
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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
September 30, 2025 June 30, 2025
September 30, 2024
Average Price
Realization(1)
Average Price
Realization(1)
Average Price
Realization(1)
Sales of Crude Oil (per bbl):
Brent
$ 68.17 $ 66.71 $ 78.71
Realized price without derivative settlements
$ 62.21 91% $ 61.26 92% $ 72.40 92%
Effects of derivative settlements
5.12 6.28 (1.39)
Realized price with derivative settlements
$ 67.33 99% $ 67.54 101% $ 71.01 90%
WTI
$ 64.94 $ 63.92 $ 75.26
Realized price without derivative settlements $ 62.21 96% $ 61.26 96% $ 72.40 96%
Purchased Natural Gas (per mmbtu)
Average Monthly Settled Price - NWPL
$ 2.60 $ 2.18 $ 1.92
Realized price without derivative settlements $ 3.17 122% $ 2.80 128% $ 2.72 142%
Effects of derivative settlements 1.49 1.89 1.64
Realized price with derivative settlements $ 4.66 179% $ 4.69 215% $ 4.36 227%
__________
(1) Represents the percentage of our realized prices compared to the indicated index.
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Nine Months Ended
September 30, 2025 September 30, 2024
Average Price
Realization(1)
Average Price
Realization(1)
Sales of Crude Oil (per bbl):
Brent
$ 69.91 $ 81.82
Realized price without derivative settlements
$ 64.37 92% $ 75.31 92%
Effects of derivative settlements
3.79 (2.71)
Realized price with derivative settlements
$ 68.16 97% $ 72.60 89%
WTI
$ 66.76 $ 77.62
Realized price without derivative settlements $ 64.37 96% $ 75.31 97%
Purchased Natural Gas (per mmbtu)
Average Monthly Settled Price - NWPL
$ 2.88 $ 2.24
Realized price without derivative settlements $ 3.45 120% $ 3.04 136%
Effects of derivative settlements 1.24 1.53
Realized price with derivative settlements $ 4.69 163% $ 4.57 204%
__________
(1) Represents the percentage of our realized prices compared to the indicated index.
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 third quarter of 2025, average oil prices were slightly higher than the second quarter of 2025, remaining below levels where they were seen in the first quarter of 2025 and the fourth quarter of 2024. Interim price volatility during the third quarter of 2025 was largely driven by the gradual unwinding of OPEC+ cuts and geopolitical events.
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. Further, the California Energy Commission issued policy recommendations in June 2025 to expand oil storage requirements and provide more regulatory flexibility designed to reduce uncertainty and volatility for the oil and gas industry. We currently do not expect that the announced refinery closures will negatively impact our price realizations; however, additional refinery closures could have an adverse impact on our ability to market our crude production in California. The Southern California refinery fire in October 2025 has had no impact on the marketing of our products.
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. A major loading terminal in Utah is also expected to more than double its processing capacity by spring 2026, enhancing takeaway capacity and market access. 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 September 30, 2025, June 30, 2025, and September 30, 2024, Utah had an average realized oil price
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of$50.50, $49.08 and $60.35, respectively, compared to an average Brent oil price of $68.17, $66.71 and $78.71 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 $2.81 per mmbtu and as low as $2.33 per mmbtu in the third quarter of 2025. The price from the SoCal Gas city-gate index was as high as $4.21 per mmbtu and as low as $3.41 per mmbtu in the third quarter of 2025. Overall, on an unhedged basis, we paid an average of $3.17 per mmbtu in the third quarter of 2025 for our gas purchases which includes transportation costs. When including the hedging effects in our gas purchases, we paid $4.66, $4.69 and $4.36 per mmbtu in the third quarter of 2025, the second quarter of 2025, and the third 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 third quarter of 2025, natural gas sales from our Utah operations had an average realized gas price of $2.99, compared to an average Northwest, Rocky Mountains gas price of $2.60, which was a 115% realization. In the three months ended June 30, 2025 and September 30, 2024, Utah had an average realized gas price of $2.30, and $2.01, compared to an average Northwest, Rocky Mountains gas price of $2.18, or 106% realization, and $1.92, or 105% realization, respectively.
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 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 2,000 mmbtu/d in each of the third quarter of 2025, the second quarter of 2025 and the third 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 third quarter of 2025 compared to the second quarter of 2025. 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.
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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 permits to support sidetrack drilling and workover activity into 2026. On June 26, 2025, Kern County approved revisions to its oil and gas permitting ordinance and certified a Second Supplemental Recirculated Environmental Impact Report (SSREIR) which could allow for approximately 2,700 new oil wells to be permitted each year. In September 2025, Senate Bill 237 (SB 237) was signed and once in effect will implement a number of changes to help facilitate new and continued oil and gas production in California (particularly in Kern County). Among other provisions, SB 237 deems the SSREIR sufficient for full compliance with the requirements of the California Environmental Quality Act (CEQA) for purposes of a certain Kern County zoning ordinances related to oil and gas activities and requires no further environmental review. These provisions of SB 237 apply prospectively and, in certain circumstances, retroactively and become effective as of January 1, 2026. We expect Kern County and CalGEM to begin issuing significantly more well permits in Kern County from the beginning of 2026 for up to the next ten years.
We believe that this legislation provides greater regulatory certainty for oil and gas operations in Kern County, which accounts for a substantial portion of California's crude oil and natural gas production. The adoption of SB 237 is particularly important to our business as all of our assets in California are located in Kern County. SB 237's facilitation of the timely resumption of permitting activity will likely support operational continuity and investment planning by California's oil and gas industry. In addition, we believe that the increased clarity around permitting standards will help to enhance long-term development opportunities in Kern County, benefiting both the broader industry and our California asset base.
In addition, Assembly Bill 1207 (AB 1207) was enacted in September 2025 and extends California's GHG Cap-and-Invest program through 2045 and modifies key program parameters, including offset eligibility and the allocation of free allowances. The legislation establishes a Climate Mitigation Fund to support consumer rebates and investments to reduce household energy costs. AB 1207 also establishes emissions reduction initiatives and enhances program transparency through expanded reporting requirements for the California Air Resources Board. While AB 1207 provides long-term certainty, it may increase compliance costs associated with carbon pricing and limit the availability of lower cost offset options for regulated entities. For additional information regarding well permitting with respect to our California operations, see Part I, Item 1 "Regulatory Matters" in our Annual Report.
Executive Orders Relating to Energy Production
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
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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.
Income Taxes
On July 4, 2025, the One Big Beautiful Bill Act ("OBBBA") was enacted into law in the United States. The OBBBA includes significant provisions, including favorable changes to bonus depreciation and the business interest limitation. The impact of the new legislation is expected to result in increased tax deductions and credits and reduced federal tax payments.
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 three quarters of 2025, inflation rates continued to stabilize and decrease following a trend of increasing inflation that began in the middle of 2023. We are unable to predict if such inflationary pressures and contributing factors will continue through the remainder of 2025. We have not experienced a material change to our cost structure due to inflation thus far in 2025. We will continue to monitor cost trends that could have an impact on our capital expenditures and operating costs next year and beyond.
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Our Capital Program
For the three and nine months ended September 30, 2025, our total capital expenditures were approximately $17 million and $100 million, respectively, including capitalized overhead and interest and excluding acquisitions and asset retirement spending. E&P and corporate expenditures were approximately $17 million and $99 million for the three and nine months ended September 30, 2025 (which excludes well servicing and abandonment services capital of less than $1 million in each period). The capital expenditures for the nine months ended September 30, 2025 were generally split equally between our California and Utah operations. During the first nine months of 2025, we drilled 31 wells in California and four horizontal wells in Utah. In the second quarter of 2025, we executed on a majority of the completion activity for the four horizontal wells in Utah, which were 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.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 $22 million to $26 million on plugging and abandonment activities, a significant portion of which is planned to meet our annual requirements under California's idle well regulations. During the third quarter of 2025, we incurred plugging and abandonment costs of approximately $6 million related to a steam-to-surface event in the thermal diatomite, and we expect to recover a majority of such costs from an outstanding insurance claim. The full year spending estimate does not include the net impact of the estimated insurance recoupment. We spent approximately $7 million and $20 million for plugging and abandonment activities in the three and nine months ended September 30, 2025, respectively.
For information about the potential risks related to our capital program, see Part I, Item IA. "Risk Factors" in our Annual Report and Part II, Item 1A. "Risk Factors" in this Quarterly Report.
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Production and Prices
The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.
Three Months Ended
September 30, 2025 June 30, 2025 September 30, 2024
Average daily production:(1)
Oil (mbbl/d) 21.8 22.0 22.8
Natural Gas (mmcf/d) 9.1 9.1 9.5
NGL (mbbl/d) 0.6 0.4 0.4
Total (mboe/d)(2)
23.9 23.9 24.8
Total Production:
Oil (mbbl) 2,008 2,006 2,096
Natural gas (mmcf) 840 827 872
NGLs (mbbl) 52 33 40
Total (mboe)(2)
2,200 2,177 2,281
Weighted-average realized sales prices:
Oil without hedges ($/bbl) $ 62.21 $ 61.26 $ 72.40
Effects of scheduled derivative settlements ($/bbl) $ 5.12 $ 6.28 $ (1.39)
Oil with hedges ($/bbl) $ 67.33 $ 67.54 $ 71.01
Natural gas ($/mcf) $ 2.99 $ 2.30 $ 2.01
NGL ($/bbl) $ 20.69 $ 26.04 $ 24.01
Average Benchmark prices:
Oil (bbl) - Brent $ 68.17 $ 66.71 $ 78.71
Oil (bbl) - WTI $ 64.94 $ 63.92 $ 75.26
Natural gas (mmbtu) - SoCal Gas city-gate(3)
$ 3.78 $ 3.11 $ 2.68
Natural gas (mmbtu) - Northwest, Rocky Mountains(4)
$ 2.60 $ 2.18 $ 1.92
Natural gas (mmbtu) - Henry Hub(4)
$ 3.03 $ 3.19 $ 2.11
__________
(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 September 30, 2025, the average prices of Brent oil and Henry Hub natural gas were $68.17 per bbl and $3.03 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
September 30, 2025 June 30, 2025 September 30, 2024
Average daily production (mboe/d):(1)
California 18.4 19.7 20.1
Utah
5.5 4.2 4.7
Total average daily production 23.9 23.9 24.8
__________
(1) Production represents volumes sold during the period.
Our average daily production was 23.9 mboe/d for the three months ended September 30, 2025 and June 30, 2025. Our California production was 18.4 mboe/d for the three months ended September 30, 2025, which was 7% or 1.3 mboe/d lower than the three months ended June 30, 2025. The decrease was mostly due to steam reduction in response to the steam-to-surface event at one well resulting in unplanned downtime and delay to start up of development. September production recovered due to the successful resumption of steam injection after the steam-to-surface event was resolved and the new sidetrack wells drilled in the thermal diatomite were brought online. Our Utah production was 5.5 mboe/d for the three months ended September 30, 2025, 31% or 1.3 mboe/d higher than the three months ended June 30, 2025, due to the start-up of the four horizontal wells drilled and completed during the second and third quarters of 2025.
Our average daily production decreased 4% or 0.9 mboe/d for the three months ended September 30, 2025, compared to the three months ended September 30, 2024. California average daily production was 18.4 mboe/d for the third quarter of 2025, 1.7 mboe/d lower than the same period during 2024, due to natural decline and the temporary impact of the events from the third quarter of 2025 that are discussed above. These decreases were partially offset by increased production due to development activity in the Midway Sunset field. Utah average daily production for the three months ended September 30, 2025 increased 17% or 0.8 mboe/d to 5.5 mboe/d compared to the same period in 2024, due to the new horizontal wells coming online.
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The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.
Nine Months Ended
September 30, 2025 September 30, 2024
Average daily production:(1)
Oil (mbbl/d) 22.3 23.3
Natural Gas (mmcf/d) 8.7 8.8
NGL (mbbl/d) 0.4 0.4
Total (mboe/d)(2)
24.2 25.2
Total Production:
Oil (mbbl) 6,086 6,386
Natural gas (mmcf) 2,380 2,404
NGLs (mbbl) 119 104
Total (mboe)(2)
6,602 6,891
Weighted-average realized sales prices:
Oil without hedges ($/bbl) $ 64.37 $ 75.31
Effects of scheduled derivative settlements ($/bbl) $ 3.79 $ (2.71)
Oil with hedges ($/bbl) $ 68.16 $ 72.60
Natural gas ($/mcf) $ 3.04 $ 2.46
NGL ($/bbl) $ 25.00 $ 25.70
Average Benchmark prices:
Oil (bbl) - Brent $ 69.91 $ 81.82
Oil (bbl) - WTI $ 66.76 $ 77.62
Natural gas (mmbtu) - SoCal Gas city-gate(3)
$ 3.79 $ 2.91
Natural gas (mmbtu) - Northwest, Rocky Mountains(4)
$ 2.88 $ 2.24
Natural gas (mmbtu) - Henry Hub(4)
$ 3.45 $ 2.11
__________
(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, during the nine months ended September 30, 2025, the average prices of Brent oil and Henry Hub natural gas were $69.91 per bbl and $3.45 per mmbtu respectively.
(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) Northwest, Rocky Mountains and Henry Hub are the relevant indices used for gas purchases and sales, respectively, in the Rockies.
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The following table sets forth average daily production by operating area for the periods indicated:
Nine Months Ended
September 30, 2025 September 30, 2024
Average daily production (mboe/d):(1)
California 19.5 20.8
Utah
4.7 4.4
Total average daily production 24.2 25.2
__________
(1) Production represents volumes sold during the period.
Average daily production for the nine months ended September 30, 2025, decreased 4% or 1.0 mboe/d to 24.2 mboe/d compared to the same period in 2024. California production declined 6% or 1.3 mboe/d to 19.5 mboe/d due to natural decline and the temporary impact of the events from the third quarter of 2025 that are discussed above, partially offset by increased production from development activity in the Midway Sunset field. Utah average daily production for the nine months ended September 30, 2025, increased 7% or 0.3 mboe/d compared to the same period in 2024 due to new production from both our non-operated and operated horizontal wells.
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Results of Operations
Three Months Ended September 30, 2025 compared to Three Months Ended June 30, 2025.
Three Months Ended
September 30, 2025 June 30, 2025 $ Change % Change
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales $ 128,489 $ 125,637 $ 2,852 2 %
Service revenue(1)
20,762 22,824 (2,062) (9) %
Electricity sales 5,314 4,886 428 9 %
(Losses) gains on oil and gas sales derivatives
(4,666) 56,423 (61,089) n/a
Marketing and other revenues 1,243 308 935 >100%
Total revenues and other $ 151,142 $ 210,078 $ (58,936) (28) %
__________
(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $29 million and $31 million and the intercompany elimination was $8 million for the quarters ended September 30, 2025 and June 30, 2025, respectively.
Revenues and Other
Oil, natural gas and NGL sales increased by $3 million, or 2%, to approximately $128 million for the three months ended September 30, 2025, compared to the three months ended June 30, 2025. The increase included $2 million from higher oil prices and $1 million from higher gas prices.
Service revenue consisted entirely of revenue from the well servicing and abandonment services business, excluding intercompany amounts. Service revenue decreased by $2 million, or 9%, to $21 million for the three months ended September 30, 2025, compared to the three months ended June 30, 2025 due to decreased activity.
Electricity sales represent sales to utilities and were flat at $5 million for the three months ended September 30, 2025, compared to the three months ended June 30, 2025.
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 September 30, 2025 and June 30, 2025 were $10 million and $9 million, respectively. The quarter-over-quarter increase in settlement gains was primarily due to lower settlement prices relative to fixed prices in the second quarter 2025. The mark-to-market non-cash loss for the three months ended September 30, 2025 was $15 million compared to a gain of $48 million for three months ended June 30, 2025. 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 included third-party marketing activities, were $1 million for the three months ended September 30, 2025, due to higher activity when compared to the three months ended June 30, 2025.
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Three Months Ended
$ Change % Change
September 30, 2025 June 30, 2025
(in thousands)
Expenses and other:
Lease operating expenses $ 58,137 $ 53,193 $ 4,944 9 %
Costs of services(1)
18,410 19,001 (591) (3) %
Electricity generation expenses 838 624 214 34 %
Transportation expenses 1,337 1,225 112 9 %
Marketing expenses 1,651 345 1,306 >100%
Acquisition and other transaction costs(2)
3,286 310 2,976 >100%
General and administrative expenses 20,242 20,270 (28) - %
Depreciation, depletion and amortization 38,514 35,294 3,220 9 %
Taxes, other than income taxes 14,056 12,957 1,099 8 %
Losses on natural gas purchase derivatives
16,049 3,130 12,919 >100%
Other operating (income) expense
(2,314) 1,365 (3,679) >100%
Total expenses and other 170,206 147,714 22,492 15 %
Other expenses:
Interest expense (16,430) (15,513) (917) 6 %
Other, net (2) (59) 57 (97) %
Total other expenses (16,432) (15,572) (860) 6 %
(Loss) income before income taxes
(35,496) 46,792 (82,288) >100%
Income tax (benefit) expense
(9,479) 13,188 (22,667) >100%
Net (loss) income
$ (26,017) $ 33,604 $ (59,621) >100%
Adjusted EBITDA(3)
$ 49,404 $ 52,915 $ (3,511) (7) %
Adjusted Net Income (Loss)(3)
$ (5,867) $ (364) $ (5,503) >100%
__________
(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, costs of services were $26 million for three months ended September 30, 2025 and $27 million for three months ended June 30, 2025. The intercompany elimination was $8 million for both the three months ended September 30, 2025 and June 30, 2025.
(2) Includes legal and other professional expenses related to various transaction 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, increased 9% or $5 million to $58 million in the third quarter of 2025 when compared to the second quarter of 2025. Lease operation expense excluding fuel increased $3 million due to higher outside services from increased activities and higher power from summer rates. A majority of these higher costs in the third quarter of 2025 was a result of the steam-to-surface event at one well at Mid-North Diatomite. Natural gas (fuel) costs for our California steam generation facilities increased $2 million, primarily due to an increase in prices.
Costs of services consisted entirely of costs from the well servicing and abandonment services business, excluding intercompany amounts. Cost of services decreased $1 million, or 3%, to $18 million in the third quarter of 2025 due to decreased activity.
Electricity generation expenses were flat in the three months ended September 30, 2025 compared to the three months ended June 30, 2025.
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Natural gas purchase derivatives for the three months ended September 30, 2025, resulted in a loss of $16 million that included $6 million settlement losses and $10 million mark-to-market valuation losses. Natural gas derivatives in the second quarter of 2025 resulted in a $3 million loss that included $8 million settlement losses and $5 million mark-to-market valuation gains. Quarter-over-quarter settlement losses decreased due to higher average settlement prices in the third quarter compared to those in the second quarter.
Transportation expenses were comparable for the periods presented.
Acquisition and other transaction costs were $3 million for the three months ended September 30, 2025 compared to less than $1 million for the three months ended June 30, 2025 and include legal and professional expenses related to various transaction activities, and in 2025 were mostly related to the Merger discussed elsewhere.
General and administrative expenses were flat at $20 million for the three months ended September 30, 2025 and three months ended June 30, 2025. 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, were flat for the three months ended September 30, 2025, compared to the three months ended June 30, 2025. 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 increased $3 million for the three months ended September 30, 2025, compared to the three months ended June 30, 2025 primarily due to an increase in the depletion rate.
Taxes, Other Than Income Taxes
Three Months Ended $ Change % Change
September 30, 2025 June 30, 2025
(per boe)
Severance taxes $ 1.58 $ 1.93 $ (0.35) (18) %
Ad valorem and property taxes 2.03 2.04 (0.01) - %
Greenhouse gas allowances and other emission costs 2.78 1.98 0.80 40 %
Total taxes other than income taxes $ 6.39 $ 5.95 $ 0.44 7 %
Taxes, other than income taxes, increased in the three months ended September 30, 2025 by $0.44 per boe, or 7%, to $6.39. The increase included higher greenhouse gas mark-to-market prices compared to the second quarter of 2025, partially offset by lower severance taxes.
Other Operating (Income) Expenses
Other operating income was $2 million for the three months ended September 30, 2025, which was related to development permit refunds and property tax refunds. In three months ended June 30, 2025, other operating expense was $1 million.
Interest Expense
Interest expense increased $1 million or 6% for the three months ended September 30, 2025, compared to the three months ended June 30, 2025 due to increased borrowing activity on the revolver.
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Income Taxes
Our effective tax rate was 27% for the three months ended September 30, 2025, which is comparable to 28% for the quarter ended June 30, 2025.
Three Months Ended September 30, 2025 compared to Three Months Ended September 30, 2024.
Three Months Ended
September 30, 		$ Change % Change
2025 2024
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales $ 128,489 $ 154,438 $ (25,949) (17) %
Service revenue(1)
20,762 25,465 (4,703) (18) %
Electricity sales 5,314 4,410 904 20 %
(Losses) gains on oil and gas sales derivatives
(4,666) 75,434 (80,100) n/a
Marketing and other revenues 1,243 1,961 (718) (37) %
Total revenues and other $ 151,142 $ 261,708 $ (110,566) (42) %
__________
(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $29 million and $31 million and the intercompany elimination was $8 million and $5 million for the quarters ended September 30, 2025 and 2024, respectively.
Revenues and Other
Oil, natural gas and NGL sales decreased $26 million, or 17%, to approximately $128 million for the three months ended September 30, 2025, when compared to the three months ended September 30, 2024. The decrease in revenue was driven by $20 million lower oil prices and $6 million lower oil volumes, partially offset by a $1 million increase in gas price. The lower oil volumes included temporary downtime related to the steam-to-surface event at one well in the third quarter of 2025.
Service revenue (excluding intercompany amounts) decreased by $5 million, or 18%, to $21 million for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, due to decreased activity and rates in the third quarter of 2025.
Electricity sales represent sales to utilities and were $1 million higher at $5 million for the three months ended September 30, 2025, primarily due to higher resource adequacy payments received when compared to the three months ended September 30, 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 September 30, 2025 were $10 million compared to losses of $3 million for the three months ended September 30, 2024. Settlement gains in the third quarter of 2025 were driven by higher average fixed prices relative to average settlement prices. Notional volumes were 18 mbbl/d in the third quarter of 2025 and 15 mbbl/d in the third quarter of 2024. The mark-to-market non-cash loss for the three months ended September 30, 2025 was $15 million compared to a gain of $78 million for the three months ended September 30, 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 include third-party gas marketing and processing revenue as well as revenue from gas we purchased in the Rockies and sold into the California market, decreased less than $1 million in the three months ended September 30, 2025 due to less gas marketing activity.
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Three Months Ended
September 30, 		$ Change % Change
2025 2024
(in thousands)
Expenses and other:
Lease operating expenses $ 58,137 $ 54,900 $ 3,237 6 %
Costs of services(1)
18,410 22,911 (4,501) (20) %
Electricity generation expenses 838 1,245 (407) (33) %
Transportation expenses 1,337 1,332 5 - %
Marketing expenses 1,651 1,825 (174) (10) %
Acquisition and other transaction costs(2)
3,286 971 2,315 >100%
General and administrative expenses 20,242 19,111 1,131 6 %
Depreciation, depletion and amortization 38,514 42,749 (4,235) (10) %
Taxes, other than income taxes 14,056 10,351 3,705 36 %
Losses on natural gas purchase derivatives
16,049 7,775 8,274 >100%
Other operating income
(2,314) (4,687) 2,373 (51) %
Total expenses and other 170,206 158,483 11,723 7 %
Other expenses:
Interest expense (16,430) (8,986) (7,444) 83 %
Other, net (2) 56 (58) >100%
Total other expenses (16,432) (8,930) (7,502) 84 %
(Loss) income before income tax
(35,496) 94,295 (129,791) >100%
Income tax (benefit) expense
(9,479) 24,432 (33,911) >100%
Net (loss) income
$ (26,017) $ 69,863 $ (95,880) >100%
Adjusted EBITDA(3)
$ 49,404 $ 67,121 $ (17,717) (26) %
Adjusted Net Income (Loss)(3)
$ (5,867) $ 10,839 $ (16,706) >100%
__________
(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $26 million and $28 million and the intercompany elimination was $8 million and $5 million for the quarters ended September 30, 2025 and September 30, 2024, respectively.
(2) Includes legal and other professional expenses related to various transaction 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, increased 6% or $3 million to $58 million for the third quarter of 2025 when compared to the third quarter of 2024. Non-fuel lease operating expense increased $2 million in the third quarter of 2025 due to higher outside services and surface facility costs. A majority of these higher costs in the third quarter of 2025 was a result of the steam-to-surface event at Mid-North Diatomite. Natural gas (fuel) costs for our California steam generation facilities increased $1 million in the third quarter of 2025 due to an increase in price.
Cost of services (excluding intercompany amounts) decreased $5 million, or 20%, to $18 million for the third quarter of 2025 compared to the same period in 2024 primarily due to lower activity.
Natural gas purchase derivatives in the three months ended September 30, 2025, resulted in a loss of $16 million that included $6 million settlement losses and $10 million mark-to-market losses. Natural gas purchase
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derivatives in the same period of 2024 resulted in a loss of $8 million including $7 million settlement losses and mark-to-market losses of less than $1 million.
Marketing expenses, which includes third-party gas marketing and processing expenses, as well as costs from gas we purchased in the Rockies and sold into the California market, were flat at $2 million in the three months ended September 30, 2025 compared to the same period in 2024.
Transportation expenses were comparable for the periods presented.
Acquisition and other transaction costs were $3 million for the three months ended September 30, 2025 compared to $1 million for the three months ended September 30, 2024 and include legal and professional expenses related to various transaction activities, and in 2025 mostly related to the Merger discussed elsewhere.
General and administrative expenses increased $1 million to $20 million for the three months ended September 30, 2025 when compared to the same period in 2024. For both the three months ended September 30, 2025, and 2024, general and administrative expenses had $2 million in non-cash stock compensation expense. We had no non-recurring costs in the third quarter of 2025 compared to $1 million in the same period for 2024.
Adjusted General and Administrative Expenses, which exclude non-cash stock compensation expense and non-recurring costs increased $2 million to $18 million for the three months ended September 30, 2025 when compared to the three months ended September 30, 2024 primarily due to higher payroll related costs and professional and legal expenses. 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 $4 million, or 10%, to $39 million in the three months ended September 30, 2025, primarily due to a decrease in the depletion rate and lower production when compared to the three months ended September 30, 2024.
Taxes, Other Than Income Taxes
Three Months Ended
September 30, 		$ Change % Change
2025 2024
(per boe)
Severance taxes $ 1.58 $ 1.66 $ (0.08) (5) %
Ad valorem and property taxes 2.03 2.44 (0.41) (17) %
Greenhouse gas allowances and other emission costs 2.78 0.44 2.34 >100%
Total taxes other than income taxes $ 6.39 $ 4.54 $ 1.85 41 %
Taxes, other than income taxes increased in the three months ended September 30, 2025, by 41% to $6.39 per boe primarily due to GHG mark-to-market prices increasing in the third quarter of 2025 compared to a price decrease for the same period of 2024, partially offset by lower ad valorem and severance taxes.
Other Operating (Income) Expense
For the three months ended September 30, 2025, other operating income was $2 million, which was related to development permit refunds and property tax refunds. For the three months ended September 30, 2024, other operating income was $5 million and mainly consisted of a gain on CJWS property sold of approximately $5 million in addition to a loss on material and equipment sales of approximately $1 million.
Interest Expense
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Interest expense increased $7 million in the three months ended September 30, 2025, when compared to the three months ended September 30, 2024, primarily due to the higher prevailing interest rate associated with our borrowings and increased amortization of deferred financing costs.
Income Taxes
Our effective tax rate was approximately 27% for the three months ended September 30, 2025 which is comparable 26% for the three months ended September 30, 2024.
Nine Months Ended September 30, 2025 compared to Nine Months Ended September 30, 2024.
Nine Months Ended
September 30, 		$ Change % Change
2025 2024
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales $ 401,988 $ 489,537 $ (87,549) (18) %
Service revenue(1)
67,250 88,303 (21,053) (24) %
Electricity sales 15,167 12,344 2,823 23 %
Gains (losses) on oil and gas sales derivatives
57,232 (1,610) 58,842 n/a
Marketing and other revenues 2,234 8,848 (6,614) (75) %
Total revenues and other $ 543,871 $ 597,422 $ (53,551) (9) %
__________
(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $90 million and $103 million and the intercompany elimination was $22 million and $15 million for the nine months ended September 30, 2025 and 2024, respectively.
Revenues and Other
Oil, natural gas and NGL sales decreased $88 million, or 18%, to $402 million for the nine months ended September 30, 2025 when compared to the nine months ended September 30, 2024. The variance was driven by a $67 million decrease in oil prices and a $22 million decrease in oil volumes, partially offset by a $1 million increase in gas prices. The lower oil volumes were due to natural decline and downtime related to the steam-to-surface event at one well in the third quarter of 2025.
Service revenue (excluding intercompany amounts) decreased $21 million, or 24%, to $67 million for the nine months ended September 30, 2025 when compared to the nine months ended September 30, 2024, due to lower activity and rates.
Electricity sales, which represent sales to utilities increased $3 million, or 23%, to $15 million for the nine months ended September 30, 2025, when compared to the nine months ended September 30, 2024, due to higher resource adequacy payments received and operating volumes.
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 nine months ended September 30, 2025 were $19 million compared to a loss of $17 million for nine months ended September 30, 2024. Settlement gains in the third quarter of 2025 were driven by a lower average settlement price relative to the average fixed price. The mark-to-market non-cash gain was $38 million for the nine months ended September 30, 2025, compared to a gain of $16 million for the nine months ended September 30, 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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Marketing and other revenues, which 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 $2 million in the nine months ended September 30, 2025, $7 million lower than the same period in 2024, due to less gas marketing activity.
Nine Months Ended
September 30, 		$ Change % Change
2025 2024
(in thousands)
Expenses and other:
Lease operating expenses $ 168,612 $ 170,061 $ (1,449) (1) %
Costs of services(1)
58,236 75,236 (17,000) (23) %
Electricity generation expenses 2,671 2,924 (253) (9) %
Transportation expenses 3,501 3,430 71 2 %
Marketing expenses 2,288 8,100 (5,812) (72) %
Acquisition and other transaction costs(2)
3,596 4,982 (1,386) (28) %
General and administrative expenses 60,817 58,226 2,591 4 %
Depreciation, depletion and amortization 114,200 128,423 (14,223) (11) %
Impairment of oil and gas properties 157,910 43,980 113,930 >100%
Taxes, other than income taxes 36,253 38,714 (2,461) (6) %
Losses on natural gas purchase derivatives
13,488 14,898 (1,410) (9) %
Other operating income
(548) (8,024) 7,476 >100%
Total expenses and other 621,024 540,950 80,074 15 %
Other expenses
Interest expense (47,115) (28,176) (18,939) 67 %
Other, net 211 (80) 291 >100%
Total other expenses (46,904) (28,256) (18,648) 66 %
(Loss) income before income taxes
(124,057) 28,216 (152,273) >100%
Income tax (benefit) expense
(34,964) 7,206 (42,170) >100%
Net (loss) income
$ (89,093) $ 21,010 $ (110,103) >100%
Adjusted EBITDA(3)
$ 170,769 $ 209,984 $ (39,215) (19) %
Adjusted Net Income(3)
$ 3,139 $ 35,904 $ (32,765) (91) %
__________
(1) The well servicing and abandonment services segment provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $81 million and $90 million and the intercompany elimination was $22 million and $15 million for the nine months ended September 30, 2025 and September 30, 2024, respectively.
(2) Includes legal and other professional expenses related to various transaction 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."
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Expenses
Lease operating expenses, which do not include the effects of gas purchase hedges, decreased 1%, or $1 million, on an absolute dollar basis to $169 million for the nine months ended September 30, 2025 when compared to the nine months ended September 30, 2024. The decrease was due to lower power, well servicing and lease maintenance costs. Natural gas (fuel) costs for our California steam generation facilities increased $1 million for nine months ended September 30, 2025 when compared to the same period in 2024. A $6 million increase in fuel price was partially offset by a $5 million decrease in fuel volumes.
Cost of services (excluding intercompany amounts) decreased $17 million, or 23%, to $58 million in the nine months ended September 30, 2025, due to lower activity.
Electricity generation expenses were flat at $3 million for the nine months ended September 30, 2025 compared to the same period in 2024.
Loss on natural gas purchase derivatives for the nine months ended September 30, 2025 was $13 million resulting from $15 million settlement losses, partially offset by $2 million mark-to-market gains. Loss on natural gas purchase derivatives for the same period in 2024 was $15 million resulting from $21 million settlement losses, partially offset by $6 million settlement gains. Mark-to-market valuation gains were consistent with the changes in futures prices at the end of each period. Settlement losses were the result of average settlement prices that were lower than average fixed prices during the same periods.
Marketing expenses, which include third-party gas marketing and processing expenses as well as costs from gas we purchased in the Rockies and sold into the California market, was $2 million in the nine months ended September 30, 2025, $6 million lower than the same period in 2024, due to less gas marketing activity.
Transportation expenses were comparable for the periods presented.
Acquisition and other transaction costs were $4 million for the nine months ended September 30, 2025 compared to $5 million for the nine months ended September 30, 2024 and include legal and professional expenses related to various transaction activities, and in 2025 mostly related to the Merger discussed elsewhere.
General and Administrative expenses increased $3 million, or 4%, to approximately $61 million for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024. For the nine months ended September 30, 2025 and September 30, 2024, General and Administrative expenses included non-cash stock compensation costs of approximately $6 million and $4 million, respectively. We incurred no non-recurring costs for the nine months ended September 30, 2025. For the nine months ended September 30, 2024, we incurred non-recurring costs of $2 million.
Adjusted General and Administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs were $55 million for the nine months ended September 30, 2025, an increase of $2 million driven by an increase in payroll related costs and legal fees when compared to the nine months ended September 30, 2024. See "-Non-GAAP Financial Measures" for a reconciliation of General and Administrative expense, the most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted General and Administrative expenses.
DD&A decreased $14 million, or 11%, to $114 million for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024, due to decreased depletion rates and 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 nine months ended September 30, 2025. For the nine months ended September 30, 2024, we recorded an impairment of oil and gas properties for $44 million as a result of regulatory changes that negatively impacted unproved oil and gas properties in certain California locations. For information regarding Impairment of
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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
Nine Months Ended
September 30, 		$ Change % Change
2025 2024
(per boe)
Severance taxes $ 1.88 $ 1.68 $ 0.20 12 %
Ad valorem and property taxes 2.07 2.36 (0.29) (12) %
Greenhouse gas allowances and other emission costs 1.54 1.57 (0.03) (2) %
Total taxes other than income taxes $ 5.49 $ 5.61 $ (0.12) (2) %
Taxes other than income taxes decreased 2% to $5.49 per boe for the nine months ended September 30, 2025, compared to $5.61 per boe for the nine months ended September 30, 2024. Ad valorem and property taxes were lower due to decreased property valuations in the nine months ended September 30, 2025. Severance taxes increased due to supplemental tax charges.
Other Operating (Income) Expenses
For the nine months ended September 30, 2025, other operating income was less than $1 million, which was related to development permit refunds and property tax refunds. For the nine months ended September 30, 2024, other operating income was $8 million and mainly consisted of a $5 million gain on property sold for CJWS, a $1 million gain on prior period royalty receipts, and a $1 million gain on property tax refunds, partially offset by a loss on material and equipment sales of approximately $1 million.
Interest Expense
Interest expense increased $19 million, or 67%, in the nine months ended September 30, 2025, compared to the same period in 2024, primarily due to the higher prevailing interest rate associated with our larger borrowings and increased amortization of deferred financing costs.
Income Taxes
Our effective tax rate was approximately 28% for the nine months ended September 30, 2025, compared to 26% for the nine months ended September 30, 2024, respectively. The effective tax rate in both periods included the effect of certain permanent items that are not deductible for tax purposes and the impact of tax credits generated.
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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 Nine Months Ended
September 30,
2025 		June 30,
2025 		September 30,
2024 		September 30,
2025 		September 30,
2024
(in thousands)
Adjusted EBITDA reconciliation:
Net (loss) income
$ (26,017) $ 33,604 $ 69,863 $ (89,093) $ 21,010
Add (Subtract):
Interest expense 16,430 15,513 8,986 47,115 28,176
Income tax (benefit) expense
(9,479) 13,188 24,432 (34,964) 7,206
Depreciation, depletion and amortization 38,514 35,294 42,749 114,200 128,423
Impairment of oil and gas properties - - - 157,910 43,980
Losses (gains) on derivatives
20,715 (53,293) (67,659) (43,744) 16,508
Net cash received (paid) for scheduled derivative settlements
4,082 4,908 (10,397) 7,678 (38,606)
Other operating (income) expense
(2,314) 1,365 (4,687) (548) (8,024)
Stock compensation expense
2,247 2,026 2,301 6,679 4,676
Acquisition and other transaction costs(1)
3,286 310 971 3,596 4,982
Non-recurring costs(2)
1,940 - 562 1,940 1,653
Adjusted EBITDA $ 49,404 $ 52,915 $ 67,121 $ 170,769 $ 209,984
__________
(1) Includes legal and other professional expenses related to various transaction activities.
(2) In 2025, non-recurring costs related to a steam-to-surface event at one well in the third quarter. In 2024, non-recurring costs included cost savings initiatives.
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Three Months Ended Nine Months Ended
September 30,
2025 		June 30,
2025 		September 30,
2024 		September 30,
2025 		September 30,
2024
(in thousands)
Adjusted EBITDA reconciliation:
Net cash provided by operating activities $ 55,411 $ 28,638 $ 70,695 $ 129,921 $ 168,859
Add (Subtract):
Cash interest payments 13,932 14,487 16,174 41,878 32,825
Cash income tax payments 177 5,239 2,286 5,482 2,777
Acquisition and other transaction costs(1)
3,286 310 971 3,596 4,982
Non-recurring costs(2)
1,940 - 562 1,940 1,653
Changes in operating assets and liabilities - working capital(3)
(22,346) 3,852 (13,605) (9,229) 12,231
Other operating (income) expense - cash portion(4)
(2,996) 389 (9,962) (2,819) (13,343)
Adjusted EBITDA $ 49,404 $ 52,915 $ 67,121 $ 170,769 $ 209,984
__________
(1) Includes legal and other professional expenses related to various transaction activities.
(2) In 2025, non-recurring costs related to a steam-to-surface event at one well in the third quarter. In 2024, 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.
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
Nine Months Ended
September 30,
2025 		June 30,
2025 		September 30,
2024 		September 30,
2025 		September 30,
2024
(in thousands)
Free Cash Flow reconciliation:
Net cash provided by operating activities
$ 55,411 $ 28,638 $ 70,695 $ 129,921 $ 168,859
Capital expenditures
(17,021) (54,249) (25,874) (99,659) (85,135)
Free Cash Flow
$ 38,390 $ (25,611) $ 44,821 $ 30,262 $ 83,724
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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
September 30, 2025 June 30, 2025 September 30, 2024
(in thousands) per share - diluted (in thousands) per share - diluted (in thousands) per share - diluted
Adjusted Net Income (Loss) reconciliation:
Net (loss) income
$ (26,017) $ (0.34) $ 33,604 $ 0.43 $ 69,863 $ 0.91
Add (Subtract):
Losses (gains) on derivatives
20,715 0.27 (53,293) (0.69) (67,659) (0.88)
Net cash received (paid) for scheduled derivative settlements
4,082 0.05 4,908 0.07 (10,397) (0.13)
Other operating (income) expenses
(2,314) (0.02) 1,365 0.03 (4,687) (0.07)
Acquisition and other transaction costs(1)
3,286 0.04 310 - 971 0.01
Non-recurring costs(2)
1,940 0.02 - - 562 0.01
Total additions, net
27,709 0.36 (46,710) (0.59) (81,210) (1.06)
Income tax (expense) benefit of adjustments(3)
(7,559) (0.10) 12,742 0.16 22,186 0.29
Adjusted Net (Loss) Income
$ (5,867) $ (0.08) $ (364) $ 0.00 $ 10,839 $ 0.14
Basic EPS on Adjusted Net (Loss) Income
$ (0.08) $ 0.00 $ 0.14
Diluted EPS on Adjusted Net (Loss) Income
$ (0.08) $ 0.00 $ 0.14
Weighted average shares of common stock outstanding - basic 77,602 77,596 76,939
Weighted average shares of common stock outstanding - diluted 77,602 77,596 77,060
__________
(1) Includes legal and other professional expenses related to various transaction activities.
(2) In 2025, non-recurring costs related to a steam-to-surface event at one well in the third quarter. In 2024, non-recurring costs included cost savings initiatives.
(3) The federal and state statutory rates were utilized for all periods presented.
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Nine Months Ended
September 30, 2025 September 30, 2024
(in thousands) per share - diluted (in thousands) per share - diluted
Adjusted Net Income (Loss) reconciliation:
Net (loss) income
$ (89,093) $ (1.15) $ 21,010 $ 0.27
Add (Subtract):
(Gains) losses on derivatives
(43,744) (0.56) 16,508 0.21
Net cash received (paid) for scheduled derivative settlements
7,678 0.10 (38,606) (0.50)
Other operating income
(548) - (8,024) (0.09)
Impairment of oil and gas properties 157,910 2.03 43,980 0.57
Acquisition and other transaction costs(1)
3,596 0.05 4,982 0.06
Non-recurring costs(2)
1,940 0.02 1,653 0.02
Total additions, net
126,832 1.64 20,493 0.27
Income tax expense of adjustments(3)
(34,600) (0.45) (5,599) (0.07)
Adjusted Net Income $ 3,139 $ 0.04 $ 35,904 $ 0.47
Basic EPS on Adjusted Net Income $ 0.04 $ 0.47
Diluted EPS on Adjusted Net Income $ 0.04 $ 0.47
Weighted average shares of common stock outstanding - basic 77,466 76,712
Weighted average shares of common stock outstanding - diluted 77,667 76,903
__________
(1) Includes legal and other professional expenses related to various transaction activities.
(2) In 2025, non-recurring costs related to a steam-to-surface event at one well in the third quarter. In 2024, non-recurring costs included cost savings initiatives.
(3) The federal and state statutory rates were utilized for all periods presented.
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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.
Three Months Ended Nine Months Ended
September 30,
2025 		June 30,
2025 		September 30,
2024 		September 30,
2025 		September 30,
2024
(in thousands)
Adjusted General and Administrative Expense reconciliation:
General and administrative expenses $ 20,242 $ 20,270 $ 19,111 $ 60,817 $ 58,226
Subtract:
Non-cash stock compensation expense (G&A portion)
(2,131) (1,957) (2,083) (6,093) (4,126)
Non-recurring costs(1)
- - (562) - (1,653)
Adjusted general and administrative expenses $ 18,111 $ 18,313 $ 16,466 $ 54,724 $ 52,447
Well servicing and abandonment services segment
$ 2,153 $ 2,124 $ 2,351 $ 6,577 $ 7,734
E&P segment, and corporate $ 15,958 $ 16,189 $ 14,115 $ 48,147 $ 44,713
E&P segment, and corporate ($/boe) $ 7.25 $ 7.44 $ 6.19 $ 7.29 $ 6.49
Total mboe 2,200 2,177 2,281 6,602 6,891
__________
(1) In 2024, 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
September 30,
2025 		June 30,
2025 		September 30,
2024
(in thousands)
Energy LOE - unhedged
$ 26,119 $ 22,476 $ 24,548
Non-energy LOE
32,018 30,717 30,352
Lease operating expenses(1)
58,137 53,193 54,900
Gas purchase hedges - realized
6,199 7,699 7,490
Lease operating expenses - hedged
$ 64,336 $ 60,892 $ 62,390
Energy LOE - unhedged
$ 26,119 $ 22,476 $ 24,548
Gas purchase hedges - realized
6,199 7,699 7,490
Energy LOE - hedged
$ 32,318 $ 30,175 $ 32,038
Three-months ended
September 30,
2025 		June 30,
2025 		September 30,
2024
(per boe)
Energy LOE - unhedged
$ 11.87 $ 10.32 $ 10.76
Non-energy LOE
14.55 14.11 13.31
Lease operating expenses(1)
26.42 24.43 24.07
Gas purchase hedges - realized
2.82 3.54 3.28
Lease operating expenses - hedged
$ 29.24 $ 27.97 $ 27.35
Energy LOE - unhedged
$ 11.87 $ 10.32 $ 10.76
Gas purchase hedges - realized
2.82 3.54 3.28
Energy LOE - hedged
$ 14.69 $ 13.86 $ 14.04
Nine-months ended
September 30,
2025 		September 30,
2024
(in thousands)
Energy LOE - unhedged
$ 74,918 $ 76,529
Non-energy LOE
93,694 93,532
Lease operating expenses(1)
168,612 170,061
Gas purchase hedges - realized
15,374 21,216
Lease operating expenses - hedged
$ 183,986 $ 191,277
Energy LOE - unhedged
$ 74,918 $ 76,529
Gas purchase hedges - realized
15,374 21,216
Energy LOE - hedged
$ 90,292 $ 97,745
__________
(1) Lease operating expenses ("LOE") is also referred to as LOE - unhedged.
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Nine-months ended
September 30,
2025 		September 30,
2024
(per boe)
Energy LOE - unhedged
$ 11.35 $ 11.11
Non-energy LOE
14.19 13.57
Lease operating expenses(1)
25.54 24.68
Gas purchase hedges - realized
2.33 3.08
Lease operating expenses - hedged
$ 27.87 $ 27.76
Energy LOE - unhedged
$ 11.35 $ 11.11
Gas purchase hedges - realized
2.33 3.08
Energy LOE - hedged
$ 13.68 $ 14.19
__________
(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 September 30, 2025, we had $416 million outstanding on our 2024 Term Loan (as defined below) and no borrowings outstanding under our 2024 Revolver. As of September 30, 2025, we had $94 million of liquidity consisting of $13 million of cash, $49 million of available borrowing capacity on the 2024 Revolver and $32 million of available commitments under the Delayed Draw Term Loan (defined below) provided under the 2024 Term Loan.
We review the usage of our Free Cash Flow periodically 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.
Under the terms of the Merger Agreement, we are restricted, subject to limited exceptions, from, among other things, (i) incurring indebtedness under the 2024 Revolver outside of the ordinary course of business consistent with past practices, and in no event exceeding $30 million of incremental borrowings in the aggregate outstanding at any given time, after giving effect to repayments after the date of the Merger Agreement and (ii) selling shares of our common stock pursuant to the ATM Program or otherwise while the Merger Agreement is in effect.
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 (as amended, 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,
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which aligned certain terms with the 2024 Revolver. The Original Term Loan Agreement, as amended to date, 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, 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.
As of September 30, 2025, we had $416 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
On December 24, 2024, the Company entered into a Senior Secured Revolving Credit Agreement (as amended to date, 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 September 30, 2025, and (iii) the aggregate elected commitment amount, which was equal to $63 million as of September 30, 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. On October 30, 2025, the parties to the 2024 Revolver entered into a consent to postpone the next redetermination of the 2024 Revolver borrowing base from November 1, 2025 to February 15, 2026 (or as promptly thereafter as reasonably practicable). 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.
As of September 30, 2025, we had approximately $49 million of available borrowing capacity under the 2024 Revolver with $14 million of letters of credit and no borrowings outstanding. For additional information regarding the 2024 Revolver, see "Note 2-Debt" in the notes to condensed consolidated financial statements in Part I, Item 1. "Financial Statements" in this Quarterly Report.
Hedging
We have protected a significant portion of our anticipated cash flows through our commodity hedging program, including swaps, puts, calls and collars. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge gas purchases to protect against price increases. We have also entered into gas transportation contracts in the Rockies to help reduce the price fluctuation exposure; however these do not qualify as hedges.
The 2024 Revolver and 2024 Term Loan each requires us to maintain commodity hedges as described in "Note 3-Derivatives" in the notes to condensed consolidated financial statements in Part I, Item 1. "Financial Statements" in this Quarterly Report.
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Our generally low-decline production base affords an ability to hedge a material amount of our future expected production. We expect our operations to generate sufficient cash flows at current commodity prices including our current hedging positions. For information regarding risks related to our hedging program, see Part I-Item 1A. "Risk Factors-Risks Related to Our Operations and Industry" in our Annual Report.
As of October 31, 2025, we had the following crude oil production and gas purchase hedges.
Q4 2025
FY 2026
FY 2027
FY 2028
Brent - Crude Oil production
Swaps
Hedged volume (bbls) 1,610,000 5,382,518 3,915,500 2,045,000
Hedged volume (mbbls) per day
17.5 14.7 10.7 5.6
Weighted-average price ($/bbl) $ 74.69 $ 69.71 $ 69.27 $ 67.59
Collars
Hedged volume (bbls) 61,750 462,000 899,550 561,400
Hedged volume (mbbls) per day
0.7 1.3 2.5 1.5
Weighted-average ceiling ($/bbl)
$ 73.01 $ 73.53 $ 71.06 $ 70.59
Weighted-average floor ($/bbl)
$ 60.00 $ 60.00 $ 61.01 $ 60.00
NWPL - Natural Gas purchases(1)
Swaps
Hedged volume (mmbtu) 3,680,000 14,600,000 12,160,000 -
Hedged volume (mbbtu) per day
40.0 40.0 33.3 -
Weighted-average price ($/mmbtu) $ 4.15 $ 3.97 $ 4.18 $ -
__________
(1) The term "NWPL" is defined as Northwest Rocky Mountain Pipeline and represents the index used for these gas purchase hedges.
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(Losses) gains on Derivatives
A summary of gains and losses on the derivatives included on the statements of operations is presented below:
Three Months Ended Nine Months Ended
September 30,
2025 		June 30,
2025 		September 30,
2024 		September 30,
2025 		September 30,
2024
(in thousands)
Realized gains (losses) on commodity derivatives:
Realized gains (losses) on oil sales derivatives
$ 10,282 $ 8,593 $ (2,907) $ 19,039 $ (17,390)
Realized losses on natural gas purchase derivatives
(6,200) (7,698) (7,490) (15,374) (21,216)
Total realized gains (losses) on derivatives $ 4,082 $ 895 $ (10,397) $ 3,665 $ (38,606)
Unrealized (losses) gains on commodity derivatives:
Unrealized (losses) gains on oil sales derivatives
$ (14,948) $ 47,830 $ 78,341 $ 38,193 $ 15,780
Unrealized (losses) gains on natural gas purchase derivatives
(9,849) 4,568 (285) 1,886 6,318
Total unrealized (losses) gains on derivatives $ (24,797) $ 52,398 $ 78,056 $ 40,079 $ 22,098
Total (losses) gains on derivatives
$ (20,715) $ 53,293 $ 67,659 $ 43,744 $ (16,508)
The following table summarizes the historical results of our hedging activities.
Three Months Ended Nine Months Ended
September 30,
2025 		June 30,
2025 		September 30,
2024 		September 30,
2025 		September 30,
2024
Crude Oil (per bbl):
Realized sales price, before the effects of derivative settlements $ 62.21 $ 61.26 $ 72.40 $ 64.37 $ 75.31
Effects of derivative settlements 5.12 6.28 (1.39) 3.79 (2.71)
Realized sales price, after the effects of derivative settlements
$ 67.33 $ 67.54 $ 71.01 $ 68.16 $ 72.60
Purchased Natural Gas (per mmbtu):
Purchase price, before the effects of derivative settlements $ 3.17 $ 2.80 $ 2.72 $ 3.45 $ 3.04
Effects of derivative settlements 1.49 1.89 1.64 1.24 1.53
Purchase price, after the effects of derivatives settlements $ 4.66 $ 4.69 $ 4.36 $ 4.69 $ 4.57
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Cash Dividends
In March 2025, our Board of Directors declared a cash dividend of $0.03 per share, which was paid in April 2025. In May 2025, the Board of Directors declared a cash dividend of $0.03 per share, which was paid in May 2025. In August 2025, the Board of Directors approved a cash dividend of $0.03 per share, which is expected to be paid in August 2025. In November 2025, the Board of Directors approved a fixed cash dividend of $0.03 which is expected to be paid in December 2025.
Pursuant to the terms of the Merger Agreement, the Company may declare regular quarterly cash dividends, in an amount not to exceed $0.03 per share of common stock, with declaration and payment dates consistent with the Company's historical practice.
Stock Repurchase Program
Our Board of Directors has authorized a stock repurchase program; however, under the terms of the Merger Agreement, subject to certain limited exceptions, we are restricted in our ability to redeem, repurchase or otherwise acquire our common stock, including pursuant to our stock repurchase program.
As of September 30, 2025, the Company's remaining total share repurchase authority approved by the Board of Directors was $190 million.
The Company did not repurchase any shares during the nine months ended September 30, 2025. As of September 30, 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"). 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. Pursuant to the terms of the Merger Agreement, the Company has agreed to certain customary restrictions on its ability to issue shares of its common stock, subject to certain limited exceptions, which do not permit any sales of common stock pursuant to the ATM Program while the Merger Agreement is in effect.
During the nine months ended September 30, 2025, the Company did not sell any shares of common stock under the ATM Program.
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Statements of Cash Flows
The following is a comparative cash flow summary:
Nine Months Ended
September 30,
2025 2024
(in thousands)
Net cash:
Provided by operating activities $ 129,921 $ 168,859
Used in investing activities (101,131) (85,649)
Used in financing activities (45,212) (78,574)
Net (decease) increase in cash and cash equivalents
$ (16,422) $ 4,636
Operating Activities
Cash provided by operating activities decreased for the nine months ended September 30, 2025 by approximately $39 million when compared to the nine months ended September 30, 2024. The decrease was primarily related to a decrease in revenue from lower oil prices and lower volumes and a decrease in net margin from CJWS, partially offset by an increase in derivative settlements received.
Investing Activities
The following provides a comparative summary of cash flows from investing activities:
Nine Months Ended
September 30,
2025 2024
(in thousands)
Capital expenditures:
Capital expenditures $ (99,659) $ (85,135)
Changes in capital expenditures accruals (1,992) 1,219
Acquisitions, net of cash received - (9,188)
Proceeds from sale of property and equipment and other
520 7,455
Net cash used in investing activities
$ (101,131) $ (85,649)
Cash used in investing activities increased $15 million for the nine months ended September 30, 2025 when compared to the same period in 2024. The year-over-year changes included increased capital expenditures mainly from drilling and completion activity (particularly in Utah), offset by reduced acquisition and disposal activity in 2025.
Financing Activities
Cash used in financing activities decreased approximately $33 million for the nine months ended September 30, 2025 when compared to the nine months ended September 30, 2024. Cash used for the nine months ended September 30, 2025 included the first three quarterly debt service payments on our 2024 Term Loan, fixed dividend payments, and shares withheld for payment of taxes on equity awards. Cash used for the nine months ended September 30, 2024 included the deferred consideration payment for the Macpherson Acquisition, payments for the fixed and variable dividends, shares withheld for payment of taxes on equity awards and debt issuance costs.
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Balance Sheet Analysis
The changes in our balance sheet from December 31, 2024 to September 30, 2025 are discussed below.
September 30, 2025 December 31, 2024
(in thousands)
Cash and cash equivalents $ 13,364 $ 15,336
Restricted cash
$ 250 $ 14,700
Accounts receivable, net
$ 68,565 $ 77,630
Derivative instruments assets - current and long-term
$ 44,585 $ 16,223
Other current assets $ 35,914 $ 37,451
Property, plant & equipment, net $ 1,157,596 $ 1,320,380
Deferred income taxes asset - long-term $ 57,647 $ 26,779
Other noncurrent assets $ 9,077 $ 9,187
Accounts payable and accrued expenses $ 133,214 $ 133,809
Derivative instruments liabilities - current and long-term $ - $ 7,703
Current portion of long-term debt, net $ 45,000 $ 45,000
Income taxes payable
$ - $ 1,368
Long-term debt, net $ 354,469 $ 384,633
Deferred income taxes liability - long-term $ - $ 1,612
Asset retirement obligations - long-term $ 177,585 $ 185,283
Other noncurrent liabilities $ 37,748 $ 27,642
Stockholders' equity $ 638,982 $ 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 $9 million decrease in accounts receivable was primarily due to decreased oil and gas sales between the two ending periods.
The $36 million increase in net derivative assets, which includes the derivative liability, is due to changes 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 amortization of prepaid expenses and the return of deposits offset by a tax receivable resulting from the impact of the new regulations enacted by the OBBBA.
The $163 million decrease in property, plant and equipment was primarily due to the $158 million first quarter 2025 impairment and year-to-date DD&A expense of $105 million, offset by $100 million in capital investments.
The $32 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.
The $1 million decrease in accounts payable and accrued expenses primarily includes $8 million of settlements of short-term GHG liabilities, a $7 million decrease in royalties payable, and a $2 million decrease in accrued expenses, offset by a $13 million increase in trade accounts payable and a $4 million increase in taxes, other than income tax liability.
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The $1 million decrease in income taxes payable was primarily due to the impact of the new regulations enacted by the OBBBA.
The $30 million decrease in long-term debt, net largely reflects the payment of $33 million on our 2024 term loan offset by $3 million in amortization of the debt issuance costs.
The $8 million decrease in the long-term portion of the asset retirement obligations from $185 million at December 31, 2024 to $178 million at September 30, 2025 was due to $17 million of liabilities settled during the period, offset by $9 million of accretion expense.
The $10 million increase in other noncurrent liabilities is primarily due to the obligations for greenhouse gas allowances incurred in 2025, which are due over one year.
The $92 million decrease in stockholders' equity was due to a net loss of $89 million, $8 million of common stock dividends, and $1 million of shares withheld for payment of taxes on equity awards, offset by $7 million of stock-based compensation.
Lawsuits, Claims, Commitments, and Contingencies
In the normal course of business, we, or our subsidiaries, are the subject of, or party to, pending or threatened legal proceedings, contingencies and commitments involving a variety of matters that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, false claims, property damage or other losses, punitive damages, fines and penalties, remediation costs, or injunctive or declaratory relief. In addition, we may be subject to lawsuits relating to the Merger although we are currently unaware of any such suits having been filed.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances for these items at September 30, 2025 and December 31, 2024 were not material to our consolidated financial position or results of operations as of such dates. 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 September 30, 2025, we are not aware of material indemnity claims pending or threatened against us.
Securities Litigation Matters
On October 20, 2022, a shareholder derivative lawsuit (the "Assad Lawsuit") was filed in the United States District Court for the Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that alleges certain current and former Berry directors and officers breached their fiduciary duties by causing or failing to prevent Berry from making allegedly false and misleading statements between the IPO and November 3, 2020, and in the IPO offering materials, about the Company's permits and permitting processes allegedly in violation of the Securities Act of 1933 and the Exchange Act of 1934. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act.
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On January 20, 2023, a second shareholder derivative lawsuit (the "Karp Lawsuit," together with the Assad Lawsuit, the "Shareholder Derivative Actions") was filed, this time in the United States District Court for the District of Delaware, by putative stockholder Molly Karp, allegedly on behalf of the Company. The Karp Lawsuit, similar to the Assad Lawsuit, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the same alleged securities violations at issue in the Assad Lawsuit. In addition, the Karp Lawsuit complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry's 2022 proxy statement was false and misleading in that it suggested the Company's internal controls were sufficient and the Board of Directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case.
In addition, on or around April 17, 2023, the Company received a stockholder litigation demand that the Board of Directors investigate and commence legal proceedings against certain current and former officers and directors based ostensibly on the same claims asserted in the Shareholder Derivative Actions. The Board of Directors appointed a Demand Review Committee for the purpose of reviewing the demand.
On September 24, 2025, all parties in the Karp Lawsuit filed a joint motion to stay the case pending the closing of the Merger, which the court granted. On October 1, 2025, all parties in the Assad Lawsuit filed a similar joint motion to stay that case, which was granted. On October 6, 2025, counsel for the Demand Review Committee notified the demanding shareholder of the court-ordered stays of the Shareholder Derivative Actions and informed the demanding shareholder that the Demand Review Committee was similarly pausing its work pending the closing of the Merger.
As of September 30, 2025, we are currently unable to estimate the probability of the outcome of these matters or the range of reasonably possible loss that may be related to these matters.
Contractual Obligations
The following is a summary of our commitments and contractual obligations as of September 30, 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)
416,250 45,000 371,250 - -
2024 Term Loan Interest(2)
96,711 46,525 50,186 - -
Other:
Leases
4,316 2,098 2,085 133 -
Asset retirement obligations(3)
194,585 17,000 - - 177,585
Off-Balance Sheet arrangements:(4)
Transportation and processing contracts(5)
70,296 11,418 21,193 16,374 21,311
GHG compliance purchase contracts(6)
6,213 6,213 - - -
Other purchase obligations(7)
17,100 8,400 8,700 - -
Total contractual obligations
$ 805,471 $ 136,654 $ 453,414 $ 16,507 $ 198,896
__________
(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 September 30, 2025 and expected outstanding balance throughout the term.
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(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 judgments that are subject to revisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See "Note 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 $0.8 million due over the course of the next year.
(6) We have entered into contracts to purchase GHG compliance instruments totaling $6 million.
(7) As of September 30, 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, Part II, Item 1A. "Risk Factors" in this Quarterly 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:
•risks related to the impact of the Merger, including the following: transaction costs, unknown liabilities; the risk that any announcements relating to the Merger could have adverse effects on the market price of our common stock; the ability to successfully integrate our and CRC's businesses; the ability to achieve projected synergies or that it may take longer than expected to achieve those synergies; risks related to financial community and rating agency perceptions of us or our business, operations, financial condition and the industry in which we operate; the occurrence of any event, change or other circumstance that could give rise to the termination of the Merger Agreement; the risk that our stockholders may not approve the proposed transaction; risks related to disruption of management's time from ongoing business operations due to the Merger; effects of the announcement or pendency of the Merger on our ability to retain customers and retain and hire key personnel and maintain relationships with our suppliers and customers; the risk that any of the other closing conditions to closing of the Merger may not be satisfied in a timely manner, including the risk that all necessary regulatory approvals may not be obtained or may be obtained subject to conditions that are not anticipated;
•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;
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•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;
•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, including higher-than-expected decline rates, or lower-than-expected production, reserves or resources, whether due to operating risks, drilling risks, or the inherent uncertainties in predicting reserve and reservoir performance;
•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 or 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;
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•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.
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 September 30, 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 September 30, 2025, the fair value of our hedge positions was a net asset of approximately $45 million. A 10% increase in the oil and natural gas index prices above the September 30, 2025 prices would result in a net liability of approximately $33 million; conversely, a 10% decrease in the oil and natural gas index prices below the September 30, 2025 prices would result in a net asset of approximately $123 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 September 30, 2025, the fair value of our emission allowances required by California's cap-and-trade program was $13 million. A 10% increase or decrease in the market price would result in a change in expense by $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 September 30, 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 third 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.
Previously Reported Legal Proceedings
CalGEM Matter
On April 4, 2025, CalGEM notified the Company that CalGEM's records indicated that the Company had not completed mechanical integrity testing on certain of its injection wells by April 1, 2024, which was required in order to maintain uninterrupted approval for injection. The Company has engaged with CalGEM and has confirmed that all of the subject injection wells have either undergone mechanical integrity testing and are now in compliance or have been disconnected. On September 3, 2025, CalGEM issued an Order to Pay Civil Penalties and Perform Remedial Work No. 1554 to the Company. On October 3, 2025, the Company paid a civil penalty of $2,082,560 pursuant to the Order and considers this matter to be closed.
Securities Litigation
On October 20, 2022, a shareholder derivative lawsuit (the "Assad Lawsuit") was filed in the United States District Court for the Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that alleges certain current and former Berry directors and officers breached their fiduciary duties by causing or failing to prevent Berry from making allegedly false and misleading statements between the IPO and November 3, 2020, and in the IPO offering materials, about the Company's permits and permitting processes allegedly in violation of the Securities Act of 1933 and the Exchange Act of 1934. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act.
On January 20, 2023, a second shareholder derivative lawsuit (the "Karp Lawsuit," together with the Assad Lawsuit, the "Shareholder Derivative Actions") was filed, this time in the United States District Court for the District of Delaware, by putative stockholder Molly Karp, allegedly on behalf of the Company. The Karp Lawsuit, similar to the Assad Lawsuit, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the same alleged securities violations at issue in the Assad Lawsuit. In addition, the Karp Lawsuit complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry's 2022 proxy statement was false and misleading in that it suggested the Company's internal controls were sufficient and the Board of Directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case.
In addition, on or around April 17, 2023, the Company received a stockholder litigation demand that the Board of Directors investigate and commence legal proceedings against certain current and former officers and directors based ostensibly on the same claims asserted in the Shareholder Derivative Actions. The Board of Directors appointed a Demand Review Committee for the purpose of reviewing the demand.
On September 24, 2025, all parties in the Karp Lawsuit filed a joint motion to stay the case pending the closing of the Merger, which the court granted. On October 1, 2025, all parties in the Assad Lawsuit filed a similar joint motion to stay that case, which was granted. On October 6, 2025, counsel for the Demand Review Committee notified the demanding shareholder of the court-ordered stays of the Shareholder Derivative Actions and informed the demanding shareholder that the Demand Review Committee was similarly pausing its work pending the closing of the Merger.
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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. Except as disclosed herein, there have been no material changes in the risk factors that were described in our Annual Report.
The Merger is subject to conditions, including certain conditions that are beyond our control and may not be satisfied on a timely basis or at all. Failure to complete the Merger could have adverse effects on us.
Completion of the Merger is subject to a number of conditions, including, among others: (i) the approval by our stockholders of the adoption of the Merger Agreement, (ii) the expiration or termination of any waiting period applicable to the Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act") and (iii) the receipt of authorization to consummate the Merger under Section 203 of U.S. Federal Power Act (the "FPA") from the U.S. Federal Energy Regulatory Commission ("FERC") and FERC's implementing rules thereunder, which make the completion and timing of the completion of the Merger uncertain.
The completion of the Merger is subject to the expiration or termination of the applicable waiting period under the HSR Act and receipt of FERC approval. Regulatory review under the HSR Act, the FPA and other applicable regulations may result in regulatory authorities imposing conditions on the granting of such approvals. Such conditions and the process of obtaining regulatory approvals could have the effect of delaying completion of the Merger or of imposing additional costs or limitations on the combined company following the completion of the Merger, and such conditions could result in a closing condition under the Merger Agreement not being satisfied. The regulatory approvals may not be received at all, may not be received in a timely fashion, or may contain conditions on the completion of the Merger that CRC is not required to accept under the terms of the Merger Agreement.
We cannot assure you that the various conditions to the closing will be satisfied or will not result in the abandonment or delay of the Merger. Any delay in completing the Merger could cause us not to realize, or to be delayed in realizing, some or all of the benefits that we expect to achieve if the Merger is completed within the time currently expected.
If the Merger is not completed for any reason, including as a result of our stockholders' failure to approve the Merger Agreement, our ongoing business could be adversely affected, and, without realizing any of the benefits of having completed the Merger, we would be subject to a number of risks, including:
•time and resources committed by our management to matters relating to the Merger could otherwise have been devoted to day-to-day operations or pursuing other beneficial opportunities;
•the market price of our common stock could decline as a result, particularly if the then-current market price were elevated based on a market assumption that the Merger would be completed;
•we could be required to pay a termination fee or provide expense reimbursement, as applicable, as required by the Merger Agreement;
•litigation related to the failure to complete the Merger or related to any enforcement proceeding that may be commenced against us to perform our obligations pursuant to the Merger Agreement; and
•if the Merger Agreement were terminated, and we were to seek another business combination, we might not be able to negotiate or complete a transaction on terms comparable to or more attractive than the terms of the Merger Agreement.
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Additionally, we have incurred and will incur substantial expenses in connection with the negotiation and completion of the Merger contemplated by the Merger Agreement, as well as the costs and expenses of preparing, filing, printing and mailing of a proxy statement/prospectus, and all other fees paid in connection with the Merger. If the Merger is not completed, we would have to pay some of these expenses without realizing the expected benefits of the Merger.
The Merger is subject to certain regulatory approvals that, if delayed, not granted or granted with certain burdensome conditions, could delay, impair or prevent completion of the Merger or result in additional costs or reduce the anticipated benefits of the Merger.
The completion of the Merger is subject to the expiration or termination of all waiting periods (and any agreed upon extensions of any waiting period or commitment not to complete the Merger for any period of time) applicable to the completion of the Merger under the HSR Act and the receipt of certain additional regulatory approvals.
With respect to United States antitrust and competition laws, under the HSR Act, the Merger may not be completed until Notification and Report Forms ("HSR Notifications") have been filed with the Federal Trade Commission (the "FTC") and the Antitrust Division of the Department of Justice (the "DOJ") and the applicable waiting period (or any extension thereof) has expired or been terminated. A transaction requiring notification under the HSR Act may not be completed until the expiration of the applicable 30-day waiting period following the parties' filing of their respective HSR Notifications or the early termination of that waiting period, at the earliest. If the FTC or the DOJ issues a Request for Additional Information and Documentary Material (a "Second Request") prior to the expiration of the waiting period, the parties must observe an additional 30-day waiting period, which begins to run only after both parties have complied with the Second Request, unless the waiting period is terminated earlier or the parties otherwise agree to extend the waiting period (or commit not to complete the Merger for a specified period of time). We and CRC each filed HSR Notifications with the FTC and the DOJ on October 10, 2025.
At any time before or after completion of the Merger, notwithstanding the expiration or termination of the applicable waiting period under the HSR Act, the DOJ or the FTC could take such action under antitrust or competition laws as it deems necessary or desirable in the public interest, including seeking to enjoin the completion of the Merger, seeking divestiture of substantial assets of the parties or requiring the parties to license, or hold separate, assets or to terminate existing relationships and contractual rights. Under certain circumstances, private parties may also seek to take legal action against the Merger under antitrust or competition laws.
Any one of these requirements, limitations, costs, divestitures or restrictions imposed by regulatory authorities could jeopardize or delay the completion, or reduce the anticipated benefits, of the Merger. There is no assurance that we and CRC will obtain all required regulatory consents or approvals on a timely basis, or at all. Failure to obtain the necessary consents and approvals could substantially delay or prevent the completion of the Merger, which could negatively affect us.
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The Merger Agreement limits our ability to pursue alternatives to the Merger and could discourage a potential transaction partner from making a favorable alternative transaction proposal.
Under the Merger Agreement, we are required, subject to certain exceptions with respect to unsolicited proposals, not to directly or indirectly initiate, solicit, propose or take any action to knowingly facilitate any inquiry or the making of any proposal or offer that constitutes, or would reasonably be expected to lead to, an Acquisition Proposal (as defined in the Merger Agreement) or to engage in, continue or otherwise participate in any discussions with or negotiations relating to, provide non-public information in connection with, or otherwise knowingly facilitate any effort or attempt to make an Acquisition Proposal or any inquiry, proposal or offer that would reasonably be expected to lead to an Acquisition Proposal, or otherwise enter into any alternative transaction agreement. In addition, upon termination of the Merger Agreement under certain circumstances, we may be required to pay CRC a termination fee of approximately $12.0 million. In certain circumstances, we could be required to provide expense reimbursement as required by the Merger Agreement. These provisions could discourage a potential transaction partner that might have an interest in acquiring all or a significant portion of the Company from considering or pursuing an alternative transaction with us or proposing such a transaction, even if the potential transaction partner were prepared to pay consideration with a higher per share cash or market value than the per share market value proposed to be received or realized in the Merger. These provisions might also result in a potential transaction partner proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable by us in certain circumstances. If the Merger Agreement were terminated, and we were to seek another business combination, we might not be able to negotiate or complete a transaction on terms comparable to or more attractive than the terms of the Merger Agreement.
The Merger, and uncertainty regarding the Merger, may adversely affect our relationships with customers, suppliers, strategic partners and others and could adversely affect our ability to effectively manage our business.
The Merger will occur only if the Merger Agreement's conditions to the closing are satisfied or waived. Accordingly, there may be uncertainty regarding the completion of the Merger. This uncertainty and the prospect of the Merger itself may cause customers, suppliers, strategic partners and others that deal with us to delay or defer entering into contracts with us or making other decisions concerning us or to seek changes in or cancellation of existing business relationships with us. Delays or deferrals of contracts or other decisions or changes in or cancellations of existing agreements or relationships could in some individual cases or in the aggregate have an adverse impact on our business, regardless of whether the Merger is ultimately completed.
In addition, under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to the completion of the Merger, including being obligated to use their commercially reasonable efforts to conduct our business in the ordinary course and being limited in our ability in certain cases to take certain actions that may adversely affect our ability to consummate the Merger on a timely basis without the consent of CRC, which could delay or otherwise adversely affect our ability to execute certain of our business strategies or limit our ability to respond to competitive or other developments that arise prior to the completion of the Merger and could negatively affect our business and operations.
Uncertainties associated with the Merger may result in a loss of management and other key personnel, which could adversely affect our future business and operations should the Merger not be completed.
We are dependent on the experience and industry knowledge of its officers and other key management, technical and professional personnel to execute our business plans. Our current and prospective employees may experience uncertainty about their roles within the combined company following the Merger or have other concerns regarding the timing and completion of the Merger or the operations of the combined company following the Merger, any of which may have an adverse effect on our ability to retain, attract or motivate key management and other key personnel. Furthermore, we may incur costs in our efforts to retain management personnel and other key employees prior to completion of the Merger. Accordingly, no assurance can be given that we will be able to retain management personnel and other key employees to the same extent that we have been able to in the past. If we are unable to retain personnel, including key management, who are critical to our future operations, we could face
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disruptions in its operations, loss of customers, suppliers, strategic partners or others that deal with us, loss of key information, expertise or know-how and unanticipated additional recruitment and training costs.
The Merger might be completed even if material adverse changes, such as industry-wide changes or other events, subsequent to the announcement of the Merger were to occur.
Although one of the conditions to the closing of the Merger is there not having occurred any Company Material Adverse Effect or Parent Material Adverse Effect (each as defined in the Merger Agreement) since the date of the Merger Agreement, some types of changes would not constitute a basis for the parties to refuse to complete the Merger, even if such changes would have a material adverse effect on either of the parties. In such a case, the business and financial position, results of operations and cash flows of the combined company after the Merger might be negatively affected as a result of the Merger.
We are expected to incur significant transaction costs in connection with the Merger, which may be in excess of those we anticipate.
We have incurred and are expected to continue to incur significant non-recurring costs associated with negotiating and completing the Merger, including fees paid to financial, legal, accounting and other advisors and employee retention costs. These fees and costs have been, and will continue to be, substantial and, in many cases, will be borne by us regardless of whether the Merger is completed, and could have an adverse effect on our financial position, results of operations and cash flows.
Our stockholders will not be entitled to appraisal rights in the Merger.
Appraisal rights are statutory rights that, if applicable under Delaware law, enable stockholders of a corporation to dissent from an extraordinary transaction, such as a merger, and to demand that such corporation pay the fair value for their shares as determined by a court in a judicial proceeding instead of receiving the consideration offered to such stockholders in connection with the extraordinary transaction. Under the General Corporation Law of the State of Delaware, stockholders generally do not have appraisal rights if the shares of stock they hold are either listed on a national securities exchange or held of record by more than 2,000 holders. Notwithstanding the foregoing, appraisal rights are available if stockholders are required by the terms of the Merger Agreement to accept for their shares anything other than (a) shares of stock of the surviving corporation, (b) shares of stock of another corporation that will either be listed on a national securities exchange or held of record by more than 2,000 holders, (c) cash in lieu of fractional shares or (d) any combination of the foregoing.
Because our common stock is listed on the NASDAQ and CRC common stock is listed on the NYSE, both national securities exchanges, and because our stockholders are not required by the terms of the Merger Agreement to accept for their shares of our common stock anything other than shares of CRC common stock and cash in lieu of fractional shares, holders of our common stock are not entitled to appraisal rights in connection with the Merger.
We may be a target of securities class action and derivative lawsuits, which could result in substantial costs and could delay or prevent the completion of the Merger.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements and have been threatened against us in connection with the Merger. Even if such a lawsuit is unsuccessful or merely threatened, defending against these claims can result in substantial costs. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.
Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, then that injunction may delay or prevent the Merger from being completed, or from being completed within the expected time frame.
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Our current stockholders will have a significantly reduced ownership and voting interest in the combined company after the Merger compared to their ownership in Berry and will exercise less influence over management.
At the effective time of the Merger, each share of our common stock will be converted into, and exchangeable for, 0.0718 shares of CRC common stock (the "Exchange Ratio"). At this Exchange Ratio, it is estimated that, immediately after completion of the Merger, our stockholders as of immediately prior to the Merger (disregarding any shares of CRC common stock held by our stockholders immediately prior to the Merger) would hold approximately 6% of the outstanding shares of CRC common stock. As a result, our stockholders will have a significantly reduced share of ownership and voting interests, resulting in less influence on the policies of the combined company than they currently have on the policies of Berry. In addition, CRC may from time to time engage in issuances of equity or equity-linked securities, which would result in additional dilution. The exact equity stake of our stockholders in CRC immediately following the completion of the Merger will depend on the number of shares of CRC common stock and shares of our common stock issued and outstanding immediately prior to the effective time of the Merger.
We and CRC may waive one or more of the conditions to the closing of the Merger without resoliciting approval of our stockholders and may terminate the Merger Agreement even if it has been adopted by our stockholders.
Certain conditions to the closing may be waived, in whole or in part, to the extent permitted by applicable law and by signed written agreement of us, CRC and Merger Sub or by signed written agreement of the party against which such waiver is to be effective. In addition, we and CRC can agree in writing to terminate the Merger Agreement even if our stockholders have already voted to adopt the Merger Agreement.
The Exchange Ratio is fixed and will not be adjusted in the event of fluctuations in the market price shares of CRC common stock or shares of our common stock.
In the Merger, each share of our common stock issued and outstanding immediately prior to the effective time of the Merger (other than certain excluded shares), will be converted into, and become exchangeable for, 0.0718 shares of CRC common stock. The Exchange Ratio is fixed in the Merger Agreement and will not be adjusted for changes in the market price of either our common stock or CRC common stock. Due to the fixed Exchange Ratio, fluctuations in the price of CRC common stock will drive corresponding changes in the value of the merger consideration. As a result, changes in the price of CRC common stock prior to the completion of the Merger will affect the market value that our stockholders will become entitled to receive at the effective time of the Merger. Changes in the price of CRC common stock or our common stock could result from changes in the business, operations or prospects of us or CRC prior to or following the completion of the Merger, regulatory considerations, general market and economic conditions and other factors both within and beyond our control, including, among other things, a decline in the price of oil or gas, a reduction in demand for oil and gas products, increased regulation of drilling and production and a number of other factors that are more fully described in the risk factors sections included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024.
After the Merger is completed, our stockholders will have their rights as stockholders governed by CRC's organizational documents.
Upon completion of the Merger, our stockholders will no longer be stockholders of Berry, but will instead become stockholders of CRC. Our former stockholders will instead have rights as a stockholder of CRC that differ from the rights they had as a stockholder of Berry before the Merger.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Stock Repurchase Program
The Company did not repurchase any shares during the nine months ended September 30, 2025. As of September 30, 2025, the Company had repurchased a total of 11.9 million shares, cumulatively, under the stock repurchase program for approximately $114 million in aggregate, which is 15% of outstanding shares as of September 30, 2025.
Our Board of Directors has authorized a stock repurchase program and, as of September 30, 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. Under the terms of the Merger Agreement, the Company is restricted in its ability to redeem, repurchase or otherwise acquire its common stock, including pursuant to the stock repurchase program. As a result, we do not expect to repurchase shares pursuant to the stock repurchase program while the Merger Agreement is in effect.
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.
Item 5. Other Information
During the quarter ended September 30, 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
2.1
Agreement and Plan of Merger, dated as of September 14, 2025, by and among Berry Corporation (bry), California Resources Corporation, and Dornoch Merger Sub, LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed September 16, 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
Second Amendment to Senior Secured Revolving Credit Agreement, dated as of July 18, 2025, among Berry Corporation (Bry), the guarantors party thereto, the lenders party thereto, and Texas Capital Bank, as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed August 7, 2025).
10.2
Third Amendment to Senior Secured Term Loan Credit Agreement, dated as of July 18, 2025, by and among Berry Corporation (bry), each of the guarantors party thereto, each of the lenders that is a signatory thereto and Breakwall Credit Management LLC, as administrative agent (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed August 7, 2025).
10.3†
Amended and Restated Key Employee Agreement by and between Berry Petroleum Company, LLC and Jeff Magids, effective August 5, 2025 (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed August 7, 2025).
10.4†
Key Employee Agreement by and between Berry Petroleum Company, LLC and Jenarae Garland, effective April 14, 2025, and Amendment 1 thereto effective August 5, 2025 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed August 7, 2025).
10.5†*
Amended and Restated Berry Corporation (bry) Non-Employee Director Meeting Fee Compensation Policy (effective as of August 11, 2025).
10.6†
Form of Executive Officer Retention Agreement (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed September 16, 2025).
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: November 5, 2025
/s/ Michael S. Helm
Michael S. Helm
Vice President, Chief Accounting Officer
(Principal Accounting Officer)
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Berry Corporation published this content on November 05, 2025, and is solely responsible for the information contained herein. Distributed via Edgar on November 05, 2025 at 19:22 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]