Berry Corporation

11/08/2024 | Press release | Distributed by Public on 11/08/2024 13:41

Quarterly Report for Quarter Ending September 30, 2024 (Form 10-Q)

bry-20240930
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, 2024
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 November 1, 2024 76,938,994
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
21
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
72
Item 4.
Controls and Procedures
73
Part II - Other Information
Item 1.
Legal Proceedings
74
Item 1A.
Risk Factors
75
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities
77
Item 5.
Other Information
77
Item 6.
Exhibits
78
Glossary of Terms
79
Signatures
86
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, 2024 December 31, 2023
(in thousands, except share amounts)
Unaudited
ASSETS
Current assets:
Cash and cash equivalents $ 9,471 $ 4,835
Accounts receivable, net of allowance for doubtful accounts of $655 at September 30, 2024 and December 31, 2023
74,542 86,918
Derivative instruments 17,312 5,288
Other current assets 35,539 43,759
Total current assets 136,864 140,800
Noncurrent assets:
Oil and natural gas properties 1,954,258 1,906,134
Accumulated depletion and amortization (698,350) (592,621)
Total oil and natural gas properties, net 1,255,908 1,313,513
Other property and equipment 169,017 167,767
Accumulated depreciation (87,650) (74,668)
Total other property and equipment, net 81,367 93,099
Deferred income taxes 27,378 30,308
Derivative instruments 4,798 5,463
Other noncurrent assets 10,833 10,975
Total assets $ 1,517,148 $ 1,594,158
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 144,186 $ 213,401
Derivative instruments - 9,781
Current portion of long-term debt, net
27,500 -
Total current liabilities 171,686 223,182
Noncurrent liabilities:
Long-term debt, net
398,000 427,993
Derivative instruments - 959
Deferred income taxes 4,264 2,344
Asset retirement obligations 178,329 176,578
Other noncurrent liabilities 32,660 5,126
Commitments and Contingencies - Note 4
Stockholders' equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 88,942,805 and 87,671,241 shares issued; and 76,938,994 and 75,667,430 shares outstanding, at September 30, 2024 and December 31, 2023, respectively)
89 88
Additional paid-in-capital 785,459 819,157
Treasury stock, at cost (12,003,811 shares at September 30, 2024 and December 31, 2023, respectively)
(113,768) (113,768)
Retained earnings 60,429 52,499
Total stockholders' equity 732,209 757,976
Total liabilities and stockholders' equity $ 1,517,148 $ 1,594,158
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,
2024 2023 2024 2023
(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales
$ 154,438 $ 172,611 $ 489,537 $ 496,671
Services revenue 25,465 45,511 88,303 137,808
Electricity sales 4,410 3,849 12,344 12,372
Gains (losses) on oil and gas sales derivatives
75,434 (103,282) (1,610) (43,912)
Other revenues 37 113 140 194
Total revenues and other 259,784 118,802 588,714 603,133
Expenses and other:
Lease operating expenses 54,801 59,842 169,487 249,384
Costs of services 22,911 35,806 75,236 108,988
Electricity generation expenses 1,245 1,479 2,890 5,252
Transportation expenses 1,332 1,089 3,430 3,226
Acquisition costs 971 2,082 4,982 3,054
General and administrative expenses 19,111 20,987 58,226 75,144
Depreciation, depletion, and amortization 42,749 39,729 128,423 119,605
Impairment of oil and gas properties - - 43,980 -
Taxes, other than income taxes 10,351 17,980 38,714 42,147
Losses (gains) on natural gas purchase derivatives
7,775 (8,425) 14,898 4,989
Other operating (income)
(4,687) (505) (8,024) (1,824)
Total expenses and other 156,559 170,064 532,242 609,965
Other expenses:
Interest expense (8,986) (9,101) (28,176) (25,732)
Other, net 56 (42) (80) (227)
Total other expenses (8,930) (9,143) (28,256) (25,959)
Income (loss) before income taxes
94,295 (60,405) 28,216 (32,791)
Income tax expense (benefit)
24,432 (15,343) 7,206 (7,640)
Net income (loss)
$ 69,863 $ (45,062) $ 21,010 $ (25,151)
Net income (loss) income per share:
Basic
$ 0.91 $ (0.60) $ 0.27 $ (0.33)
Diluted
$ 0.91 $ (0.60) $ 0.27 $ (0.33)
The accompanying notes are an integral part of these condensed consolidated financial statements.
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BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
Nine-Month Period Ended September 30, 2023
Common Stock Additional Paid-in Capital Treasury Stock
Retained Earnings
Total Stockholders' Equity
(in thousands)
December 31, 2022 $ 86 $ 821,443 $ (103,739) $ 82,695 $ 800,485
Shares withheld for payment of taxes on equity awards and other - (4,260) - - (4,260)
Stock-based compensation
- 4,989 - - 4,989
Issuance of common stock 2 - - - 2
Dividends declared on common stock, $0.50/share
- - - (42,421) (42,421)
Net loss - - - (5,859) (5,859)
March 31, 2023 88 822,172 (103,739) 34,415 752,936
Shares withheld for payment of taxes on equity awards and other - (2,612) - - (2,612)
Stock-based compensation - 3,770 - - 3,770
Purchases of treasury stock - - (10,029) - (10,029)
Dividends declared on common stock, $0.12/share
- - - (9,260) (9,260)
Net income - - - 25,770 25,770
June 30, 2023 88 823,330 (113,768) 50,925 760,575
Shares withheld for payment of taxes on equity awards and other - (44) - - (44)
Stock based compensation - 3,243 - - 3,243
Dividends declared on common stock, $0.14/share
- (10,593) - - (10,593)
Net loss
- - - (45,062) (45,062)
September 30, 2023 $ 88 $ 815,936 $ (113,768) $ 5,863 $ 708,119
The accompanying notes are an integral part of these condensed consolidated financial statements.
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BERRY CORPORATION (bry)
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
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, $0.17/share
- - - (13,080) (13,080)
Net income
- - - 69,863 69,863
September 30, 2024 $ 89 $ 785,459 $ (113,768) $ 60,429 $ 732,209
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,
2024 2023
(in thousands)
Cash flows from operating activities:
Net income (loss)
$ 21,010 $ (25,151)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization 128,423 119,605
Amortization of debt issuance costs 2,126 1,952
Impairment of oil and gas properties 43,980 -
Stock-based compensation expense 4,676 11,336
Deferred income taxes 4,850 (10,397)
Other operating expenses
(2,135) 1,283
Derivative activities:
Total losses
16,508 48,901
Cash settlements (paid) received on derivatives
(38,606) 15,511
Changes in assets and liabilities:
Decrease in accounts receivable
12,414 11,644
Decrease (increase) in other assets
7,072 (3,820)
Decrease in accounts payable and accrued expenses
(48,819) (53,347)
Increase in other liabilities
17,360 2,122
Net cash provided by operating activities 168,859 119,639
Cash flows from investing activities:
Capital expenditures:
Capital expenditures (85,135) (56,124)
Changes in capital expenditures accruals 1,219 (10,431)
Acquisitions, net of cash received (9,188) (59,895)
Proceeds from sale of property and equipment and other 7,455 -
Net cash used in investing activities (85,649) (126,450)
Cash flows from financing activities:
Borrowings under 2021 RBL credit facility 502,500 387,000
Repayments on 2021 RBL credit facility (506,000) (330,000)
Dividends paid on common stock (46,719) (62,274)
Payment of deferred acquisition payable
(20,000) -
Purchase of treasury stock - (10,029)
Shares withheld for payment of taxes on equity awards and other (5,257) (6,936)
Debt issuance cost
(3,098) -
Net cash used in financing activities (78,574) (22,239)
Net increase (decrease) in cash and cash equivalents 4,636 (29,050)
Cash and cash equivalents:
Beginning 4,835 46,250
Ending $ 9,471 $ 17,200
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 ("Macpherson Energy") and its subsidiaries; (2) CJ Berry Well Services Management, LLC ("C&J Management") and (3) C&J Well Services, LLC, ("C&J," together with C&J Management, "CJWS"). As the context may require, the "Company," "we," "our" or similar words in this report refer to, Berry Corp., together with its subsidiaries, Berry LLC, C&J Management, and C&J.
Nature of Business
We are a 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. 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), while our Utah assets are in the Uinta basin (60% oil and 40% gas). We operate our well servicing and abandonment segment in California.
Principles of Consolidation and Reporting
The condensed consolidated financial statements were prepared in conformity with U.S. generally accepted accounting principles ("GAAP"), which requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. In management's opinion, the accompanying financial statements contain all normal, recurring adjustments that are necessary to fairly present our interim unaudited condensed consolidated financial statements. We eliminated all significant intercompany transactions and balances upon consolidation. For oil and gas 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 may not accurately forecast results for future periods. This Quarterly Report on Form 10-Q should be read in conjunction with the consolidated financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2023.
New Accounting Standards Issued, But Not Yet Adopted
In November 2023, the Financial Accounting Standards Board ("FASB") issued guidance to improve the reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. In addition, the guidance enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss and contains other disclosure requirements. The purpose of the guidance is to enable investors to better understand an entity's overall performance and assess potential future cash flows. The guidance is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. Adoption of this standard will result in additional disclosure, but will not impact the Company's consolidated financial position, results of operations or cash flows.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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 are currently evaluating the impact the new guidance will have on our consolidated financial statements Adoption of this standard will result in additional disclosure, but will not impact the Company's consolidated financial position, results of operations or cash flows.
Note 2-Debt
The following table summarizes our outstanding debt:
September 30,
2024 		December 31,
2023 		Interest Rate Maturity Security
(in thousands)
2021 RBL Facility
variable rates 10.25% (2024) and 10.50% (2023)
August 26, 2025
Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets
Long-term
$ - $ 31,000
Current
27,500 -
2022 ABL Facility - -
variable rates 9.25% (2024)
and 9.75% (2023)
June 5, 2027 CJWS property and certain other assets
2026 Notes 400,000 400,000 7.0% February 15, 2026 Unsecured
Debt - Principal Amount 427,500 431,000
Debt Issuance Costs (2,000) (3,007)
Current Portion of Debt (27,500) -
Long-Term Debt, net $ 398,000 $ 427,993
Deferred Financing Costs
We incurred legal and bank fees related to the issuance of debt. At September 30, 2024 and December 31, 2023, debt issuance costs reported in "other noncurrent assets" on the balance sheet were approximately (i) $2 million and $3 million, respectively, net of amortization, for the Credit Agreement, dated as of August 26, 2021, among Berry Corp, as a guarantor, Berry LLC, as the borrower, JPMorgan Chase Bank, N.A., as the administrative agent and an issuing bank, and each of the lenders from time to time party thereto (as amended, restated, modified or otherwise supplemented from time to time, the "2021 RBL Facility") and (ii) an immaterial amount, net of amortization, for the Revolving Loan and Security Agreement, dated as of August 9, 2022, among C&J and C&J Management, as borrowers, and Tri Counties Bank, as lender (as amended, restated, supplemented or otherwise modified from time to time, the "2022 ABL Facility"). At September 30, 2024 and December 31, 2023, debt issuance costs, net of amortization, for the unsecured notes due February 2026 (the "2026 Notes") reported in "Long-Term Debt, net" on the balance sheet were approximately $2 million and $3 million, respectively.
For each of the three month periods ended September 30, 2024 and 2023, the amortization expense for the 2021 RBL Facility, the 2022 ABL Facility and the 2026 Notes, combined, was approximately $1 million. For each of the nine month periods ended September 30, 2024 and 2023, the amortization expense for the 2021 RBL Facility, the 2022 ABL Facility and the 2026 Notes, combined, was approximately $2 million. 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 amounts of the 2021 RBL Facility and the 2022 ABL Facility approximate fair value because the interest rates are variable and reflect market rates. The 2021 RBL Facility and 2022 ABL Facility are Level 2 in the fair value hierarchy. The fair value of the 2026 Notes was approximately $388 million and $391 million at September 30, 2024 and December 31, 2023, respectively. The 2026 Notes are Level 1 in the fair value hierarchy and the fair value is based on available market pricing.
2021 RBL Facility
The 2021 RBL Facility provides for a revolving loan with up to $500 million of commitment, subject to a borrowing base and an aggregate elected commitment amount. The borrowing base under the 2021 RBL Facility is redetermined semi-annually, and the borrowing base redeterminations generally become effective each May and November, although the borrower and the lenders may each make one interim redetermination between scheduled redeterminations. On August 20, 2024, the scheduled semi-annual redetermination of the borrowing base occurred under the Credit Agreement, dated as of August 26, 2021 (as amended, supplemented or otherwise modified, the "Credit Agreement"), by and among Berry Corporation (bry) as a guarantor, Berry LLC, our wholly-owned subsidiary, as the borrower (the "Borrower"), JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto. In connection with such redetermination, the Borrower's borrowing base and aggregate elected committed amount are each $125 million (previously $200 million), effective as of the redetermination date. In accordance with the Credit Agreement, the next scheduled semi-annual borrowing base redetermination will be in or around November 2024.
As of September 30, 2024, the 2021 RBL Facility had a $500 million revolving commitment, a $125 million borrowing base, a $125 million aggregate elected commitment amount and a $20 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). Availability under the 2021 RBL Facility may not exceed the lesser of the aggregate elected commitment amount or the borrowing base less outstanding advances and letters of credit. The 2021 RBL Facility matures on August 26, 2025, unless terminated earlier in accordance with the terms of the 2021 RBL Facility. The 2021 RBL Facility is available to us for general corporate purposes, including working capital.
The outstanding borrowings under the 2021 RBL Facility bear interest at a rate equal to, at our option, either (a) a customary base rate plus an applicable margin ranging from 2.0% to 3.0% or (b) a term SOFR reference rate, plus an applicable margin ranging from 3.0% to 4.0%, in each case determined based on the utilization level under the 2021 RBL Facility. 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 six months, at the election of the borrower, and is payable on the last day of such interest period (or, for interest periods of six months, three months after the commencement of such interest period and at the end of such interest period). Unused commitment fees are charged at a rate of 0.50%.
The 2021 RBL Facility provides that, to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. In addition, the 2021 RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a leverage ratio of not more than 2.75 to 1.0 and (ii) a current ratio of not less than 1.0 to 1.0. As of September 30, 2024, we were in compliance with all of covenants under the 2021 RBL Facility.
The 2021 RBL Facility also contains other customary affirmative and negative covenants, as well as events of default and remedies. If we do not comply with the financial and other covenants in the 2021 RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the 2021 RBL Facility and terminate the commitments thereunder.
The 2021 RBL Facility is guaranteed by Berry Corp. and certain of its subsidiaries. Each future subsidiary of Berry Corp., with certain exceptions, is required to guarantee our obligations and obligations of the other guarantors under the 2021 RBL Facility and under certain hedging transactions and banking services arrangements. The lenders under the 2021 RBL Facility hold a mortgage on at least 90% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions. C&J and C&J Management do not guarantee the 2021 RBL Facility or grant any liens on their assets to secure any obligations under the 2021 RBL Facility.
On July 30, 2024, we entered into a letter agreement to amend the 2021 RBL Facility to extend the permitted tenor of certain commodity hedging agreements which we may enter into, from a tenor not to exceed 48 months to a tenor not to exceed 60 months.
As of September 30, 2024, we had $28 million borrowings outstanding, $9 million in letters of credit outstanding and approximately $88 million of available borrowing capacity under the 2021 RBL Facility. Under the terms of the 2024 Term Loan Agreement, the 2021 RBL Facility will be terminated upon funding of the 2024 Term Loan.
2022 ABL Facility
Subject to satisfaction of customary conditions precedent to borrowing, as of September 30, 2024, C&J and C&J Management could borrow up to the lesser of (x) $10 million and (y) the borrowing base under the 2022 ABL Facility, with a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $7.5 million (with borrowing availability being reduced by the face amount of any letters of credit issued under the subfacility). The "borrowing base" is an amount equal to 80% of the balance due on eligible accounts receivable, subject to reserves that the lender may implement in its reasonable discretion. As of September 30, 2024, the borrowing base was $10 million. Interest on the outstanding principal amount of the revolving loans under the 2022 ABL Facility accrues at a per annum rate equal to 1.25% in excess of the variable rate of interest, on a per annum basis, which is announced and/or published in the "Money Rates" section of The Wall Street Journal from time to time as its "Prime Rate". Interest is due quarterly, in arrears. In June 2024, we entered into the Third Amendment to Revolving Loan and Security Agreement and Amendment to Other Loan Documents which, among other things, extended the maturity of the 2022 ABL Facility from June 5, 2025 to June 5, 2027, unless terminated earlier in accordance with the terms of the 2022 ABL Facility.
The 2022 ABL Facility requires C&J and C&J Management to comply with the following financial covenants: (i) maintain on a consolidated basis a ratio of total liabilities to tangible net worth of no greater than 1.5 to 1.0 at any time; (ii) reduce the amount of revolving advances outstanding under the 2022 ABL Facility to not more than 90% of the lesser of (a) the maximum revolving advance amount or (b) the borrowing base, as of the lender's close of business on the last day of each fiscal quarter; and (iii) maintain net income before taxes of not less than $1.00 as of each fiscal year end. As of September 30, 2024, each of C&J and C&J Management was in compliance with all of the covenants under the 2022 ABL Facility.
The 2022 ABL Facility also contains other customary affirmative and negative covenants, as well as events of default and remedies. If C&J or C&J Management does not comply with the financial and other covenants in the 2022 ABL Facility, the lender may, subject to customary cure rights, require immediate payment of all amounts outstanding under the 2022 ABL Facility and terminate the commitment thereunder. The obligations of C&J and C&J Management under the 2022 ABL Facility are guaranteed by C&J Management and C&J, respectively, and are secured by liens on substantially all of the personal property of C&J and C&J Management, subject to customary exceptions. The obligations of C&J and C&J Management under the 2022 ABL Facility are not guaranteed by Berry Corp. or Berry LLC and Berry Corp. and Berry LLC do not and are not required to provide any credit support for such obligations.
As of September 30, 2024, each of C&J and C&J Management had no borrowings and $3 million letters of credit outstanding with $7 million of available borrowing capacity under the 2022 ABL Facility. Under the terms of the 2024 Term Loan Agreement, the 2022 ABL Facility will be terminated upon funding of the 2024 Term Loan.
Senior Unsecured Notes Due February 2026
In February 2018, Berry LLC completed a private issuance of $400 million in aggregate principal amount of 7.0% senior unsecured notes due February 2026, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers' discount.
The 2026 Notes are Berry LLC's senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The 2026 Notes are fully and unconditionally guaranteed on a senior unsecured basis by Berry Corp and certain of its subsidiaries. C&J and C&J Management do not guarantee the 2026 Notes.
The indenture governing the 2026 Notes contains customary covenants and events of default (in some cases, subject to grace periods). We were in compliance with all covenants under the 2026 Notes as of September 30, 2024.
In conjunction with and subject to the closing of the 2024 Term Loan Credit Agreement discussed below, the Company is required to redeem the 2026 Notes. This report does not constitute a notice of redemption of the 2026 Notes.
2024 Term Loan Credit Agreement
Subsequent to the end of the third quarter of 2024, but before the issuance date of these financials, the Company entered into a Senior Secured Term Loan Credit Agreement (the "2024 Term Loan Credit Agreement") among the Company, as borrower, certain subsidiaries of the Company, as guarantors, Breakwall Credit Management LLC, as administrative agent, and the lenders from time to time party thereto.
The 2024 Term Loan Credit Agreement provides for aggregate commitments equal to $545 million, consisting of (i) an initial term loan facility in the aggregate principal amount of $450 million (the "Initial Term Loans"), and (ii) a delayed draw term loan facility in an aggregate principal amount of up to $95 million which is available from the date of the first borrowing of the Initial Term Loans (the "Funding Date") until the date that is two years after the effectiveness of the 2024 Term Loan Credit Agreement (the "Working Capital Term Loan Facility"). The ability of the Company to borrow under the 2024 Term Loan Credit Agreement, including to refinance the 2026 Notes, 2021 RBL Facility, and the 2022 ABL Facility, is subject to satisfaction of certain customary conditions precedent, as further set forth in the 2024 Term Loan Credit Agreement, including (a) the repayment and termination of liens under each of the 2021 RBL Facility and 2022 ABL Facility and (b) satisfaction and discharge of the 2026 Notes. The proceeds of the Initial Term Loans are limited in their use to the satisfaction and discharge of existing debt, payment of fees and expenses in connection with the 2024 Term Loan Credit Agreement and other related transactions, capital expenditures in accordance with the 2024 Term Loan Credit Agreement, working capital, and other general corporate purposes. A requirement of funding the Initial Term Loans is (a) the contemporaneous termination of the 2022 ABL Facility and the 2021 RBL Facility, including satisfaction and discharge of any remaining balances thereon and (b) the satisfaction and discharge of the 2026 Notes.
The 2024 Term Loan Credit Agreement will have an initial maturity date of three years from the Funding Date, which may be extended by up to two one-year increments subject to payment of extension fees, and satisfaction of certain other customary conditions. Quarterly debt service payments of an amount equal to the sum of 2.5% of (a) the face value of the Initial Term Loan and (b) the aggregate amount of delayed draws made from the Working Capital Term Loan Facility are required beginning in March 2025.
Loans under the 2024 Term Loan Credit Agreement will bear interest at a rate per annum equal to Term SOFR (as defined in the 2024 Term Loan Credit Agreement) plus an applicable margin of 7.50%. If an Event of Default (as defined in the 2024 Term Loan Credit Agreement) exists and is continuing, upon the election of the Majority Lenders (as defined in the 2024 Term Loan Credit Agreement) under the 2024 Term Loan Credit Agreement, or automatically without such election, in the case of a bankruptcy, insolvency, or payment default, all amounts outstanding under the 2024 Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto (it being understood that the 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 Company will be able to repay any amounts borrowed prior to the maturity date (i) without any premium for any optional prepayment on or prior to the date that is 24 months after the Funding Date and (ii) thereafter, subject to a concurrent payment of 2.75% of the principal amount being repaid.
On the Funding Date, the 2024 Term Loan Credit Agreement will be guaranteed by the Company and all of its wholly owned subsidiaries and will be secured by a first lien security interest in substantially all assets of the Company and all of its wholly owned subsidiaries.
The 2024 Term Loan Credit Agreement allows the Company to replace the commitments and outstanding borrowings under the Working Capital Term Loan Facility with a super-priority reserve based credit facility of up to $95 million (the "New RBL Facility"), subject to terms and conditions set forth therin, including the entry by the Company and the subsidiaries of the Company party thereto into of an intercreditor agreement, as more fully described in the 2024 Term Loan Credit Agreement.
The 2024 Term Loan Credit Agreement also contains certain financial covenants, including (a) minimum liquidity of $25 million as of the last day of any calendar month and (b) commencing with the fiscal quarter ending March 31, 2025, (i) a total net leverage ratio that may not exceed 2.5 to 1.0 and (ii) an asset coverage ratio that may not be less than 1.3 to 1.0 as of the last day of any fiscal quarter, in each case, as fully more described in the 2024 Term Loan Credit Agreement.
Additionally, the 2024 Term Loan Credit Agreement contains additional restrictive covenants that (i) from and after the effective date thereof, 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, and sell assets, and (ii) from and after the Funding Date, will limit the ability of the Company and its subsidiaries to, among other things, incur additional indebtedness (with such exceptions including the New RBL Facility), incur additional liens, enter into certain hedging transactions, engage in transactions with affiliates and make certain capital expenditures.
In addition, the 2024 Term Loan Credit Agreement 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, the administrative agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments and exercise remedies against any collateral.
The 2024 Term Loan Credit Agreement became effective on November 6, 2024 (the "Closing").
The foregoing description of the 2024 Term Loan Credit Agreement is qualified in its entirety by reference to the 2024 Term Loan Credit Agreement, a copy of which is attached hereto as Exhibit 10.1 and is incorporated by reference.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 3-Derivatives
We utilize derivatives, such as swaps, puts, calls and collars, to hedge a portion of our forecasted oil and gas production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices, which addresses our market risk. In addition to satisfying the oil hedging requirements of the 2021 RBL Facility, which specifies the volume and types of our hedges, we target covering our operating expenses and a majority of our fixed charges, which includes capital needed to sustain production levels, as well as interest and fixed dividends as applicable, with the oil and gas sales hedges generally for a period of up to three years out. At times, we will hedge beyond three years when strike prices appear to satisfy anticipated costs in those years. Additionally, we target fixing the price for a large portion of our natural gas purchases used in our steam operations for up to three years. We have also entered into gas transportation contracts to help reduce the price fluctuation exposure, however these do not qualify as hedges. We also, from time to time, have entered into agreements to purchase a portion of the natural gas we require for our operations, which we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions. We had no such transactions in the periods presented.
Oil Sales Hedges
For fixed-price sales swaps, we are the seller, so we make settlement payments for prices above the indicated weighted-average price per bbl and per mmbtu, respectively, and receive settlement payments for prices below the indicated weighted-average price per bbl and per mmbtu, respectively.
For our sold call options, we would make settlement payments for prices above the indicated weighted-average price per barrel, net of any deferred premium. No payment would be made or received for prices below the indicated weighted-average price per barrel, other than any applicable deferred premium.
For our purchased puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel, net of any deferred premium. No payment would be made or received for prices above the indicated weighted-average price per barrel, other than any applicable deferred premium.
For our sold puts, we would make settlement payments for prices below the indicated weighted-average price per barrel, net of any deferred premium. No payment would be made or received for prices above the indicated weighted-average price per barrel, other than any applicable deferred premium.
Gas Purchase Hedges
For fixed-price gas purchase swaps, we are the buyer, so we make settlement payments for prices below the indicated weighted-average price per mmbtu and receive settlement payments for prices above the indicated weighted-average price per mmbtu.
For some of our options we paid or received a premium at the time the positions were created and for others, the premium payment or receipt is deferred until the time of settlement. As of September 30, 2024, we have net payable deferred premiums of less than $1 million, which is reflected in the mark-to-market valuation and will be payable through December 31, 2024.
We use oil and gas production hedges to protect our sales against decreases in oil and gas prices. We also use natural gas purchase hedges to protect our natural gas purchases against increases in prices. We do not enter into derivative contracts for speculative trading purposes and have not accounted for our derivatives as cash-flow or fair-value hedges. The changes in fair value of these instruments are recorded in current earnings. Gains (losses) on oil and gas sales hedges are classified in the revenues and other section of the statement of operations, while natural gas purchase hedges are included in expenses and other section of the statement of operations.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
As of September 30, 2024, we had the following crude oil production and gas purchases hedges.
Q4 2024
FY 2025 FY 2026
FY 2027
FY 2028
FY 2029
Brent - Crude Oil production
Swaps
Hedged volume (bbls) 1,438,656 4,951,125 2,633,268 3,056,000 2,378,000 724,000
Weighted-average price ($/bbl) $ 76.93 $ 76.06 $ 71.76 $ 70.66 $ 68.36 $ 67.44
Sold Calls(1)
Hedged volume (bbls) 92,000 296,127 1,251,500 318,500 - -
Weighted-average price ($/bbl) $ 105.00 $ 88.69 $ 85.53 $ 80.03 $ - $ -
Purchased Puts (net)(2)
Hedged volume (bbls) 322,000 - - - - -
Weighted-average price ($/bbl) $ 50.00 $ - $ - $ - $ - $ -
Purchased Puts (net)(2)
Hedged volume (bbls) - 296,127 1,251,500 318,500 - -
Weighted-average price ($/bbl) $ - $ 60.00 $ 60.00 $ 65.00 $ - $ -
Sold Puts (net)(2)
Hedged volume (bbls) 46,000 - - - - -
Weighted-average price ($/bbl) $ 40.00 $ - $ - $ - $ - $ -
NWPL - Natural Gas purchases(3)
Swaps
Hedged volume (mmbtu) 3,680,000 13,380,000 3,040,000 - - -
Weighted-average price ($/mmbtu) $ 3.96 $ 4.27 $ 4.26 $ - $ - $ -
__________
(1) Purchased calls and sold calls with the same strike price have been presented on a net basis.
(2) Purchased puts and sold puts with the same strike price have been presented on a net basis.
(3) The term "NWPL" is defined as Northwest Rocky Mountain Pipeline.
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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, 2024 and December 31, 2023:
September 30, 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 $ 33,422 $ (16,110) $ 17,312
Commodity Contracts Non-current assets 23,225 (18,427) 4,798
Liabilities:
Commodity Contracts Current liabilities (16,110) 16,110 -
Commodity Contracts Non-current liabilities (18,427) 18,427 -
Total derivatives $ 22,110 $ - $ 22,110
December 31, 2023
Balance Sheet
Classification 		Gross Amounts
Recognized at Fair Value 		Gross Amounts Offset
in the Balance Sheet 		Net Fair Value Presented
in the Balance Sheet
(in thousands)
Assets:
Commodity Contracts Current assets $ 26,230 $ (20,942) $ 5,288
Commodity Contracts Non-current assets 28,992 (23,529) 5,463
Liabilities:
Commodity Contracts Current liabilities (30,723) 20,942 (9,781)
Commodity Contracts Non-current liabilities (24,488) 23,529 (959)
Total derivatives $ 11 $ - $ 11
By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We do not receive collateral from our counterparties.
We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, our 2021 RBL Facility prevents us from entering into hedging arrangements that are secured, except with our lenders and their affiliates, 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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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Gains (Losses) on Derivatives
Three Months Ended
September 30,
Nine Months Ended
September 30,
2024 2023 2024 2023
(in thousands)
Realized (losses) gains on commodity derivatives:
Realized (losses) on oil sales derivatives
$ (2,907) $ (12,304) $ (17,390) $ (21,512)
Realized (losses) gains on natural gas purchase derivatives
(7,490) (7,128) (21,216) 37,023
Total realized (losses) gains on derivatives $ (10,397) $ (19,432) $ (38,606) $ 15,511
Unrealized gains (losses) on commodity derivatives:
Unrealized gains (losses) on oil sales derivatives
$ 78,341 $ (90,977) $ 15,780 $ (22,399)
Unrealized (losses) gains on natural gas purchase derivatives
(285) 15,552 6,318 (42,013)
Total unrealized gains (losses) on derivatives
$ 78,056 $ (75,425) $ 22,098 $ (64,412)
Total gains (losses) on derivatives
$ 67,659 $ (94,857) $ (16,508) $ (48,901)
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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 for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at September 30, 2024 and December 31, 2023. 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, 2024, we are not aware of material indemnity claims pending or threatened against us.
Securities Litigation Matters
In November 2020, a putative securities class action (the "Securities Class Action") was filed in the United States District Court for the Northern District of Texas, claiming that Berry Corp. and certain of its current and former directors and officers violated the Securities Act of 1933 and the Exchange Act of 1934 by allegedly making 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.
While the motion for class certification was still pending before the court, the parties reached an agreement-in-principle to settle all claims in the Securities Class Action for an aggregate sum of $2.5 million. Following notice to the class and an opt-out and objection process, the Court granted final approval of the settlement on February 6, 2024, and terminated the case. The Defendants continue to maintain that the claims were without merit and admitted no liability in connection with the settlement.
While the Securities Class Action is now concluded, certain related shareholder derivative actions remain pending. 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 piggy-backs on the Securities Class Action and is currently pending before the same court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the Securities Class Action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27, 2023, the court granted the parties' joint stipulated request to stay the Assad Lawsuit pending resolution of the Securities Class Action.
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, again piggy-backing on the Securities Class Action. This complaint, 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 securities violations alleged in the Securities Class Action. In addition, the complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry's 2022 proxy statement was false and misleading in that it suggested the Company's internal controls were sufficient and the Board of Directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case. On February 13, 2023, the court granted the parties' joint stipulated request to stay the Karp Lawsuit pending further developments in the Securities Class Action.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The settlement of the Securities Class Action did not resolve the Shareholder Derivative Actions, which remain pending. The defendants continue to believe the claims in the Shareholder Derivative Actions are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to these matters.
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.
Commitments
We have entered into contracts to purchase GHG compliance instruments totaling $22 million, of which $6 million was delivered and paid in October 2024. The remaining amount of $16 million of these instruments will be delivered and paid in 2025.
Note 5-Equity
Cash Dividends
In the first quarter of 2024, our Board of Directors declared a fixed cash dividend of $0.12 per share, as well as a variable cash dividend of $0.14 per share which was based on the results of the fourth quarter of 2023, for a total of $0.26 per share, which we paid in March 2024. In April 2024, the Board of Directors approved a fixed cash dividend totaling $0.12 per share, which was paid in May 2024. In July 2024, the Board of Directors approved a fixed cash dividend of $0.12 per share and a variable cash dividend of $0.05 per share, based on the results for the six months ended June 30, 2024, for a total of $0.17 per share, which was paid in August 2024. In October 2024, the Board of Directors approved a fixed cash dividend of $0.03 which is expected to be paid in November 2024.
Stock Repurchase Program
The Company did not repurchase any shares during the three and nine months ended September 30, 2024. As of September 30, 2024, the Company had repurchased a total of 11.9 million shares, cumulatively, under the stock repurchase program for approximately $114 million in aggregate.
As of September 30, 2024, 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.
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.
Stock-Based Compensation
In March 2024, pursuant to the Company's 2022 Omnibus Incentive Plan, the Company granted (i) approximately 1,328,000 restricted stock units ("RSUs"), which will vest annually in equal amounts over three years or, in the case of directors, on March 1, 2025, and (ii) a target number of approximately 406,000 performance-based restricted stock units ("PSUs"), which will cliff vest at the end of a three-year performance period, at the earned performance level. The fair value of these RSU and PSU awards was approximately $13 million.
The RSUs awarded in March 2024 are solely time-based awards. Of the PSUs awarded in March 2024, (a) 50%
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
of such will vest, if at all, at the earned performance level, based on the Company's absolute total stockholder return ("TSR") performance metric, which is defined as the capital gains per share of stock plus cumulative dividends and (b) 50% of such will vest, if at all, at the earned performance level, based on the relative TSR performance metric, which is defined as the capital gains per share of stock plus cumulative dividends, with TSR measured on a relative basis to the TSR of the 47 exploration and production companies in the Vanguard World Fund - Vanguard Energy ETF Index plus the S&P SmallCap 600 Value Index (collectively, the "Peer Group") during the performance period. Depending on the results achieved during the three-year performance period, the actual number of shares 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 relative TSR award and the value of the absolute TSR award. The historical volatility was determined at the date of grant for the Company and for each company in the peer group. 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.
Note 6-Supplemental Disclosures to the Financial Statements
Other current assets reported on the condensed consolidated balance sheets included the following:
September 30, 2024 December 31, 2023
(in thousands)
Prepaid expenses $ 7,178 $ 12,330
Materials and supplies 13,084 17,021
Deposits 9,055 9,012
Oil inventories 4,341 4,098
Other 1,881 1,298
Total other current assets $ 35,539 $ 43,759
Noncurrent assets
Other noncurrent assets at September 30, 2024 was approximately $11 million, which mainly included $6 million of operating lease right-of-use assets, net of amortization and $5 million of deferred financing costs, net of amortization. At December 31, 2023, other non-current assets was approximately $11 million, which included $8 million of operating lease right-of-use assets, net of amortization and $3 million of deferred financing costs, net of amortization.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Accounts payable and accrued expenses on the condensed consolidated balance sheets included the following:
September 30, 2024 December 31, 2023
(in thousands)
Accounts payable - trade $ 20,231 $ 31,184
Deferred acquisition payable(1)
- 18,999
Accrued expenses 53,246 55,663
Royalties payable 22,444 28,179
Greenhouse gas liability - current portion(2)
8,323 37,945
Taxes other than income tax liability 12,579 6,488
Accrued interest 5,036 11,999
Asset retirement obligations - current portion 20,000 20,000
Operating lease liability 2,327 2,944
Total accounts payable and accrued expenses $ 144,186 $ 213,401
__________
(1) The deferred consideration of $20 million for the acquisition of Macpherson Energy was paid in July 2024.
(2) The current portion of greenhouse gas liability will be settled in the fourth quarter of 2024.
Noncurrent liabilities
The increase of approximately $2 million in the long-term portion of the asset retirement obligations from $177 million at December 31, 2023 to $178 million at September 30, 2024 was due to $9 million of accretion expense and $2 million of liabilities incurred, largely offset by $9 million of liabilities settled during the period.
Other noncurrent liabilities at September 30, 2024 was approximately $33 million, which included approximately $29 million of greenhouse gas liability, and $4 million of operating lease noncurrent liability. At December 31, 2023, other noncurrent liabilities was approximately $5 million, which was operating lease noncurrent liability.
Supplemental Information on the Statement of Operations
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, 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. For the nine months ended September 30, 2023, other operating income was $2 million, and mainly consisted of net property tax refunds from prior periods and a net gain on equipment sales.
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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,
2024 2023
(in thousands)
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Deferred consideration payable for acquisition(1)
$ - $ 18,499
Material inventory transfers to oil and natural gas properties $ 3,937 $ 1,300
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized $ 32,825 $ 30,457
Income taxes payments $ 2,777 $ 2,757
__________
(1) The deferred consideration of $20 million for the acquisition of Macpherson Energy was paid in July 2024.
Note 7-Acquisition and Divestiture
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 will be 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 paid $20 million in deferred consideration for the acquisition of Macpherson Energy. No additional payments are required.
In July 2024, we also completed the sale of CJWS' storage facility in Ventura, California for approximately $7 million in net cash proceeds for a gain of $5 million which is included in other operating (income) expenses on the statement of operations.
During 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, also located in Duchesne County, Utah. We will receive 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.
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BERRY CORPORATION (bry)
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, 2024, 121,000 and 191,000 RSU and PSU shares were included in the diluted EPS calculation, respectively. For the three and nine months ended September 30, 2023, no RSU or PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the "if converted" method
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2024 2023 2024 2023
(in thousands except per share amounts)
Basic EPS calculation
Net income (loss)
$ 69,863 $ (45,062) $ 21,010 $ (25,151)
Weighted-average shares of common stock outstanding 76,939 75,662 76,712 76,163
Basic income (loss) per share
$ 0.91 $ (0.60) $ 0.27 $ (0.33)
Diluted EPS calculation
Net income (loss)
$ 69,863 $ (45,062) $ 21,010 $ (25,151)
Weighted-average shares of common stock outstanding 76,939 75,662 76,712 76,163
Dilutive effect of potentially dilutive securities(1)
121 - 191 -
Weighted-average common shares outstanding - diluted 77,060 75,662 76,903 76,163
Diluted income (loss) per share
$ 0.91 $ (0.60) $ 0.27 $ (0.33)
__________
(1) We excluded approximately 1.9 million of combined RSUs and PSUs from the dilutive weighted-average common shares outstanding for each of the three and nine months ended September 30, 2023 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. Revenue from CJWS is generated from well servicing and abandonment business.
The following table provides disaggregated revenue for the three and nine months ended September 30, 2024 and 2023:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2024 2023 2024 2023
(in thousands)
Oil sales $ 151,735 $ 168,491 $ 480,953 $ 475,138
Natural gas sales 1,751 3,130 5,910 19,083
Natural gas liquids sales 952 990 2,674 2,450
Service revenue(1)
25,465 45,511 88,303 137,808
Electricity sales 4,410 3,849 12,344 12,372
Other revenues 37 113 140 194
Revenues from contracts with customers 184,350 222,084 590,324 647,045
Gains (losses) gains on oil and gas sales derivatives
75,434 (103,282) (1,610) (43,912)
Total revenues and other $ 259,784 $ 118,802 $ 588,714 $ 603,133
__________
(1) The well servicing and abandonment segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $31 million and $47 million and the intercompany elimination was $5 million and $2 million for the three months ended September 30, 2024 and 2023, respectively. Prior to the intercompany elimination, service revenue was approximately $103 million and $143 million and the intercompany elimination was $15 million and $5 million for the nine months ended September 30, 2024 and 2023, 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.
We evaluate the impairment of our unproved oil and gas properties on a property-by-property basis whenever events or changes in circumstances indicate the carrying value may not be recoverable. If exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions, 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.
An impairment triggering event occurred as of June 2024 as a result of the following legislative events. On September 16, 2022, the California Governor signed into law Senate Bill No. 1137 (SB 1137) which prohibits CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or rework is within 3,200 feet of certain sensitive receptors such as homes, schools or parks. The law originally became effective January 1, 2023. However, in December 2022, proponents of a voter referendum (the "Referendum") collected more than the number of signatures required to put SB 1137 on the November 2024 ballot. On February 3, 2023, the Secretary of State of California certified the signatures and confirmed that the Referendum qualified for the November 2024 ballot. SB 1137 was stayed pending a vote of the California General Election in November 2024,
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
however, in June 2024, the ballot proposal was withdrawn with the proposal's sponsors instead indicating a view to challenging SB 1137 in court and the provisions of SB 1137 then became effective immediately. SB 1137 prohibits the issuance of well permits and the construction and operation of new production facilities within a health protection zone of 3,200 feet from a sensitive receptor, as defined in the regulation. However, on September 30, 2024, the Governor signed into law Senate Bill No. 218 (SB 218), which delays the deadline for compliance with CalGEM's regulations implementing SB 1137 until July 1, 2026 and further delays compliance with certain other requirements of AB 1137 by up to three years.
As a result of SB 1137 previously going into effect as of June 2024, in the second quarter of 2024 we identified a triggering event that required assessment with respect to our proved and unproved oil and gas properties. This event also triggered the reassessment of the DD&A rate of certain proved properties, which was adjusted as of the triggering event date. This legislation impacts our ability to develop proved undeveloped reserves and our unproved acreage as planned. Our assessment of the triggering event for proved property impairment did not indicate that after consideration of the impact of SB 1137 it was more likely than not that the associated costs would be recoverable as of June 30, 2024. We believe our current plans and exploration and development efforts will allow us to realize the carrying value of our proved property balance. Our assessment of the triggering event for unproved property cost impairment indicated, however that portions of our capitalized unproved costs would not be recoverable given their proximity to sensitive receptors. Consequently, we recorded a non-cash pre-tax asset impairment charge of $44 million, $33 million after-tax on unproved oil and gas properties in certain California locations during the second quarter of 2024. The impairment represented approximately 2% of our total oil and natural gas properties in the E&P segment as of the impairment date.
As of September 30, 2024, no triggering events were identified for proved or unproved property costs.
Note 11-Segment Information
We operate in two business segments: (i) E&P and (ii) well servicing and abandonment. 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 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.
The well servicing and abandonment segment provides services to our E&P segment, as such, we recorded an intercompany elimination of $5 million and $15 million in revenue and expense during consolidation for the three and nine months ended September 30, 2024. The intercompany elimination was $2 million and $5 million for the three and nine months ended September 30, 2023.
The following table represents selected financial information for the periods presented regarding the Company's business segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis.
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BERRY CORPORATION (bry)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Three Months Ended
September 30, 2024
E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company
(in thousands)
Revenues(1)
$ 158,886 $ 30,836 $ (5,372) $ 184,350
Net income (loss) before income taxes $ 118,271 $ 2,748 $ (26,724) $ 94,295
Capital expenditures $ 24,793 $ 498 $ 583 $ 25,874
Total assets $ 1,545,517 $ 56,528 $ (84,897) $ 1,517,148
Three Months Ended
September 30, 2023
E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company
(in thousands)
Revenues(1)
$ 176,573 $ 47,259 $ (1,748) $ 222,084
Net income (loss) before income taxes
$ (35,485) $ 3,295 $ (28,215) $ (60,405)
Capital expenditures $ 10,833 $ 2,104 $ 659 $ 13,596
Total assets $ 1,604,253 $ 71,891 $ (62,219) $ 1,613,925
Nine Months Ended
September 30, 2024
E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company
(in thousands)
Revenues(1)
$ 502,022 $ 102,984 $ (14,682) $ 590,324
Net income (loss) before income taxes
$ 107,295 $ 2,601 $ (81,680) $ 28,216
Capital expenditures $ 81,945 $ 2,298 $ 892 $ 85,135
Total assets $ 1,545,517 $ 56,528 $ (84,897) $ 1,517,148
Nine Months Ended
September 30, 2023
E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company
(in thousands)
Revenues(1)
$ 509,237 $ 142,921 $ (5,113) $ 647,045
Net income (loss) before income taxes
$ 50,697 $ 10,245 $ (93,733) $ (32,791)
Capital expenditures $ 49,730 $ 4,420 $ 1,974 $ 56,124
Total assets $ 1,604,253 $ 71,891 $ (62,219) $ 1,613,925
__________
(1) These revenues do not include hedge settlements.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") should be read in conjunction with our interim unaudited consolidated financial statements and related notes presented in this Quarterly Report on Form 10-Q (the "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, 2023 (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. 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), while our Utah assets are in the Uinta basin (60% oil and 40% gas). We operate our well servicing and abandonment segment in California.
With respect to our E&P business in California, we focus on conventional, shallow oil reservoirs. The drilling and completion of such wells 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. In September 2023, we completed the acquisition of Macpherson Energy (so called, or the "Macpherson Acquisition"), a privately held Kern County, California operator. The acquired assets are high-quality, low decline oil producing properties that are closely located to existing Berry properties in rural Kern County, California. In December 2023 and in the second quarter of 2024, we acquired additional, highly synergistic working interests in Kern County, California. These assets align with our strategy of acquiring accretive, producing bolt-ons in support of our goal to maintain flat production year-over-year.
We have upstream assets in Utah, located in the Uinta basin, which produce oil and natural gas at depths ranging from 4,000 feet to 8,000 feet. We have high operational control of our existing acreage, which provides significant upside for additional development and recompletions. As of September 30, 2024, we held approximately 99,000 net acres in the Uinta basin. Over the last year, the Uinta basin has experienced an increase in activity, including successful results from horizontal drilling across the basin which indicates new development potential for our existing acreage. Our historic Uinta basin development has focused on vertical production from five reservoirs and we are now actively evaluating horizontal drilling potential. In April 2024, we purchased 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 are better than 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 will receive 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, these wells are adjacent to our existing operations, and the results from all of these farmed-in horizontal wells will be used to evaluate opportunities on our own acreage. We believe horizontal well development of our own acreage could be a substantial opportunity, with low break-even economics and a runway of future development in the increasingly active Uinta basin. With a high working interest in our 99,000 acres and the majority of acreage held by production, we are strategically positioned to develop our own acreage horizontally at an optimal pace, staying true to our commitment to generate free cash flow. We believe doing so has the potential to unlock all of our Uinta net acres while allowing us to maintain disciplined financial policies.
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In our well servicing and abandonment segment, we operate one of the largest upstream well servicing and abandonment businesses in California, which operates as C&J. C&J provides wellsite services in California to oil and natural gas production companies, including well servicing and water logistics. Additionally, C&J performs plugging and abandonment services on wells at the end of their productive life, which we believe has upside opportunity based on the significant inventory of idle wells within California coupled with existing and new regulations that are expected to increase the obligations of operators with respect to those idle wells. C&J also provides a competitive advantage to Berry by providing access and control over an important part of our supply chain.
We believe that the successful execution of our strategy across our low-declining, oil-weighted production base, coupled with extensive inventory of identified drilling, sidetrack and workover locations with attractive full-cycle economics, will support our objectives to maintain production levels year-over-year and generate free cash flow, which funds our operations, optimizes capital efficiency and maximizes enterprise value. We also strive to maintain an appropriate liquidity position and manageable leverage profile that will enable us to explore attractive organic and strategic growth through commodity price cycles and acquisitions. In addition to operating and developing our existing world-class assets efficiently and strategically under the highest compliance standards, we seek to acquire accretive, producing bolt-on properties that complement our existing operations, enhance our cash flows and allow us to further our strategy of maintaining production levels year-over-year, subject to delays in the issuance of necessary permits and approvals. For more information, see Part I, Items 1 and 2. "Business and Properties-Regulatory Matters-Regulation of the Oil and Gas Industry" in our Annual Report. Our strategy includes proactively engaging the many forces driving our industry and impacting our operations, whether positive or negative, to maximize the utility of our assets, create value for shareholders, and support environmental goals that align with safer, more efficient and lower emission operations.
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 field operations measures; (e) HSE results; (f) general and administrative expenses; and (g) the performance of our well servicing and abandonment 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 the operating performance of both our E&P business and CJWS. 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 2021 RBL Facility and 2024 Term Loan Credit Agreement (as defined below). 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
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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.
We previously reported Adjusted Free Cash Flow, a non-GAAP measure, and made allocations of Adjusted Free Cash Flow in connection with our shareholder return model, most recently (a) 80% primarily in the form of debt repurchases, stock repurchases, strategic growth, and acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends. However, in October 2024, in anticipation of entering into the 2024 Term Loan Credit Agreement, we transitioned away from the shareholder return model to a more flexible approach to capital allocation that aligns with the covenants contained in the 2024 Term Loan Credit Agreement and prioritizes debt reduction while facilitating our operating strategy and enabling investment in development opportunities. For a discussion and presentation of Adjusted Free Cash Flow for the prior period, see our previous filings with the SEC.
Production
Oil and gas production is a key driver of our operating performance, an important factor to the success of our business, and used in forecasting future development economics. We measure and closely monitor production on a continuous basis, adjusting our property development efforts in accordance with the results. We track production by commodity type and compare it to prior periods and expected results.
E&P Field Operations
Overall, management assesses the efficiency of our E&P field operations by considering core E&P operating expenses together with our cogeneration, marketing and transportation activities. In particular, a core component of our E&P operations in California is steam, which we use to lift heavy oil to the surface. We operate several cogeneration facilities to produce some of the steam needed in our operations. In comparing the cost effectiveness of our cogeneration plants against other sources of steam in our operations, management considers the cost of operating the cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the steam and electricity used in our E&P field operations and the revenues we receive from sales of excess electricity to the grid. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural gas purchase hedges. Consequently, the efficiency of our E&P field 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. With respect to transportation and marketing, management also considers opportunistic sales of incremental capacity in assessing the overall efficiencies of E&P operations.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Electricity generation expenses include the portion of fuel, labor, maintenance, and tools and supplies from two of our cogeneration facilities allocated to electricity generation expense; the remaining cogeneration expenses are included in lease operating expense. Transportation expenses relate to our costs to transport the oil and gas that we produce within our properties or move it to the market. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then sold to third parties. Electricity revenue is from the sale of excess electricity from two of our cogeneration facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are sized to satisfy the steam needs in their respective fields, but the corresponding electricity produced is more than the electricity that is currently required for the operations in those fields. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and marketing revenues represent sales of natural gas purchased from and sold to third parties.
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Health, Safety & Environmental
Like other companies in the oil and gas industry, the operations of both our E&P business and C&J 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 Operations Performance
We consistently monitor our well servicing and abandonment operations performance with revenue and cost by service and customer, as well as Adjusted EBITDA for this business.
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Business Environment, Market Conditions and Outlook
Our operating and financial results, and those of the oil and gas industry as a whole, are heavily influenced by commodity prices, 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. 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.
Our well servicing and abandonment 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. Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells historically have been relatively stable and predictable when production is steady. Additionally, our customers' requirements to plug and abandon wells are largely driven by regulatory requirements that are less dependent on commodity prices.
The price of oil is impacted by the actions of OPEC+ and recently they have implemented production cuts to address global supply levels. In June 2024, OPEC+ extended the reduced production quotas of 3.66 mmbbls/d through the end of 2025 and extended the 2.2 mmbbls/d voluntary cuts through the end of September 2024. In September 2024, OPEC+ agreed to extend their additional voluntary production cuts of 2.2 mmbbls/d for two months until the end of November 2024, after which these cuts will be gradually phased out on a monthly basis starting December 1st, 2024. Through the end of September, oil prices declined in 2024, but experienced an increase in early October 2024 due to increased geopolitical tension in the Middle East.
Sanctions and import bans on Russian oil have been implemented by various countries in response to the ongoing conflict in Ukraine, further altering flows of global oil supply. Oil and natural gas prices could decrease or increase with any changes in demand due to, among other things, the ongoing conflict in Ukraine, the ongoing conflict in the Middle East, international sanctions, speculation as to future actions by OPEC+, higher gas prices, high interest rates, 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. Further, the volatility in oil and natural gas prices could accelerate a transition away from fossil fuels, resulting in reduced demand over the longer term. To what extent these and other external factors (such as government action with respect to climate change regulation) ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors, including future developments, that are not within our control and cannot be accurately predicted.
Additionally, like other companies in the oil and gas industry, our operations are subject to stringent federal, state and local laws and regulations relating to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing, and sale of our products. Federal, state and local agencies may assert overlapping authority to regulate in these areas. See Part I, Items 1 and 2. "Business and Properties-Regulatory Matters-Regulation of Health, Safety and Environmental Matters" in our Annual Report for a description of laws and regulations that affect our business. For more information related to regulatory risks, see Part I, Item 1A. "Risk Factors-Risks Related to Our Operations and Industry" in our Annual Report and Part II, Item 1A. "Risk Factors" in this Quarterly Report.
Commodity Pricing and Differentials
Our revenue, costs, profitability, shareholder returns and future growth are highly dependent on the prices we receive for our oil and natural gas production, as well as the prices we pay for our natural gas purchases, which are affected by a variety of factors, including those discussed in Part I, Item 1A. "Risk Factors" in our Annual Report.
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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 tables set 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, 2024 June 30, 2024
September 30, 2023
Average Price
Realization(1)
Average Price
Realization(1)
Average Price
Realization(1)
Sales of Crude Oil (per bbl):
Brent
$ 78.71 $ 85.03 $ 85.92
Realized price without derivative settlements
$ 72.40 92% $ 78.18 92% $ 78.89 92%
Effects of derivative settlements
(1.39) (4.60) (5.76)
Realized price with derivative settlements
$ 71.01 90% $ 73.58 87% $ 73.13 85%
WTI
$ 75.26 $ 80.60 $ 81.99
Realized price without derivative settlements $ 72.40 96% $ 78.18 97% $ 78.89 96%
Purchased Natural Gas (per mmbtu)
Average Monthly Settled Price - NWPL
$ 1.92 $ 1.40 $ 3.40
Realized price without derivative settlements $ 2.70 141% $ 2.26 161% $ 4.18 123%
Effects of derivative settlements 1.64 2.04 1.43
Realized price with derivative settlements $ 4.34 226% $ 4.30 307% $ 5.61 165%
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Nine Months Ended
September 30, 2024
September 30, 2023
Average Price
Realization(1)
Average Price
Realization(1)
Sales of Crude Oil (per bbl):
Brent
$ 81.82 $ 81.96
Realized price without derivative settlements
$ 75.31 92% $ 74.72 91%
Effects of derivative settlements
(2.71) (3.38)
Realized price with derivative settlements
$ 72.60 89% $ 71.34 87%
WTI
$ 77.62 $ 77.31
Realized price without derivative settlements $ 75.31 97% $ 74.72 97%
Purchased Natural Gas (per mmbtu)
Average Monthly Settled Price - NWPL
$ 2.24 $ 9.54
Realized price without derivative settlements $ 3.00 134% $ 9.22 97%
Effects of derivative settlements 1.52 (2.56)
Realized price with derivative settlements $ 4.52 202% $ 6.66 70%
__________
(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 75% 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 2024, oil prices decreased relative to the second quarter of 2024 and the third quarter of 2023.
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 via rail to refiners, primarily in the Gulf Coast. However, 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, 2024, June 30, 2024, and September 30, 2023, Utah had an average realized oil price of $60.35, $65.58 and $70.48, respectively, compared to an average Brent oil price of $78.71, $85.03 and $85.92 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 plus transportation costs for the purchases made in the Rockies and the SoCal Gas city-gate index for the purchases made in California. We currently buy most of our gas in the Rockies. Now that we are purchasing a majority of our fuel gas in the Rockies, most of the purchases made in California use the SoCal Gas city-gate index, whereas prior to this shift the predominant index for California purchases was Kern, Delivered. The price from the Northwest, Rocky Mountain index was as high as $2.40 per mmbtu and as low as $1.42 per mmbtu in the third quarter of 2024. The price from the SoCal Gas city-gate index was as high as $3.19 per mmbtu and as low as $1.81 per mmbtu in the third quarter of 2024. Overall, on an unhedged basis, we paid an average of $2.70 per mmbtu in the third quarter of 2024 for our gas purchases which includes transportation costs. When including the hedging effects in our gas purchases, we paid $4.34, $4.30 and $5.61 per mmbtu in the third quarter of 2024, the second quarter of 2024, and the third quarter of 2023, respectively.
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The price of our fuel 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 2024, our Utah operations had an average realized gas price of $2.01, compared to an average Northwest, Rocky Mountains gas price of $1.92, which was a 105% realization. In the three months ended June 30, 2024 and September 30, 2023, Utah had an average realized gas price of $1.78, and $3.57, compared to an average Northwest, Rocky Mountains gas price of $1.40, or 127% realization, and $3.40, 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 substantially more natural gas for our California steamfloods and cogeneration facilities than we produce and sell in the Rockies. We purchase most of our gas in the Rockies and transport it to our California operations using our Kern River pipeline capacity. We buy approximately 48,000 mmbtu/d in the Rockies, and the remainder comes from California markets. The volume purchased in California fluctuates and averaged 2,000 mbbtu/d in the third quarter of 2024, 2,000 mmbtu/d in the second quarter of 2024, and 6,000 mmbtu/d in the third quarter of 2023. 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 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 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 slightly in the third quarter of 2024 compared to the second quarter of 2024. The natural gas futures indicate that prices will rise toward the end of 2024 and into 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.
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, both our E&P business and CJWS are subject to complex and stringent federal, state and local laws and regulations, and California, where most of our operations and assets are located, is one of the most heavily regulated states in the United States with respect to oil and gas operations. Collectively, the effect of the existing laws and regulations is to limit the number and location of our wells through restrictions on the use of our properties, limit our ability to develop certain assets and conduct certain operations, including through a restrictive and burdensome permitting and approval process, and have the effect of reducing the amount of oil and natural gas that we can produce from our wells, potentially reducing such production below levels that would otherwise be possible or economical. Additionally, the regulatory burden in the past has resulted, and in the future could result, in increased costs and consequently has had an adverse effect on operations, capital expenditures, earnings and our competitive position and may continue to have such effects in the future. Violations and liabilities with respect to these laws and regulations could also result in reputational damage and significant administrative, civil or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or
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revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and future prospects. Our operations in California are particularly exposed to increased regulatory risks given the stringent environmental regulations imposed on the oil and gas industry, and current political and social trends in California continue to increase limitations on and impose additional permitting, mitigation, and emissions control obligations, amongst others, upon the oil and gas industry. We cannot predict what new laws or regulations governmental authorities within California (or the federal government) may impose upon our operations in the future; however, any such future laws or regulations could materially and adversely impact our business and results of operations. For additional information about the potential impact that government regulations, including those regarding environmental matters, may have upon our business, operations, capital expenditures, earnings and competitive position, please see Part I, Item 1 "Regulatory Matters," as well as Part I, Item 1A. "Risk Factors" in our Annual Report and Part II, Item 1A. "Risk Factors" in this Quarterly Report.
Permitting
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, as well as a more time- and cost-intensive permitting process. The issuance of permits and other approvals for drilling and production activities by state and local agencies or by federal agencies are subject to environmental reviews under the California Environmental Quality Act ("CEQA") and/or the National Environmental Policy Act ("NEPA"), respectively. The requirement to demonstrate compliance with CEQA and/or NEPA is currently resulting in (and in the future may result in) significant delays in the issuance of permits to drill new wells, as well as the potential imposition of mitigation measures and restrictions on proposed oil field operations, among other things. Before an operator can pursue drilling operations in California, they must first obtain permission to engage in oil and gas land use. CEQA requires the reviewing state and local agencies to consider the environmental impacts of the proposed oil and gas operations for permitting decisions. Historically, we satisfied CEQA by complying with the Kern County zoning ordinance for oil and gas operations, which was supported by the Kern County Environmental Impact Report ("EIR"). However, the Kern County EIR was legally challenged in 2015 and the use of the Kern County EIR is currently stayed and has been stayed for lengths of time throughout the litigation. Most recently, the Kern County EIR was stayed in January 2023 by a California appellate court while they reviewed the November 2022 ruling by the lower court that reinstated the Kern County EIR; since that time, operators have been unable to use the Kern County EIR to demonstrate CEQA compliance as required to receive permits to drill new wells. In March 2024, the California appellate court delivered its opinion finding certain deficiencies in the Kern County EIR and the reliance on the EIR remains enjoined until those deficiencies are remedied. Accordingly, our ability to rely on the Kern County EIR to demonstrate CEQA compliance to obtain permits and approvals to drill new wells is constrained unless and until Kern County is able to favorably resolve the litigation and certify a new revised EIR that the Court deems fully complies with CEQA. In the meantime, to obtain permits for drilling new wells in Kern County we must demonstrate compliance with CEQA to CalGEM through means other than the Kern County EIR. Berry does have a separate environmental impact analysis covering certain assets, and we have received permits to drill new wells in the covered areas. In fact, in May 2024, we received 13 permits to drill new wells, which we are executing on in 2024 and 2025. We are currently exploring a number of alternative permitting strategies for new drill permits to meet future needs; however, we cannot guarantee that any of these strategies will ultimately be successful. Importantly, the litigation impacting the Kern County EIR does not restrict the issuance of sidetrack and workover permits, and we have continued to receive the necessary permits to meet our production goals. Although in the latter part of 2023 and into 2024, we did experience some delays in the issuance of sidetrack and workover permits due to changes in CalGEM's CEQA review process. CalGEM is now processing applications on a more timely basis and permits are being issued on a more predictable timeline. We have completed our 2024 planned drilling activities and currently have sufficient permits in hand to support remaining 2024 activity and also support activity into 2025, including for new wells, sidetracks and workovers. Based on permits in hand and assuming the current permitting regime continues, we are confident in our ability to execute our strategy of holding production relatively flat in 2025, as we have for the last six years. However, it is possible that permit approval delays could adversely impact operations in 2025 and beyond and the inability to secure permits (on a timely basis or at all) could adversely impact our business and results of operations.
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On August 26, 2024, CalGEM approved a final rule to prohibit permitting of well stimulation treatments (which includes hydraulic fracturing), which became effective on October 1, 2024. Although we do rely on other methods to stimulate production, such as cyclic and continuous steam injection, we currently do not perform any hydraulic fracturing in California and our near term plans do not include the development of assets requiring hydraulic fracturing. See Part I, Item 1 and 2. "Business and Properties-Regulatory Matters-Regulation of the Oil and Gas Industry" in our Annual Report, as well as Part I, Item 1A. "Risk Factors" in our Annual Report and Part II, Item 1A. "Risk Factors" in this Quarterly Report for more information regarding the EIR and other permitting considerations.
Approximately 95% of our production in 2023 came from our base production, with the remainder from 33 wells drilled in California during the year (5 new wells and 28 sidetracks), workovers and other activities related to existing wellbores, and production acquired from the Macpherson Acquisition, which closed in September 2023. Similar to 2023, our 2024 plans focus on drilling sidetracks and working over existing wells, as well as drilling some of the new wells approved by CalGEM in May 2024. Our goal of maintaining consistent production levels from 2023 to 2024 will also benefit from production from the assets acquired in the Macpherson Acquisition and other smaller bolt-on acquisitions in the second quarter of 2024, as well as production from the Utah Horizontal farm-in well interests. We have in hand all the permits needed to support our 2024 plans and activity into 2025, and we are in the process of obtaining the additional permits needed to support our 2025 plans.
Setbacks - SB 1137
Separately, on September 16, 2022, the California Governor signed into law SB 1137 to be effective January 1, 2023, which prohibits CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or rework is within 3,200 feet of certain sensitive receptors such as homes, schools or parks. Additional provisions of SB 1137, include, among others, the imposition of HSE controls applicable to wells located within the setback areas related to noise, light, and dust pollution controls and air emission monitoring, and the immediate suspension of operations at production facilities determined not to be in compliance with certain air emission requirements. However, in December 2022, proponents of a voter referendum (the "Referendum") collected more than the number of signatures required to put SB 1137 on the November 2024 ballot. On February 3, 2023, the Secretary of State of California certified the signatures and confirmed that the Referendum qualified for the November 2024 ballot and SB 1137 was stayed pending a vote of the California General Election in November 2024. However, in June 2024, the ballot proposal was withdrawn with the proposal's sponsors instead indicating a view to challenging SB 1137 in court. The provisions of SB 1137 became effective immediately in June 2024. Then on September 30, 2024, the Governor signed into law AB 218, which delays the deadline for some compliance with CalGEM's regulations implementing SB 1137 until July 1, 2026 and further delays compliance with certain other requirements of SB 1137 by up to three years.
Certain of our undeveloped costs are located within the setbacks established by SB 1137, which required an analysis of impairment as of the date the law became effective. Accordingly, following SB 1137's immediate effectiveness in June 2024, we recorded a non-cash pre-tax asset impairment charge of $44 million, $33 million after-tax on unproved oil and gas properties in certain California locations during the second quarter of 2024. The impairment represents approximately 2% of the gross cost basis of our total oil and natural gas properties. See Note 10-Oil and Natural Gas Properties to the Financial Statements.
We do not expect this law to result in any material change to our overall existing proved developed producing reserves or current production rates. The majority of our production is in rural areas in the San Joaquin basin and is unlikely to be affected by SB 1137 as supplemented by AB 218. Approximately 13% of our production for the nine months ended September 30, 2024 was within setback zones and subject to SB 1137's requirements.
Following the passage of AB 218 in September 2024 which extended the deadline for certain compliance requirements of SB 1137, all wells and facilities within a setback must be in compliance with specific health, safety and environmental requirements pursuant to SB 1137 by July 1, 2026, with leak detection and response plans developed and submitted to CalGEM for agency approval by July 1, 2028. CalGEM must approve these plans by July 1, 2029 and, beginning on July 1, 2030, operators are required to suspend operations within setback areas unless
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they have a CalGEM-approved leak detection and response plan that has been fully implemented. This plan must be updated every five years, and operators must annually report on implementation of these plans as well as the results of baseline water quality testing. While we are still assessing the impact and additional costs associated with compliance with SB 1137, the impact and costs are expected to be immaterial.
Local Ordinances - AB 3233
On September 25, 2024, the California Governor signed Assembly Bill 3233 (AB 3233) into law, which explicitly authorizes local governments to limit methods for, or even prohibit, oil and gas operations or development within its jurisdiction, including with respect to existing operations. This legislation specifically was passed in response to a prior California Supreme Court decision that found limits on the authority of local governments to regulate oil and gas operations on the basis of preemption because of existing state law providing CalGEM with sole authority to regulate the methods for oil and gas production. Certain jurisdictions within California, including Monterey and Los Angeles, had previously taken steps to limit oil and gas operations that were struck down by that now invalidated California Supreme Court decision and it is possible that they or other local governments in California may pass similar legislation following AB 3233. We currently only operate in Kern County and at this time we are not aware of any local governments within Kern County that would seek to materially limit or otherwise prohibit oil and gas operations within its jurisdiction. However, it is difficult to predict how local governments in California may choose to exercise their new authority under AB 3233. While there may be future legal challenges to AB 3233 and any local ordinances enacted thereunder, we cannot predict whether or not such challenges will be successful, or if AB 3233 or any ordinances enacted pursuant to it will be stayed pending the outcome of such challenges. Notwithstanding any potential claims for regulatory takings we may have in the event local jurisdictions seek to prohibit any of our existing operations, any restrictions that materially limit or prohibit oil and gas production in the areas where we operate could materially impact our operations and financial condition.
Other Legislation
The potential exists for additional federal, state, and local legislation in the future that could adversely impact our operations. For example, in 2023, a legislator introduced Senate Bill No. 556 (SB 556) into the California Senate in 2023, providing for joint and several liability for operators and owners of an entity that owns an oil and gas production facility for certain adverse health conditions in a setback zone, subject to limited defenses. SB 556 also provided for civil penalties to be assessed against potentially responsible parties. Although this bill died during the last legislative session, similar bills could be introduced in the future. Another example is Assembly Bill 2716 (AB 2716), signed into law by the California Governor on September 25, 2024, that requires the plugging and abandonment of certain low-production wells located within the boundary of the Baldwin Hills Conservancy within a certain timeframe or otherwise subjects operators to administrative penalties. Although AB 2716 is indicative of the state of California's interest in accelerating the plugging and abandonment of low-production wells, this law is limited in scope to only certain wells within the Baldwin Hills Conservancy, which encompasses the Inglewood Oil Field. We do not currently operate any wells in the Inglewood Oil Field and, as such, this legislation will not impact our existing operations.
Assembly Bill 1167 (AB 1167), signed into law by the California Governor in October 2023 and effective as of January 1, 2024, imposes stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in the state of California, which are more significant than those in effect for existing operators. Specifically, AB 1167 requires such persons to fulfill bonding requirements in an amount determined by the CalGEM to sufficiently cover full plugging and abandonment costs, decommissioning and site restoration of all wells and production facilities. Transfer of operatorship of a well or production facility is prohibited until CalGEM has determined the appropriate bond amount and the bond has been filed. Upon signing AB 1167, the California Governor called for further legislative changes to the new requirements to mitigate the potential risk of an increase in the number of orphaned wells becoming state liabilities following the implementation of the law.
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In April 2019, CalGEM issued updated idle well management that include a comprehensive well testing regime to demonstrate the mechanical integrity of idle wells, a compliance schedule for testing or plugging and abandoning idle wells, the collection of data necessary to prioritize testing and/or plugging idle wells, an engineering analysis for each well idled 15 years or longer, and requirements for active observation wells. These idle well regulations require operators to plug and abandon idle wells under two programs: operators are required to either submit annual idle well management plans describing how they will plug and abandon or reactivate a specified percentage of long-term idle wells or pay additional annual fees and perform additional testing to retain greater flexibility to return long-term idle wells to service in the future. Assembly Bill 1866 (AB 1866), signed into law by the California Governor on September 25, 2024 and effective January 1, 2025, sets forth either (a) increased annual fees for operators of idle wells depending on how long each well has been idle or (b) in lieu of payment of the annual fee, operators can instead file a plan with the state that provides for the management and elimination of all idle wells, with consideration shown to a number of specified factors when prioritizing idle wells for testing or plugging and abandonment. CalGEM is in the process of implementing the provisions of AB 1866, so we are unable to fully assess the potential impact at this time. However, based on our preliminary assessment, we expect the impact to our plugging and abandoning costs to be minimal.
In October 2023, the California Governor signed two bills that require quantitative and qualitative climate disclosures for certain public and private companies doing business in California. Senate Bill 253 (SB 253) requires that the California Air Resources Board ("CARB") develop and adopt regulations to require the annual disclosure of Scope 1, 2 and 3 GHG emissions, with certain emissions data subject to third party assurance. The bill requires disclosure of Scope 1 and 2 GHG emissions beginning in 2026 for the 2025 reporting year and disclosure of Scope 3 GHG emissions beginning in 2027 for the 2026 reporting year. SB 253 would be effective for public and private companies with total annual revenues exceeding $1 billion and that do business in California. Senate Bill 261 (SB 261) requires biennial disclosures posted on a company's website related to climate-related financial risks and the measures a company has adopted to reduce and adapt to such risks. The bill requires disclosure of the climate-related financial risk disclosures beginning in 2026 for the 2025 reporting year. SB 261 is effective for public and private companies with total annual revenues exceeding $500 million. Both SB 253 and 261 have been challenged in the U.S. District Court for the Central District of California. Further, on September 27, 2024, the California Governor amended both SB 253 and SB 261 by signing into law Senate Bill 219 (SB 219). SB 219 extends the time in which CARB has to promulgate implementing regulations for SB 253 until July 1, 2025, a delay of six months, but does not otherwise change the reporting deadlines in SB 253 or SB 261.
In July 2024 the California Governor signed a bill that limits the use of California net operating losses ("NOLs"). The legislation suspended the use of the California NOL deduction for corporate taxpayers with California net income or modified adjusted gross income of $1 million or more for tax years beginning on or after January 1, 2024, and before January 1, 2027. We determined that the legislation does not currently impact the carrying value of and ability to ultimately utilize our California NOLs before their expiration, but there could be a future impact to our carrying value and ability to utilize our California NOLs.
Inflation
The U.S. inflation rate has become more significant in recent years. The Company, similar to other companies in our industry, has experienced inflationary pressures on our costs-namely inflationary pressures have resulted in increases to the costs of our goods, services and personnel, which in turn, have caused our capital expenditures and operating costs to rise. Such inflationary pressures have resulted from supply chain disruptions caused by the COVID-19 pandemic, increased demand, labor shortages and other factors, including the conflict between Russia and Ukraine. During the first half of 2024, inflation rates have continued their trend of stabilizing as seen in the latter half of 2023. We are unable to accurately predict if such inflationary pressures and contributing factors will continue through the remainder of 2024. However, as of September 30, 2024, we determined there have not been any material changes in inflationary pressures since the year ended December 31, 2023.
Seasonality
Seasonal weather conditions have in the past, and in the future likely will, impact our drilling, production and
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well servicing activities. Extreme weather conditions can pose challenges to meeting well-drilling and completion objectives and production goals. Seasonal weather can also lead to increased competition for equipment, supplies and personnel, which could lead to shortages and increased costs or delayed operations. Our operations have been, and in the future could be, impacted by ice and snow in the winter, especially in Utah, and by electrical storms and high temperatures in the spring and summer, as well as by wildfires and rain.
We seek to mitigate a substantial portion of the gas purchase 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. In the third quarter of 2024, gas prices increased slightly from prices in the second quarter of 2024. Our hedging strategy coupled with our midstream access to gas from the Rockies helps us mitigate the impact of high natural gas prices on our cost structure.
Capital Expenditures
For the three and nine months ended September 30, 2024, our total capital expenditures were approximately $26 million and $85 million, respectively, including capitalized overhead and interest and excluding acquisitions and asset retirement spending. E&P and corporate expenditures were $25 million and $83 million for the three and nine months ended September 30, 2024, respectively (which excludes well servicing and abandonment capital of less than $1 million and $2 million for the three and nine months ended September 30, 2024, respectively). Approximately 75% and 25% of these capital expenditures for the nine months ended September 30, 2024 were directed to California and Utah operations, respectively. During the first nine months of 2024 we drilled 40 wells in California and four vertical wells in Utah, as well as four non-operated horizontal wells in Utah of which our working interest is approximately 21%.
Our 2024 capital expenditure budget for E&P operations, CJWS and corporate activities is expected to be between $95 to $110 million, which, if executed fully, we expect to result in meeting our goal of delivering 2024 production consistent with 2023. We currently anticipate oil production will be approximately 93% of total production volume in 2024, substantially consistent with 2023. Total capital expenditures were approximately $73 million in 2023, after reallocating $35 million from planned capital expenditures to fund a portion of the Macpherson Acquisition which closed in September 2023. Our 2024 E&P capital program focuses primarily on drilling sidetracks and the workovers of existing well in California, and was prepared on the assumption that we would not receive permits to drill new wells in 2024 given the permitting delays we were experiencing at the time. We later modified our plans to include drilling some of the new wells approved by CalGEM in May 2024. Reflected in our 2024 E&P capital program is our expectation that results will also benefit from a full year of production from the Macpherson Acquisition, as well as from production from the additional working interests acquired in December 2023 and the second quarter of 2024, and the Utah horizontal farm-in well interests which came online in June 2024. Our E&P drilling activities have essentially been completed for the year and we expect full year capital expenditures to be within the provided range. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund the remainder of our 2024 capital development programs from cash flow from operations. We currently have sufficient permits in hand to support our remaining planned activities for the the year and to support drilling and workover activities into 2025. 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, including those impacting regulatory approval and permitting requirements.
Exclusive of the capital expenditures noted above, for the full year 2024, we currently plan to spend approximately $13 million to $17 million on plugging and abandonment activities, most of which is planned to meet our annual obligation requirements under California's idle well regulations. In 2023, we spent $18 million on plugging and abandonment activities, most of which was in compliance with California idle well regulations. We spent approximately $4 million and $10 million for plugging and abandonment activities in the three months and nine months ended September 30, 2024, respectively.
For information about the potential risks related to our capital program, see Part I, Item IA. "Risk Factors" in our Annual Report, as well as "-Regulatory Matters."
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Production and Prices
The following table sets forth information regarding average daily production, total production and average prices for each of the periods indicated.
Three Months Ended
September 30, 2024 June 30, 2024 September 30, 2023
Average daily production:(1)
Oil (mbbl/d) 22.8 23.4 23.2
Natural Gas (mmcf/d) 9.5 8.9 9.5
NGL (mbbl/d) 0.4 0.4 0.5
Total (mboe/d)(2)
24.8 25.3 25.3
Total Production:
Oil (mbbl) 2,096 2,129 2,136
Natural gas (mmcf) 872 808 877
NGLs (mbbl) 40 36 44
Total (mboe)(2)
2,281 2,300 2,326
Weighted-average realized sales prices:
Oil without hedges ($/bbl) $ 72.40 $ 78.18 $ 78.89
Effects of scheduled derivative settlements ($/bbl) $ (1.39) $ (4.60) $ (5.76)
Oil with hedges ($/bbl) $ 71.01 $ 73.58 $ 73.13
Natural gas ($/mcf) $ 2.01 $ 1.78 $ 3.57
NGL ($/bbl) $ 24.01 $ 24.46 $ 22.54
Average Benchmark prices:
Oil (bbl) - Brent $ 78.71 $ 85.03 $ 85.92
Oil (bbl) - WTI $ 75.26 $ 80.60 $ 81.99
Natural gas (mmbtu) - SoCal Gas city-gate(3)
$ 2.68 $ 1.86 $ 7.10
Natural gas (mmbtu) - Northwest, Rocky Mountains(4)
$ 1.92 $ 1.40 $ 3.40
Natural gas (mmbtu) - Henry Hub(4)
$ 2.11 $ 2.07 $ 2.59
__________
(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, 2024, the average prices of Brent oil and Henry Hub natural gas were $78.71 per bbl and $2.11 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.
(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, 2024 June 30, 2024 September 30, 2023
Average daily production (mboe/d):(1)
California 20.1 21.1 20.5
Utah
4.7 4.2 4.8
Total average daily production 24.8 25.3 25.3
__________
(1) Production represents volumes sold during the period.
Our average daily production decreased 2%, or 0.5 mboe/d, for the three months ended September 30, 2024, compared to the three months ended June 30, 2024. Our California production was 20.1 mboe/d for the third quarter of 2024, a decrease of 5% or 1.0 mboe/d from the second quarter of 2024, partially due to the timing of adding new wells to production in our Midway Sunset field. These wells were put on-line at the end of the third quarter which increased our exit rate production. The decrease was also due to temporarily reduced steam injection in the Midway Sunset field which was restored by the end of the quarter. Utah production increased 0.5 mboe/d mostly due to our recent investment in four non-operated wells which began production in June 2024.
Our average daily production decreased 2%, or 0.5 mboe/d, for the three months ended September 30, 2024, compared to the three months ended September 30, 2023. Lower 2024 production in California was primarily due to lower production from the Midway Sunset field, discussed above, partially offset by production from the Macpherson Acquisition in the third quarter of 2023. Utah production was consistent year-over-year due to mid-year 2024 development which included our recent investment in the four non-operated wells described above.
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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, 2024 September 30, 2023
Average daily production:(1)
Oil (mbbl/d) 23.3 23.3
Natural Gas (mmcf/d) 8.8 9.1
NGL (mbbl/d) 0.4 0.4
Total (mboe/d)(2)
25.2 25.2
Total Production:
Oil (mbbl) 6,386 6,359
Natural gas (mmcf) 2,404 2,495
NGLs (mbbl) 104 99
Total (mboe)(2)
6,891 6,874
Weighted-average realized sales prices:
Oil without hedges ($/bbl) $ 75.31 $ 74.72
Effects of scheduled derivative settlements ($/bbl) $ (2.71) $ (3.38)
Oil with hedges ($/bbl) $ 72.60 $ 71.34
Natural gas ($/mcf) $ 2.46 $ 7.65
NGL ($/bbl) $ 25.70 $ 24.73
Average Benchmark prices:
Oil (bbl) - Brent $ 81.82 $ 81.96
Oil (bbl) - WTI $ 77.62 $ 77.31
Natural gas (mmbtu) - SoCal Gas city-gate(3)
$ 2.91 $ 12.52
Natural gas (mmbtu) - Northwest, Rocky Mountains(4)
$ 2.24 $ 9.54
Natural gas (mmbtu) - Henry Hub(4)
$ 2.11 $ 2.46
__________
(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, 2024, the average prices of Brent oil and Henry Hub natural gas were $81.82 per bbl and $2.11 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.
(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, 2024 September 30, 2023
Average daily production (mboe/d):(1)
California 20.8 20.4
Utah
4.4 4.8
Total average daily production 25.2 25.2
__________
(1) Production represents volumes sold during the period.
Average daily production for the nine months ended September 30, 2024, was comparable to the same period in 2023. California produced 20.8 mboe/d for the nine months ended September 30, 2024, an increase of 0.4 mboe/d, or 2%, when compared to the nine months ended September 30, 2023, primarily due to the Macpherson Acquisition in late 2023 and development activity throughout 2024. Average daily production in Utah for the nine months ended September 30, 2024, decreased by 0.4 mboe/d, or 8% compared to the same period in 2023 due to natural well decline, partially offset by our recent investment in the four non-operated wells described above.
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Results of Operations
Three Months Ended September 30, 2024 compared to Three Months Ended June 30, 2024.
Three Months Ended
September 30, 2024 June 30, 2024 $ Change % Change
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales $ 154,438 $ 168,781 $ (14,343) (8) %
Service revenue(1)
25,465 31,155 (5,690) (18) %
Electricity sales 4,410 3,691 719 19 %
Gains (losses) on oil and gas sales derivatives
75,434 (5,844) 81,278 n/a
Other revenues 37 36 1 3 %
Total revenues and other $ 259,784 $ 197,819 $ 61,965 31 %
__________
(1) The well servicing and abandonment segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $31 million and $37 million and the intercompany elimination was $5 million and $6 million for the quarters ended September 30, 2024 and June 30, 2024, respectively.
Revenues and Other
Oil, natural gas and NGL sales decreased by $14 million, or 8%, to approximately $154 million for the three months ended September 30, 2024, compared to the three months ended June 30, 2024. The decrease was driven by a $12 million decrease in oil prices and a $2 million decrease in oil volumes.
Service revenue consisted entirely of revenue from the well servicing and abandonment business, excluding intercompany amounts. Service revenue decreased $6 million or 18% to $25 million for the three months ended September 30, 2024, compared to the three months ended June 30, 2024. The decrease was due to lower rates and activity in the third quarter.
Electricity sales represent sales to utilities and increased $1 million to $4 million for the three months ended September 30, 2024 compared to the three months ended June 30, 2024, due to higher operating rates for our cogeneration facilities.
Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement loss for the three months ended September 30, 2024 and June 30, 2024 was $3 million and $10 million, respectively. This quarter-over-quarter decrease in settlement loss was primarily due to lower Brent settlement prices, the index for all our oil derivatives. The mark-to-market non-cash gain for the three months ended September 30, 2024 was $78 million compared to a gain of $4 million in the three months ended June 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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Three Months Ended
$ Change % Change
September 30, 2024 June 30, 2024
(in thousands)
Expenses and other:
Lease operating expenses $ 54,801 $ 53,989 $ 812 2 %
Costs of services(1)
22,911 25,021 (2,110) (8) %
Electricity generation expenses 1,245 552 693 126 %
Transportation expenses 1,332 1,039 293 28 %
Acquisition costs(2)
971 1,394 (423) (30) %
General and administrative expenses 19,111 18,881 230 1 %
Depreciation, depletion and amortization 42,749 42,843 (94) - %
Impairment of oil and gas properties - 43,980 (43,980) 100 %
Taxes, other than income taxes 10,351 12,674 (2,323) (18) %
Losses on natural gas purchase derivatives
7,775 2,642 5,133 194 %
Other operating (income)
(4,687) (3,204) (1,483) (46) %
Total expenses and other 156,559 199,811 (43,252) (22) %
Other expenses:
Interest expense (8,986) (10,050) 1,064 (11) %
Other, net 56 (53) 109 (206) %
Total other expenses (8,930) (10,103) 1,173 (12) %
Income (loss) before income taxes
94,295 (12,095) 106,390 880 %
Income tax expense (benefit)
24,432 (3,326) 27,758 (835) %
Net income (loss)
$ 69,863 $ (8,769) $ 78,632 897 %
Adjusted EBITDA(3)
$ 67,121 $ 74,329 $ (7,208) (10) %
Adjusted Net Income(3)
$ 10,839 $ 14,155 $ (3,316) (23) %
__________
(1) The well servicing and abandonment segment provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $28 million and $31 million and the intercompany elimination was $5 million and $6 million for the three months ended September 30, 2024 and June 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 2% or $1 million to $55 million for the third quarter of 2024 when compared to the second quarter of 2024. This increase was the result of higher natural gas (fuel) costs of $2 million for our California steam generation facilities due to a 19% increase in fuel prices. Lease operating expenses excluding fuel decreased $1 million due to lower well service and maintenance activity.
Costs of services consisted entirely of costs from the well servicing and abandonment business, excluding intercompany amounts. Cost of services decreased $2 million, or 8%, to $23 million in the third quarter of 2024 primarily due to cost savings in response to lower activity.
Electricity generation expenses increased approximately $1 million due to higher operating rates for our cogeneration facilities and higher fuel prices for the three months ended September 30, 2024 compared to the three months ended June 30, 2024.
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Transportation expenses for the three months ended September 30, 2024, were approximately $1 million, slightly higher than for the three months ended June 30, 2024, primarily due to higher processed volumes.
Gains and losses on natural gas purchase derivatives resulted in a loss of $8 million for the three months ended September 30, 2024 and a loss of $3 million for the three months ended June 30, 2024. Settlements for the three months ended September 30, 2024 and June 30, 2024 were a loss of $7 million, or $3.28 per boe, and a loss of $9 million, or $4.05 per boe, respectively. The decrease was due to higher settlement prices relative to the fixed price in the third quarter of 2024 compared to the second quarter of 2024. The mark-to-market valuation loss for the three months ended September 30, 2024 was less than $1 million compared to a gain of $7 million for the three months ended June 30, 2024. Because we are the fixed price payer on these natural gas swaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses).
Acquisition costs declined in the three months ended September 30, 2024 compared to the three months ended June 30, 2024 due to reduced activity and include legal and other professional expenses related to various transaction activities.
General and administrative expenses was unchanged at $19 million for the three months ended September 30, 2024, compared to the three months ended June 30, 2024. For the three months ended September 30, 2024, general and administrative expenses included $2 million non-cash stock compensation costs, compared to $2 million non-cash stock compensation costs for three months ended June 30, 2024. We had approximately $1 million of non-recurring costs for the three months ended September 30, 2024 and no non-recurring costs for the three months ended June 30, 2024.
Adjusted General and Administrative Expenses, which excludes non-cash stock compensation expense and non-recurring costs, were slightly lower for the three months ended September 30, 2024 compared to the three months ended June 30, 2024. See "-Non-GAAP Financial Measures" for a reconciliation of general and administrative expenses, the most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted General and Administrative Expenses.
DD&A was flat for the three months ended September 30, 2024 compared to the three months ended June 30, 2024.
Impairment of Oil and Gas Properties
There was no impairment of oil and gas properties for the three months ended September 30, 2024. Impairment of oil and gas properties was $44 million for the three months ended June 30, 2024.
Taxes, Other Than Income Taxes
Three Months Ended $ Change % Change
September 30, 2024 June 30, 2024
(per boe)
Severance taxes $ 1.66 $ 1.72 $ (0.06) (3) %
Ad valorem and property taxes 2.44 2.14 0.30 14 %
Greenhouse gas allowances and other emission costs 0.44 1.65 (1.21) (73) %
Total taxes other than income taxes $ 4.54 $ 5.51 $ (0.97) (18) %
Taxes, other than income taxes, decreased in the three months ended September 30, 2024 by $0.97 per boe, or 18%, to $4.54. The decrease was primarily due to lower GHG emissions and mark-to-market prices. Ad valorem and property taxes increased due to increased property valuations.
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Other Operating (Income) Expenses
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 three months ended June 30, 2024, other operating income was $3 million and mainly consisted of prior period royalty receipts and property tax refunds.
Interest Expense
Interest expense decreased $1 million for the three months ended September 30, 2024, compared to the three months ended June 30, 2024, due to lower working capital borrowings on the RBL Facility.
Income Taxes
Our effective tax rate was 26% for the three months ended September 30, 2024 and 28% for the three months ended June 30, 2024. The rate in both periods included the impact of state taxes and certain permanent items which were not deductible for tax purposes. The rate in the third quarter of 2024 also included the generation of new tax credits.
Three Months Ended September 30, 2024 compared to Three Months Ended September 30, 2023.
Three Months Ended
September 30, 		$ Change % Change
2024 2023
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales $ 154,438 $ 172,611 $ (18,173) (11) %
Service revenue(1)
25,465 45,511 (20,046) (44) %
Electricity sales 4,410 3,849 561 15 %
Gains (losses) on oil and gas sales derivatives
75,434 (103,282) 178,716 n/a
Other revenues 37 113 (76) (67) %
Total revenues and other $ 259,784 $ 118,802 $ 140,982 119 %
__________
(1) The well servicing and abandonment segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $31 million and $47 million and the intercompany elimination was $5 million and $2 million for the quarters ended September 30, 2024 and 2023, respectively.
Revenues and Other
Oil, natural gas and NGL sales decreased $18 million, or 11%, to approximately $154 million for the three months ended September 30, 2024 when compared to the three months ended September 30, 2023. The decline in revenue was from a $14 million decline in oil prices, a $3 million decrease in oil volumes, and a $1 million decrease in natural gas prices.
Service revenue (excluding intercompany amounts) decreased by $20 million, or 44%, to $25 million for the three months ended September 30, 2024, compared to the three months ended September 30, 2023, due to lower rates and activity in the third quarter of 2024.
Electricity sales represent sales to utilities and were slightly higher at $4 million for the three months ended September 30, 2024, primarily due to higher prices when compared to the three months ended September 30, 2023.
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Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Settlement losses for the three months ended September 30, 2024 and September 30, 2023 were $3 million and $12 million, respectively. The decrease in settlement losses was driven by lower oil prices relative to our derivative fixed prices in the third quarter of 2024 than those of the same period in 2023. Notional volumes were 15 mbbl/d in the third quarter of 2024 and 14 mbbl/d in the third quarter of 2023. The mark-to-market non-cash gain for the three months ended September 30, 2024 was $78 million compared to a loss of $91 million for the three months ended September 30, 2023. 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).
Three Months Ended
September 30, 		$ Change % Change
2024 2023
(in thousands)
Expenses and other:
Lease operating expenses $ 54,801 $ 59,842 $ (5,041) (8) %
Costs of services(1)
22,911 35,806 (12,895) (36) %
Electricity generation expenses 1,245 1,479 (234) (16) %
Transportation expenses 1,332 1,089 243 22 %
Acquisition costs(2)
971 2,082 (1,111) (53) %
General and administrative expenses 19,111 20,987 (1,876) (9) %
Depreciation, depletion and amortization 42,749 39,729 3,020 8 %
Taxes, other than income taxes 10,351 17,980 (7,629) (42) %
Losses (gains) on natural gas purchase derivatives
7,775 (8,425) 16,200 n/a
Other operating (income)
(4,687) (505) (4,182) (828) %
Total expenses and other 156,559 170,064 (13,505) (8) %
Other expenses:
Interest expense (8,986) (9,101) 115 (1) %
Other, net 56 (42) 98 (233) %
Total other expenses (8,930) (9,143) 213 (2) %
Income (loss) income before income taxes
94,295 (60,405) 154,700 256 %
Income tax expense (benefit)
24,432 (15,343) 39,775 (259) %
Net income (loss)
$ 69,863 $ (45,062) $ 114,925 255 %
Adjusted EBITDA(3)
$ 67,121 $ 69,829 $ (2,708) (4) %
Adjusted Net Income(3)
$ 10,839 $ 11,831 $ (992) (8) %
__________
(1) The well servicing and abandonment segment provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $28 million and $38 million and the intercompany elimination was $5 million and $2 million for the quarters ended September 30, 2024 and September 30, 2023, respectively.
(2) Includes legal and other professional expenses related to various transactions activities.
(3) Adjusted EBITDA and Adjusted Net Income (Loss) are financial measures that are not calculated in accordance with GAAP. For definitions and a reconciliation to the Net Cash Provided by Operating Activities and Net Income (loss), please see "-Non-GAAP Financial Measures".
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Expenses
Lease operating expenses, which do not include the effects of gas purchase hedges, decreased 8% or $5 million to $55 million for the third quarter of 2024 when compared to the third quarter of 2023. The decrease was the result of $8 million lower natural gas (fuel) costs for our California steam generation facilities mainly due to a decline in fuel price and lower volumes purchased, as a result of our cost savings initiatives to reduce steam. These decreases were partially offset by a $3 million increase in non-fuel lease operating expense from higher power, company labor, and well servicing costs.
Cost of services (excluding intercompany amounts) decreased $13 million, or 36%, to $23 million for the third quarter of 2024 compared to the third quarter of 2023 primarily due to cost savings in response to lower activity.
Electricity generation expenses declined slightly due to lower fuel purchase prices for the three months ended September 30, 2024 compared to the same period in 2023.
Transportation expenses for the three months ended September 30, 2024, were approximately $1 million, slightly higher than for the same period in 2023, mostly due to higher natural gas processing costs.
Gains and losses on natural gas purchase derivatives for the three months ended September 30, 2024, and September 30, 2023, resulted in a loss of $8 million and a gain of $8 million, respectively. Settlement loss for the three months ended September 30, 2024 was unchanged at $7 million from the three months ended September 30, 2023. The mark-to-market non-cash loss was less than $1 million for the three months ended September 30, 2024 and a gain of $16 million for three months ended September 30, 2023. Because we are the fixed price payer on these natural gas swaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses).
Acquisition costs decreased $1 million for the three months ended September 30, 2024 compared to the three months ended September 30, 2023 due to reduced activity, and include legal and other professional expenses related to various transaction activities.
General and administrative expenses decreased $2 million or 9% in the three months ended September 30, 2024 when compared to the three months ended September 30, 2023. For the three months ended September 30, 2024 general and administrative expenses had $2 million in non-cash stock compensation expense compared to $3 million for September 30, 2023. We incurred approximately $1 million in non-recurring costs for each of the three months ended September 30, 2024 and three months ended September 30, 2023.
Adjusted General and Administrative Expenses, which exclude non-cash stock compensation expense and non-recurring costs were slightly lower for the three months ended September 30, 2024 compared to the three months ended September 30, 2023. 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, or 8%, to $43 million in the three months ended September 30, 2024 when compared to the three months ended September 30, 2023 due to an increase in depletion rates.
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Taxes, Other Than Income Taxes
Three Months Ended
September 30, 		$ Change % Change
2024 2023
(per boe)
Severance taxes $ 1.66 $ 1.47 $ 0.19 13 %
Ad valorem and property taxes 2.44 2.12 0.32 15 %
Greenhouse gas allowances and other emission costs 0.44 4.14 (3.70) (89) %
Total taxes other than income taxes $ 4.54 $ 7.73 $ (3.19) (41) %
Taxes, other than income taxes decreased 41% to $4.54 per boe for the three months ended September 30, 2024, compared to $7.73 per boe for the three months ended September 30, 2023. GHG allowance expense decreased due to lower emissions and lower mark-to-market prices in the third quarter of 2024 compared to the third quarter of 2023. The increase in ad valorem and property taxes was due to increased property valuations, as well as the additional properties acquired in 2023.
Other Operating (Income) Expenses
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 three months ended September 30, 2023, other income was not material.
Interest Expense
Interest expense was flat in the three months ended September 30, 2024 when compared to the three months ended September 30, 2023.
Income Taxes
Our effective tax rate was approximately 26% for the three months ended September 30, 2024 compared to approximately 25% for the three months ended September 30, 2023. The rate in both periods included the impact of state taxes and certain permanent items which are not deductible for tax purposes. The rate in the third quarter of 2024 also included the generation of new tax credits.
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Nine Months Ended September 30, 2024 compared to Nine Months Ended September 30, 2023.
Nine Months Ended
September 30, 		$ Change % Change
2024 2023
(in thousands)
Revenues and other:
Oil, natural gas and NGL sales $ 489,537 $ 496,671 $ (7,134) (1) %
Service revenue(1)
88,303 137,808 (49,505) (36) %
Electricity sales 12,344 12,372 (28) - %
Gains (losses) on oil and gas sales derivatives
(1,610) (43,912) 42,302 (96) %
Other revenues 140 194 (54) (28) %
Total revenues and other $ 588,714 $ 603,133 $ (14,419) (2) %
__________
(1) The well servicing and abandonment segment provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $103 million and $143 million and the intercompany elimination was $15 million and $5 million for the nine months ended September 30, 2024 and 2023, respectively.
Revenues and Other
Oil, natural gas and NGL sales decreased $7 million, or 1%, to $490 million for the nine months ended September 30, 2024 when compared to the nine months ended September 30, 2023. The variance was driven by a $13 million decrease in gas sales (mostly lower prices), partially offset by a $4 million increase in oil prices, and a $2 million increase in oil volumes.
Service revenue (excluding intercompany amounts) decreased $50 million, or 36%, to $88 million for the nine months ended September 30, 2024 when compared to the nine months ended September 30, 2023, due to lower activity and rates.
Electricity sales, which represent sales to utilities were flat at $12 million for the nine months ended September 30, 2024, when compared to the nine months ended September 30, 2023.
Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Settlement losses for the nine months ended September 30, 2024 and September 30, 2023, were $17 million and $22 million, respectively. The period-over-period decrease in settlement losses was driven by a narrower spread between the settled derivative fixed prices and index oil prices in the nine months ended September 30, 2024, compared to that of the same period in 2023. The mark-to-market non-cash gain was $16 million for the nine months ended September 30, 2024, and a loss of $22 million for the nine months ended September 30, 2023. 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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Nine Months Ended
September 30, 		$ Change % Change
2024 2023
(in thousands)
Expenses and other:
Lease operating expenses $ 169,487 $ 249,384 $ (79,897) (32) %
Costs of services(1)
75,236 108,988 (33,752) (31) %
Electricity generation expenses 2,890 5,252 (2,362) (45) %
Transportation expenses 3,430 3,226 204 6 %
Acquisition costs(2)
4,982 3,054 1,928 63 %
General and administrative expenses 58,226 75,144 (16,918) (23) %
Depreciation, depletion and amortization 128,423 119,605 8,818 7 %
Impairment of oil and gas properties 43,980 - 43,980 100 %
Taxes, other than income taxes 38,714 42,147 (3,433) (8) %
Losses on natural gas purchase derivatives
14,898 4,989 9,909 199 %
Other operating (income)
(8,024) (1,824) (6,200) (340) %
Total expenses and other 532,242 609,965 (77,723) (13) %
Other (expenses) income:
Interest expense (28,176) (25,732) (2,444) 9 %
Other, net (80) (227) 147 (65) %
Total other expenses (28,256) (25,959) (2,297) 9 %
Income (loss) before income taxes
28,216 (32,791) 61,007 186 %
Income tax expense (benefit)
7,206 (7,640) 14,846 194 %
Net income (loss)
$ 21,010 $ (25,151) $ 46,161 184 %
Adjusted EBITDA(3)
$ 209,984 $ 198,221 $ 11,763 6 %
Adjusted Net Income(3)
$ 35,904 $ 28,804 $ 7,100 25 %
__________
(1) The well servicing and abandonment segment provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $90 million and $114 million and the intercompany elimination was $15 million and $5 million for the nine months ended September 30, 2024 and September 30, 2023, 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, decreased 32%, or $80 million, on an absolute dollar basis to $169 million for the nine months ended September 30, 2024 when compared to the nine months ended September 30, 2023. The decrease was due to an $89 million decrease in natural gas (fuel) costs for our California steam generation facilities, $84 million of which was from a decline in fuel prices, and $5 million from a decline in fuel volumes. Lease operating expenses excluding fuel increased $9 million due to higher power costs, company labor, and well servicing activity.
Cost of services (excluding intercompany amounts) decreased $34 million, or 31%, to $75 million in the nine months ended September 30, 2024, due to cost savings in response to lower activity.
Electricity generation expenses decreased $2 million to $3 million for the nine months ended September 30, 2024 compared to the same period in 2023, mainly due to lower fuel prices and volumes. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements.
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Gains and losses on natural gas purchase derivatives for the nine months ended September 30, 2024, and September 30, 2023, consisted of $15 million and $5 million losses, respectively. In the nine months ended September 30, 2024, the natural gas settlement price was less than the fixed price of settled positions which resulted in a settlement loss of $21 million, compared to the same period in 2023 when the natural gas settlement price was greater than the fixed prices of settled positions and resulted in a settlement gain of $37 million. The mark-to-market valuation for the nine months ended September 30, 2024, was a gain of $6 million compared to a loss of $42 million for the same period in 2023 when futures prices were lower relative to our derivative fixed prices. Because we are the fixed price payer on these natural gas swaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses).
Transportation expenses were comparable for the periods presented.
Acquisition costs increased $2 million for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023, and include legal and professional expenses related to various transaction activities.
General and administrative expenses decreased $17 million, or 23%, to approximately $58 million for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023. For the nine months ended September 30, 2024 and September 30, 2023, general and administrative expenses included non-cash stock compensation costs of approximately $4 million and $11 million, respectively. We incurred non-recurring costs of $2 million for the nine months ended September 30, 2024. For the nine months ended September 30, 2023, we incurred non-recurring costs of $9 million, which were related to executive transition costs, workforce reduction costs, and shareholder litigation expenses for the same period in 2023.
Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, decreased $3 million to $52 million for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023, largely due to lower employee- related costs, resulting from cost savings initiatives implemented in the first quarter of 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 increased $9 million, or 7%, to $128 million for the nine months ended September 30, 2024, compared to the nine months ended September 30, 2023, due to increased depletion rates.
Impairment of Oil and Gas Properties
Impairment of oil and gas properties was $44 million for the nine months ended September 30, 2024. There was no impairment of oil and gas properties for the nine months ended September 30, 2023.
Taxes, Other Than Income Taxes
Nine Months Ended
September 30, 		$ Change % Change
2024 2023
(per boe)
Severance taxes $ 1.68 $ 1.56 $ 0.12 8 %
Ad valorem and property taxes 2.36 2.06 0.30 15 %
Greenhouse gas allowances and other emission costs 1.57 2.50 (0.93) (37) %
Total taxes other than income taxes $ 5.61 $ 6.12 $ (0.51) (8) %
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Taxes, other than income taxes decreased 8% to $5.61 per boe for the nine months ended September 30, 2024, compared to $6.12 per boe for the nine months ended September 30, 2023. GHG allowance expense decreased due to lower non-cash mark-to-market prices for the allowances compared to the same period in 2023. Ad valorem taxes increased due to additional wells coming online and additional properties acquired in 2023. Severance taxes increased due to an increase in the California conservation tax rate, partially offset by utilization of Utah tax credits.
Other Operating (Income) Expenses
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. For the nine months ended September 30, 2023, other operating income was $2 million and mainly consisted of net property tax refunds from prior periods and a net gain on equipment sales.
Interest Expense
Interest expense increased $2 million, or 9%, in the nine months ended September 30, 2024, compared to the same period in 2023 as a result of higher borrowings on the RBL Facility in 2023.
Income Taxes
Our effective tax rate was approximately 26% for the nine months ended September 30, 2024, compared to 23% for the nine months ended September 30, 2023, respectively. The rate for both periods included the impact of state taxes and certain permanent items which are not deductible. The rate in 2024 also included the generation of new tax credits.
E&P Field Operations
Overall, management assesses the efficiency of our E&P field operations by considering core E&P operating expenses together with our cogeneration, marketing and transportation activities. In particular, a core component of our E&P operations in California is steam, which we use to lift heavy oil to the surface. We operate several cogeneration facilities to produce some of the steam needed in our operations. In comparing the cost effectiveness of our cogeneration plants against other sources of steam in our operations, management considers the cost of operating the cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the steam and electricity used in our E&P field operations and the revenues we receive from sales of excess electricity to the grid. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural gas purchase hedges. Consequently, the efficiency of our E&P field operations are impacted by the cash settlements we receive or pay from these derivatives. We also have contracts for the transportation of fuel gas from the Rockies which has historically been cheaper than the California markets. With respect to transportation and marketing, management also considers opportunistic sales of incremental capacity in assessing the overall efficiencies of E&P operations.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Electricity generation expenses include the portion of fuel, labor, maintenance, and tools and supplies from two of our cogeneration facilities allocated to electricity generation expense; the remaining cogeneration expenses are included in lease operating expense. Transportation expenses relate to our costs to transport the oil and gas that we produce within our properties or move it to the market. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Electricity revenue is from the sale of excess electricity from two of our cogeneration facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are sized to satisfy the steam needs in their respective fields, but the corresponding electricity produced is more than the electricity that is currently required for the operations in those fields. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and marketing revenues represent sales of natural gas purchased from and sold to third parties.
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E&P Field Operations
Three Months Ended
September 30, 2024 June 30, 2024 $ Change % Change
(per boe)
Expenses from field operations
Lease operating expenses $ 24.02 $ 23.47 $ 0.55 2 %
Electricity generation expenses 0.55 0.24 0.31 129 %
Transportation expenses 0.58 0.45 0.13 29 %
Total $ 25.15 $ 24.16 $ 0.99 4 %
Cash settlements paid for gas purchase hedges
$ 3.28 $ 4.05 $ (0.77) (19) %
E&P non-production revenues
Electricity sales $ 1.93 $ 1.60 $ 0.33 21 %
Transportation sales 0.02 0.02 - - %
Total $ 1.95 $ 1.62 $ 0.33 20 %
Three Months Ended
September 30, 2024 September 30, 2023 $ Change % Change
(per boe)
Expenses from field operations
Lease operating expenses $ 24.02 $ 25.73 $ (1.71) (7) %
Electricity generation expenses 0.55 0.64 (0.09) (14) %
Transportation expenses 0.58 0.47 0.11 23 %
Total $ 25.15 $ 26.84 $ (1.69) (6) %
Cash settlements paid for gas purchase hedges
$ 3.28 $ 3.06 $ 0.22 7 %
E&P non-production revenues
Electricity sales $ 1.93 $ 1.65 $ 0.28 17 %
Transportation sales 0.02 0.05 (0.03) (60) %
Total $ 1.95 $ 1.70 $ 0.25 15 %
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Nine Months Ended
September 30, 2024 September 30, 2023 $ Change % Change
(per boe)
Expenses from field operations
Lease operating expenses $ 24.60 $ 36.28 $ (11.68) (32) %
Electricity generation expenses 0.42 0.76 (0.34) (45) %
Transportation expenses 0.50 0.47 0.03 6 %
Total $ 25.52 $ 37.51 $ (11.99) (32) %
Cash settlements paid (received) for gas purchase hedges $ 3.08 $ (5.39) $ 8.47 (157) %
E&P non-production revenues
Electricity sales $ 1.79 $ 1.80 $ (0.01) (1) %
Transportation sales 0.02 0.03 (0.01) (33) %
Total $ 1.81 $ 1.83 $ (0.02) (1) %
See "-How We Plan and Evaluate Operations" for details.
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Non-GAAP Financial Measures
Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses
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 2021 RBL Facility and 2024 Term Loan Credit Agreement.
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 previously reported Adjusted Free Cash Flow, a non-GAAP measure, and made allocations of Adjusted Free Cash Flow in accordance with a structured shareholder return model that we implemented in January 2022, and most recently provided as follows: (a) 80% primarily in the form of debt repurchases, stock repurchases, strategic growth, and acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends. However, in October 2024, in anticipation of entering into the 2024 Term Loan Credit Agreement, we transitioned to a more flexible approach to capital allocation that aligns with the covenants contained in the 2024 Term Loan Credit Agreement and prioritizes debt reduction while facilitating our operating strategy and enabling investment in development opportunities. For a discussion and presentation of Adjusted Free Cash Flow for the prior period, see our previous filings with the SEC.
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
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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 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.
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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,
2024 		June 30,
2024 		September 30,
2023 		September 30,
2024 		September 30,
2023
(in thousands)
Adjusted EBITDA reconciliation:
Net income (loss)
$ 69,863 $ (8,769) $ (45,062) $ 21,010 $ (25,151)
Add (Subtract):
Interest expense 8,986 10,050 9,101 28,176 25,732
Income tax expense (benefit)
24,432 (3,326) (15,343) 7,206 (7,640)
Depreciation, depletion and amortization 42,749 42,843 39,729 128,423 119,605
Impairment of oil and gas properties - 43,980 - 43,980 -
(Gains) losses on derivatives
(67,659) 8,486 94,857 16,508 48,901
Net cash (paid) for scheduled derivative settlements
(10,397) (19,115) (19,432) (38,606) 15,511
Other operating (income)
(4,687) (3,204) (505) (8,024) (1,824)
Stock compensation expense
2,301 1,990 3,018 4,676 11,336
Acquisition costs(1)
971 1,394 2,082 4,982 3,054
Non-recurring costs(2)
562 - 1,384 1,653 8,697
Adjusted EBITDA $ 67,121 $ 74,329 $ 69,829 $ 209,984 $ 198,221
Three Months Ended
Nine Months Ended
September 30,
2024 		June 30,
2024 		September 30,
2023 		September 30,
2024 		September 30,
2023
(in thousands)
Adjusted EBITDA reconciliation:
Net cash provided by operating activities $ 70,695 $ 70,891 $ 55,320 $ 168,859 $ 119,639
Add (Subtract):
Cash interest payments 16,174 1,395 15,065 32,825 30,457
Cash income tax payments 2,286 491 2,087 2,777 2,757
Acquisition costs(1)
971 1,394 - 4,982 -
Non-recurring costs(2)
562 - 1,384 1,653 8,697
Changes in operating assets and liabilities - working capital(3)
(13,605) 3,293 (3,032) 12,231 39,778
Other operating (income) - cash portion(4)
(9,962) (3,135) (995) (13,343) (3,107)
Adjusted EBITDA $ 67,121 $ 74,329 $ 69,829 $ 209,984 $ 198,221
__________
(1) Includes legal and other professional expenses related to various transaction activities.
(2) In 2024, non-recurring costs included cost savings initiatives. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter, and costs related to the settlement of shareholder litigation in the third quarter.
(3) Changes in other assets and liabilities consists of working capital and various immaterial items.
(4) Represents the cash portion of other operating (income) from the income statement, net of the non-cash portion in the cash flow statement.
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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,
2024 		June 30,
2024 		September 30,
2023 		September 30,
2024 		September 30,
2023
(in thousands)
Free Cash Flow reconciliation:
Net cash provided by operating activities
$ 70,695 $ 70,891 $ 55,320 $ 168,859 $ 119,639
Subtract:
Capital expenditures
(25,874) (42,325) (13,596) (85,135) (56,124)
Free Cash Flow
$ 44,821 $ 28,566 $ 41,724 $ 83,724 $ 63,515
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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, 2024 June 30, 2024 September 30, 2023
(in thousands) per share - diluted (in thousands) per share - diluted (in thousands) per share - diluted
Adjusted Net Income (Loss) reconciliation:
Net income (loss)
$ 69,863 $ 0.91 $ (8,769) $ (0.11) $ (45,062) $ (0.58)
Add (Subtract):
(Gains) losses on derivatives
(67,659) (0.88) 8,486 0.11 94,857 1.22
Net cash (paid) for scheduled derivative settlements
(10,397) (0.13) (19,115) (0.25) (19,432) (0.25)
Other operating (income)
(4,687) (0.07) (3,204) (0.05) (505) (0.01)
Impairment of oil and gas properties - - 43,980 0.57 - -
Acquisition costs(1)
971 0.01 1,394 0.02 2,082 0.03
Non-recurring costs(2)
562 0.01 - - 1,384 0.02
Total additions (subtractions), net
(81,210) (1.06) 31,541 0.40 78,386 1.01
Income tax expense (benefit) of adjustments(3)
22,186 0.29 (8,617) (0.11) (21,493) (0.28)
Adjusted Net Income
$ 10,839 $ 0.14 $ 14,155 $ 0.18 $ 11,831 $ 0.15
Basic EPS on Adjusted Net Income $ 0.14 $ 0.18 $ 0.16
Diluted EPS on Adjusted Net Income $ 0.14 $ 0.18 $ 0.15
Weighted average shares of common stock outstanding - basic 76,939 76,939 75,662
Weighted average shares of common stock outstanding - diluted 77,060 77,161 77,606
__________
(1) Includes legal and other professional expenses related to various transaction activities.
(2) In 2024, non-recurring costs included cost savings initiatives. In 2023, non-recurring costs included costs related to the settlement of shareholder litigation in the third quarter.
(3) The federal and state statutory rates were utilized for all periods presented.
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Nine Months Ended
September 30, 2024 September 30, 2023
(in thousands) per share - diluted (in thousands) per share - diluted
Adjusted Net Income (Loss) reconciliation:
Net income (loss)
$ 21,010 $ 0.27 $ (25,151) $ (0.32)
Add (Subtract):
Losses on derivatives
16,508 0.21 48,901 0.63
Net cash (paid) received for scheduled derivative settlements (38,606) (0.50) 15,511 0.20
Other operating (income)
(8,024) (0.09) (1,824) (0.03)
Impairment of oil and gas properties 43,980 0.57 - -
Acquisition costs(1)
4,982 0.06 3,054 0.04
Non-recurring costs(2)
1,653 0.02 8,697 0.11
Total additions (subtractions), net 20,493 0.27 74,339 0.95
Income tax (benefit) expense of adjustments(3)
(5,599) (0.07) (20,384) (0.26)
Adjusted Net Income
$ 35,904 $ 0.47 $ 28,804 $ 0.37
Basic EPS on Adjusted Net Income $ 0.47 $ 0.38
Diluted EPS on Adjusted Net Income $ 0.47 $ 0.37
Weighted average shares of common stock outstanding - basic 76,712 76,163
Weighted average shares of common stock outstanding - diluted 76,903 78,090
__________
(1) Includes legal and other professional expenses related to various transaction activities.
(2) In 2024, non-recurring costs included cost savings initiatives. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter, and costs related to the settlement of shareholder litigation in the third quarter.
(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,
2024 		June 30,
2024 		September 30,
2023 		September 30,
2024 		September 30,
2023
(in thousands)
Adjusted General and Administrative Expense reconciliation:
General and administrative expenses $ 19,111 $ 18,881 $ 20,987 $ 58,226 $ 75,144
Subtract:
Non-cash stock compensation expense (G&A portion)
(2,083) (1,843) (2,840) (4,126) (10,838)
Non-recurring costs(1)
(562) - (1,384) (1,653) (8,697)
Adjusted general and administrative expenses $ 16,466 $ 17,038 $ 16,763 $ 52,447 $ 55,609
Well servicing and abandonment segment $ 2,351 $ 2,454 $ 2,910 $ 7,734 $ 8,994
E&P segment, and corporate $ 14,115 $ 14,584 $ 13,853 $ 44,713 $ 46,615
E&P segment, and corporate ($/boe) $ 6.19 $ 6.34 $ 5.96 $ 6.49 $ 6.78
Total mboe 2,281 2,300 2,326 6,891 6,874
__________
(1) In 2024, non-recurring costs included cost savings initiatives. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter, and costs related to the settlement of shareholder litigation in the third quarter.
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Liquidity and Capital Resources
As of September 30, 2024, we had liquidity of $104 million, consisting of $9 million cash, $88 million available for borrowings under our 2021 RBL Facility and $7 million available for borrowings under our 2022 ABL Facility (as defined below). Based on current commodity prices and our development success rate to date, we expect to be able to fund the remainder of our 2024 capital development programs with cash flow from operations.
We review the allocations of our Free Cash Flow from time to time based on then existing conditions and circumstances, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors. In January 2022, we introduced a structured shareholder return model to guide our allocation of Free Cash Flow, which most recently provided as follows: (a) 80% primarily in the form of debt repurchases, stock repurchases, strategic growth, and acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends. However, in October 2024, in anticipation of entering into the 2024 Term Loan Credit Agreement, we transitioned to a more flexible approach to capital allocation that prioritizes debt reduction and aligns with the covenants contained in the 2024 Term Loan Credit Agreement, while facilitating our operating strategy and 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 variable 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.
The 2021 RBL Facility matures in August 2025, and our 2026 Notes mature in February 2026. In conjunction with the closing of the 2024 Term Loan Credit Agreement, the Company expects to repay in full and terminate the 2022 ABL Facility and the 2021 RBL Facility, as well as redeem the 2026 Notes. We may not be successful in refinancing, repaying or extending the maturity of our 2026 Notes or our 2021 RBL Facility, and any such refinancing may not be obtainable on terms favorable to us. As of September 30, 2024, the outstanding amount on the 2021 RBL Facility is classified as current debt, and we expect to have sufficient sources of liquidity to pay this obligation when it comes due. Management's ongoing assessment of the Company's ability to repay its obligations under its credit agreements as they come due could result in a going concern qualification with respect to our annual audited financial statements.
We currently believe that our liquidity, capital resources, cash on hand and cash flow from operations will be sufficient to conduct our business and operations and meet our obligations for at least the next 12 months. In the longer term, if oil prices were to significantly decline and remain weak, we may not be able to continue to generate the same level of Free Cash Flow we are currently generating and our liquidity and capital resources may not be sufficient to conduct our business and operations until commodity prices recover. Please see Part II, Item 1A. "Risk Factors" in this Quarterly Report and 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.
2021 RBL Facility
See Note 2-Debt in the Notes to Consolidated Financial Statements in Part I, Item 1. "Financial Statements" of this Quarterly Report for details regarding the current terms of the 2021 RBL Facility.
2022 ABL Facility
See Note 2-Debt in the Notes to Consolidated Financial Statements in Part I, Item 1. "Financial Statements" of this Quarterly Report for details.
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Senior Unsecured Notes
In February 2018, Berry LLC completed a private issuance of $400 million in aggregate principal amount of 7.0% senior unsecured notes due February 2026, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers' discount.
The 2026 Notes are Berry LLC's senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The 2026 Notes are fully and unconditionally guaranteed on a senior unsecured basis by Berry Corp and certain of its subsidiaries. C&J and C&J Management do not guarantee the 2026 Notes.
The indenture governing the 2026 Notes contains customary covenants and events of default (in some cases, subject to grace periods). We were in compliance with all covenants under the 2026 Notes as of September 30, 2024.
In conjunction with and subject to the closing of the 2024 Term Loan Credit Agreement discussed below, the Company is required to redeem the 2026 Notes. This report does not constitute a notice of redemption of the 2026 Notes.
2024 Term Loan Credit Agreement
Subsequent to the end of the third quarter of 2024, but before the issuance date of these financials, the Company entered into a Senior Secured Term Loan Credit Agreement (the "2024 Term Loan Credit Agreement") among the Company, as borrower, certain subsidiaries of the Company, as guarantors, Breakwall Credit Management LLC, as administrative agent, and the lenders from time to time party thereto.
The 2024 Term Loan Credit Agreement provides for aggregate commitments equal to $545 million, consisting of (i) an initial term loan facility in the aggregate principal amount of $450 million (the "Initial Term Loans"), and (ii) a delayed draw term loan facility in an aggregate principal amount of up to $95 million which is available from the date of the first borrowing of the Initial Term Loans (the "Funding Date") until the date that is two years after the effectiveness of the 2024 Term Loan Credit Agreement (the "Working Capital Term Loan Facility"). The ability of the Company to borrow under the 2024 Term Loan Credit Agreement, including to refinance the 2026 Notes, 2021 RBL Facility, and the 2022 ABL Facility, is subject to satisfaction of certain customary conditions precedent, as further set forth in the 2024 Term Loan Credit Agreement, including (a) the repayment and termination of liens under each of the 2021 RBL Facility and 2022 ABL Facility and (b) satisfaction and discharge of the 2026 Notes. The proceeds of the Initial Term Loans are limited in their use to the satisfaction and discharge of existing debt, payment of fees and expenses in connection with the 2024 Term Loan Credit Agreement and other related transactions, capital expenditures in accordance with the 2024 Term Loan Credit Agreement, working capital, and other general corporate purposes. A requirement of funding the Initial Term Loans is (a) the contemporaneous termination of the 2022 ABL Facility and the 2021 RBL Facility, including satisfaction and discharge of any remaining balances thereon and (b) the satisfaction and discharge of the 2026 Notes.
The 2024 Term Loan Credit Agreement will have an initial maturity date of three years from the Funding Date, which may be extended by up to two-one year increments subject to payment of extension fees, and satisfaction of certain other customary conditions. Quarterly debt service payments of an amount equal to the sum of 2.5% of (a) the face value of the Initial Term Loan and (b) the aggregate amount of delayed draws made from the Working Capital Term Loan Facility are required beginning in March 2025.
Loans under the 2024 Term Loan Credit Agreement will bear interest at a rate per annum equal to Term SOFR (as defined in the 2024 Term Loan Credit Agreement) plus an applicable margin of 7.50%. If an Event of Default (as defined in the 2024 Term Loan Credit Agreement) exists and is continuing, upon the election of the Majority Lenders (as defined in the 2024 Term Loan Credit Agreement) under the 2024 Term Loan Credit Agreement, or automatically without such election, in the case of a bankruptcy, insolvency, or payment default, all amounts outstanding under the 2024 Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto (it being understood that the 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
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Event of Default is continuing). The Company will be able to repay any amounts borrowed prior to the maturity date (i) without any premium for any optional prepayment on or prior to the date that is 24 months after the Funding Date and (ii) thereafter, subject to a concurrent payment of 2.75% of the principal amount being repaid.
On the Funding Date, the 2024 Term Loan Credit Agreement will be guaranteed by the Company and all of its wholly owned subsidiaries and will be secured by a first lien security interest in substantially all assets of the Company and all of its wholly owned subsidiaries.
The 2024 Term Loan Credit Agreement allows the Company to replace the commitments and outstanding borrowings under the Working Capital Term Loan Facility with a super-priority reserve based credit facility of up to $95 million (the "New RBL Facility"), subject to terms and conditions set forth therin, including the entry by the Company and the subsidiaries of the Company party thereto into of an intercreditor agreement, as more fully described in the 2024 Term Loan Credit Agreement.
The 2024 Term Loan Credit Agreement also contains certain financial covenants, including (a) minimum liquidity of $25 million as of the last day of any calendar month and (b) commencing with the fiscal quarter ending March 31, 2025, (i) a total net leverage ratio that may not exceed 2.5 to 1.0 and (ii) an asset coverage ratio that may not be less than 1.3 to 1.0 as of the last day of any fiscal quarter, in each case, as fully more described in the 2024 Term Loan Credit Agreement.
Additionally, the 2024 Term Loan Credit Agreement contains additional restrictive covenants that (i) from and after the effective date thereof, 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, and sell assets, and (ii) from and after the Funding Date, will limit the ability of the Company and its subsidiaries to, among other things, incur additional indebtedness (with such exceptions including the New RBL Facility), incur additional liens, enter into certain hedging transactions, engage in transactions with affiliates and make certain capital expenditures.
In addition, the 2024 Term Loan Credit Agreement 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, the administrative agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments and exercise remedies against any collateral.
The 2024 Term Loan Credit Agreement became effective on November 6, 2024 (the "Closing").
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.
In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility and will have similar hedging requirements under out 2024 Term Loan Credit Agreement. The 2021 RBL Facility requires us to maintain commodity hedges (other than three-way collars), with floor prices no less than 80% of the then prevailing market price at the time such hedging agreement is entered into, on minimum notional volumes of (i) at least 75% of our reasonably projected production of crude oil from our PDP reserves, for each full calendar month during the period from and including the first full calendar month following each April 1 and October 1 of each calendar year after the effective date of the 2021 RBL Facility through and including the 24th full calendar month following each such April 1 and October 1 and (ii) at least 50% of our reasonably projected production of crude oil from our PDP reserves, for each full calendar month during the period from and including the 25th full calendar month following each April 1 and October 1 of each calendar year after the effective date of the 2021 RBL Facility through and including the 36th full calendar month following each April 1 and October 1; provided, that in the case of each of the above clauses (i) and (ii), the notional volumes hedged are deemed reduced by the notional volumes of any short
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puts or other similar derivatives having the effect of exposing us to commodity price risk below the "floor."
In addition to minimum hedging requirements and other restrictions in respect of hedging described therein, the 2021 RBL Facility 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 aggregated with other commodity hedges then in effect other than basis differential swaps on volumes already hedged) exceed, as of the date such hedging agreement is executed, 90% of our reasonably projected production of crude oil from our PDP reserves, for each month following the date such hedging agreement is entered into, provided that such volume limitations do not apply to, among other things, short puts or long put options contracts that are not related to corresponding calls, collars, or swaps.
The 2024 Term Loan Credit Agreement requires us to maintain commodity hedges in the form of the hedges existing as of the effective date of the 2024 Term Loan Credit Agreement, fixed price swaps (at market prices), costless collars, certain other collars meeting conditions described in the Term Loan Credit Agreement and put options, on minimum notional volumes of (i) at least 75% of our reasonably projected production of crude oil from our PDP reserves, for each full calendar month during the period from and including the first full calendar month on a quarterly basis after the Funding Date of the 2024 Term Loan Credit Agreement through and including the 24th full calendar month following 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 full calendar month during the period from and including the 25th full calendar month following the relevant minimum hedging test date after the Funding Date of the 2024 Term Loan Credit Agreement through and including the 36th full calendar month following such minimum hedging testing date. In addition, the 2024 Term Loan Credit Agreement requires us to maintain hedges in respect of purchases of natural gas for fuel in respect of 40,000 million British thermal units of natural gas for fuel for each day (a) during the 18 month calendar month period immediately following the Funding Date and (b) during the 18 month calendar month period commencing with the end of the next upcoming month after the applicable minimum hedging test date.
In addition to minimum hedging requirements and other restrictions in respect of hedging described therein, the 2024 Term Loan Credit Agreement 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 aggregated with other commodity hedges then in effect other than basis differential swaps on volumes already hedged) 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, the 2024 Term Loan Credit Agreement 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 Term Loan Credit Agreement.
Our generally low-decline production base affords an ability to hedge a material amount of our future expected production. We expect our operations to generate sufficient cash flows at current commodity prices including our current hedging positions. For information regarding risks related to our hedging program, see Part I-Item 1A. "Risk Factors-Risks Related to Our Operations and Industry" in our Annual Report.
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As of November 1, 2024, we had the following crude oil production and gas purchases hedges.
Q4 2024
FY 2025 FY 2026
FY 2027
FY 2028
FY 2029
Brent - Crude Oil production
Swaps
Hedged volume (bbls) 1,438,656 4,951,125 2,633,268 3,056,000 2,378,000 724,000
Weighted-average price ($/bbl) $ 76.93 $ 76.06 $ 71.76 $ 70.66 $ 68.36 $ 67.44
Sold Calls(1)
Hedged volume (bbls) 92,000 296,127 1,251,500 318,500 - -
Weighted-average price ($/bbl) $ 105.00 $ 88.69 $ 85.53 $ 80.03 $ - $ -
Purchased Puts (net)(2)
Hedged volume (bbls) 322,000 - - - - -
Weighted-average price ($/bbl) $ 50.00 $ - $ - $ - $ - $ -
Purchased Puts (net)(2)
Hedged volume (bbls) - 296,127 1,251,500 318,500 - -
Weighted-average price ($/bbl) $ - $ 60.00 $ 60.00 $ 65.00 $ - $ -
Sold Puts (net)(2)
Hedged volume (bbls) 46,000 - - - - -
Weighted-average price ($/bbl) $ 40.00 $ - $ - $ - $ - $ -
NWPL - Natural Gas purchases(3)
Swaps
Hedged volume (mmbtu) 3,680,000 13,380,000 3,040,000 - - -
Weighted-average price ($/mmbtu) $ 3.96 $ 4.27 $ 4.26 $ - $ - $ -
__________
(1) Purchased calls and sold calls with the same strike price have been presented on a net basis.
(2) Purchased puts and sold puts with the same strike price have been presented on a net basis.
(3) The term "NWPL" is defined as Northwest Rocky Mountain Pipeline.
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Gains (losses) on Derivatives
A summary of gains and losses on the derivatives included on the statements of operations is presented below:
Three Months Ended
Nine Months Ended
September 30,
2024 		June 30,
2024 		September 30,
2023 		September 30,
2024 		September 30,
2023
(in thousands)
Realized (losses) gains on commodity derivatives:
Realized (losses) on oil sales derivatives $ (2,907) $ (9,801) $ (12,304) $ (17,390) $ (21,512)
Realized (losses) gains on natural gas purchase derivatives (7,490) (9,314) (7,128) (21,216) 37,023
Total realized (losses) gains on derivatives $ (10,397) $ (19,115) $ (19,432) $ (38,606) $ 15,511
Unrealized gains (losses) on commodity derivatives:
Unrealized gains (losses) on oil sales derivatives $ 78,341 $ 3,957 $ (90,977) $ 15,780 $ (22,399)
Unrealized (losses) gains on natural gas purchase derivatives (285) 6,672 15,552 6,318 (42,013)
Total unrealized gains (losses) on derivatives
$ 78,056 $ 10,629 $ (75,425) $ 22,098 $ (64,412)
Total gains (losses) on derivatives $ 67,659 $ (8,486) $ (94,857) $ (16,508) $ (48,901)
The following table summarizes the historical results of our hedging activities.
Three Months Ended
Nine Months Ended
September 30,
2024 		June 30,
2024 		September 30,
2023 		September 30,
2024 		September 30,
2023
Crude Oil (per bbl):
Realized sales price, before the effects of derivative settlements $ 72.40 $ 78.18 $ 78.89 $ 75.31 $ 74.72
Effects of derivative settlements (1.39) (4.60) (5.76) (2.71) (3.38)
Realized sales price, after the effects of derivatives $ 71.01 $ 73.58 $ 73.13 $ 72.60 $ 71.34
Purchased Natural Gas (per mmbtu):
Purchase price, before the effects of derivative settlements $ 2.70 $ 2.26 $ 4.18 $ 3.00 $ 9.22
Effects of derivative settlements 1.64 2.04 1.43 1.52 (2.56)
Purchase price, after the effects of derivatives settlements $ 4.34 $ 4.30 $ 5.61 $ 4.52 $ 6.66
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Cash Dividends
In the first quarter of 2024, our Board of Directors declared a fixed cash dividend of $0.12 per share, as well as a variable cash dividend of $0.14 per share which was based on the results of the fourth quarter of 2023, for a total of $0.26 per share, which we paid in March 2024. In April 2024, the Board of Directors approved a fixed cash dividend totaling $0.12 per share, which was paid in May 2024. In July 2024, the Board of Directors approved a fixed cash dividend of $0.12 per share and a variable cash dividend of $0.05 per share, based on the results for the six months ended June 30, 2024, for a total of $0.17 per share, which was paid in August 2024. These variable dividends were paid in accordance with our shareholder return model, which allocated 20% of Adjusted Free Cash Flow to the payment of variable dividends.
In October 2024, in anticipation of entering the 2024 Term Loan Credit Agreement, we transitioned away from the previously established shareholder return model to a more flexible approach to capital allocation, which among other things prioritizes the repayment of debt. Accordingly, we suspended the quarterly variable dividend. Additionally, the Board of Directors determined it was appropriate to reduce the quarterly fixed dividend to $0.03 per share, reflecting the 2024 Term Loan Credit Agreement requirements and the desire to deploy capital to development opportunities, amongst other priorities. The fixed dividend is payable on November 25, 2024 to shareholders of record at the close of business on November 15, 2024.
The following table represents the regular fixed cash dividends on our common stock and variable dividends approved by our Board of Directors in 2024.
First Quarter Second Quarter
Third Quarter
Year-to-Date
Fixed Dividends $ 0.12 $ 0.12 $ 0.03 $ 0.27
Variable Dividends(1)
- 0.05 - 0.05
Total $ 0.12 $ 0.17 $ 0.03 $ 0.32
__________
(1) Variable dividends have been declared the quarter following the period of results. There is no variable dividend related to the results of the third quarter of 2024. The table reflects total dividends earned in each quarter.
Stock Repurchase Program
The Company did not repurchase any shares during the three and nine months ended September 30, 2024. As of September 30, 2024, the Company had repurchased a total of 11.9 million shares, cumulatively, under the stock repurchase program for approximately $114 million in aggregate.
As of September 30, 2024, 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.
The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors. Purchases may be commenced or suspended at any time without notice and the share repurchase program does not obligate the Company to purchase shares during any period or at all. Any shares repurchased are reflected as treasury stock and any shares acquired will be available for general corporate purposes.
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Statements of Cash Flows
The following is a comparative cash flow summary:
Nine Months Ended
September 30,
2024 2023
(in thousands)
Net cash:
Provided by operating activities $ 168,859 $ 119,639
Used in investing activities (85,649) (126,450)
Used in financing activities (78,574) (22,239)
Net increase (decrease) in cash and cash equivalents
$ 4,636 $ (29,050)
Operating Activities
Cash provided by operating activities increased for the nine months ended September 30, 2024 by approximately $49 million when compared to the nine months ended September 30, 2023. The increase was primarily related to a decrease in lease operating expenses, lower general and administrative expenses (from lower payroll costs) and lower executive transition costs, and lower taxes, other than income costs, partially offset by an increase in derivatives settlements paid, a decrease in net margin from CJWS and a decrease in unhedged revenue.
Investing Activities
The following provides a comparative summary of cash flows from investing activities:
Nine Months Ended
September 30,
2024 2023
(in thousands)
Capital expenditures:
Capital expenditures $ (85,135) $ (56,124)
Changes in capital expenditures accruals 1,219 (10,431)
Acquisitions, net of cash received (9,188) (59,895)
Proceeds from sale of property and equipment and other 7,455 -
Net cash used in investing activities
$ (85,649) $ (126,450)
Cash used in investing activities decreased $41 million for the nine months ended September 30, 2024 when compared to the same period in 2023, primarily due to lower acquisition activity in 2024 and cash proceeds from the sale of CJWS' storage facility in Ventura, California, offset by increased capital expenditures in 2024.
Financing Activities
Cash used in financing activities increased approximately $56 million for the nine months ended September 30, 2024 when compared to the nine months ended September 30, 2023 primarily due to the deferred consideration payment for the Macpherson Acquisition, increased repayments on the 2021 RBL credit facility, and an increase in debt issuance costs, partially offset by a decrease in dividends paid.
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Balance Sheet Analysis
The changes in our balance sheet from December 31, 2023 to September 30, 2024 are discussed below.
September 30, 2024 December 31, 2023
(in thousands)
Cash and cash equivalents $ 9,471 $ 4,835
Accounts receivable, net $ 74,542 $ 86,918
Derivative instruments assets - current and long-term $ 22,110 $ 10,751
Other current assets $ 35,539 $ 43,759
Property, plant & equipment, net $ 1,337,275 $ 1,406,612
Deferred income taxes asset - long-term $ 27,378 $ 30,308
Other noncurrent assets $ 10,833 $ 10,975
Accounts payable and accrued expenses $ 144,186 $ 213,401
Derivative instruments liabilities - current and long-term $ - $ 10,740
Current portion of long-term debt, net $ 27,500 $ -
Long-term debt, net $ 398,000 $ 427,993
Deferred income taxes liability - long-term $ 4,264 $ 2,344
Asset retirement obligations - long-term $ 178,329 $ 176,578
Other noncurrent liabilities $ 32,660 $ 5,126
Stockholders' equity $ 732,209 $ 757,976
See "-Liquidity and Capital Resources" for discussions about the changes in cash and cash equivalents.
The $12 million decrease in accounts receivable was primarily due to decreased oil and gas sales and service revenue between the two ending periods.
The $8 million decrease in other current assets was primarily due to prepaid expense amortization, as well as reduction of materials inventory.
The $69 million decrease in property, plant and equipment was primarily due to year-to-date changes in accumulated depreciation of $119 million, and $44 million in impairment, offset by $85 million in capital investments and $9 million in acquisitions.
The $3 million decrease in net deferred income taxes assets - long term, which includes the deferred tax liability, was primarily due to the utilization of federal NOL and credit carryforwards.
The $69 million decrease in accounts payable and accrued expenses includes decreased greenhouse gas liability, final payment for the acquisition of Macpherson Energy made in July 2024, decreased fuel gas purchases (based on lower fuel gas price) since year end, decreased obligations for royalties payable between the two ending periods, and decreased interest payable, offset by an increase in taxes other than income taxes.
The $22 million increase in net derivative assets, which includes the derivative liability, is due to change in the derivative values and positions at the end of each period. Changes to mark-to-market derivative values at the end of each period result from differences in the forward curve prices relative to the contract fixed prices, changes in positions held and settlements received and paid throughout the periods.
The $28 million increase in the current portion of the long-term debt, net reflects a reclass of the 2021 RBL Facility from long-term debt, net based on its maturity date.
The $30 million decrease in long-term debt, net largely reflected the reclassification of the current portion.
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The $2 million increase in deferred income taxes liability - long-term is due to the tax effect of accelerated tax deductions.
The $2 million increase in the long-term portion of the asset retirement obligations from $177 million at December 31, 2023 to $178 million at September 30, 2024 was due to $9 million of accretion expense and $2 million in liabilities incurred, largely offset by $9 million of liabilities settled during the period.
The $28 million increase in othernoncurrent liabilities is primarily due to the obligations for greenhouse gas allowances incurred in 2024 which are due in over one year.
The $26 million decrease in stockholders' equity was due to $47 million of common stock dividends, and $5 million of shares withheld for payment of taxes on equity awards, offset by $21 million in net income and $5 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.
We accrue for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at September 30, 2024 and December 31, 2023. 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, 2024, we are not aware of material indemnity claims pending or threatened against us.
Securities Litigation Matters
In November 2020, a putative securities class action (the "Securities Class Action") was filed in the United States District Court for the Northern District of Texas, claiming that Berry Corp. and certain of its current and former directors and officers violated the Securities Act of 1933 and the Exchange Act of 1934 by allegedly making 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.
While the motion for class certification was still pending before the court, the parties reached an agreement-in-principle to settle all claims in the Securities Class Action for an aggregate sum of $2.5 million. Following notice to the class and an opt-out and objection process, the Court granted final approval of the settlement on February 6, 2024, and terminated the case. The Defendants continue to maintain that the claims were without merit and admitted no liability in connection with the settlement.
While the Securities Class Action is now concluded, certain related shareholder derivative actions remain pending. 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 piggy-backs on the Securities Class Action and is currently pending before the same court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the Securities Class Action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27, 2023, the court granted the parties' joint stipulated request to stay the Assad Lawsuit pending resolution of the Securities Class Action.
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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, again piggy-backing on the Securities Class Action. This complaint, 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 securities violations alleged in the Securities Class Action. In addition, the complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry's 2022 proxy statement was false and misleading in that it suggested the Company's internal controls were sufficient and the Board of Directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case. On February 13, 2023, the court granted the parties' joint stipulated request to stay the Karp Lawsuit pending further developments in the Securities Class Action.
The settlement of the Securities Class Action did not resolve the Shareholder Derivative Actions, which remain pending. The defendants continue to believe the claims in the Shareholder Derivative Actions are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to these matters.
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.
Contractual Obligations
The following is a summary of our commitments and contractual obligations as of September 30, 2024:
Payments Due
Total Less Than 1 Year 1-3
Years 		3-5
Years 		Thereafter
(in thousands)
Debt obligations:
RBL Facility
$ 27,500 $ 27,500 $ - $ - $ -
2026 Notes
400,000 - 400,000 - -
Interest(1)
38,500 28,000 10,500 - -
Other:
Leases
6,962 2,647 3,871 444 -
Asset retirement obligations(2)
198,329 20,000 - - 178,329
Off-Balance Sheet arrangements:(3)
Transportation contracts(4)
73,443 11,523 16,362 16,165 29,393
GHG compliance purchase contracts(5)
22,114 22,114 - - -
Other purchase obligations(6)
17,100 17,100 - - -
Total contractual obligations
$ 783,948 $ 128,884 $ 430,733 $ 16,609 $ 207,722
__________
(1) Represents interest on the 2026 Notes computed at 7% through contractual maturity in 2026.
(2) Represents the estimated future asset retirement obligations on a discounted basis. We do not show the long-term asset retirement obligations by year as we are not able to precisely predict the timing of these amounts. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgements that are subject to revisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See Note 1-Basis of Presentation in the notes to consolidated financial statements in Part II-Item 8. "Financial Statements and Supplementary Data" in our Annual Report for more information.
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(3) These commitments and contractual obligations are expected to be funded by our cash flow from operations.
(4) 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.
(5) We have entered into contracts to purchase GHG compliance instruments totaling $22 million, of which $6 million will be delivered and paid in the fourth quarter 2024. The approximate remaining amount of $16 million of these instruments will be delivered and paid in 2025.
(6) As of September 30, 2024, 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 2024 and the remaining 29 wells by June 2025.
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.
Cautionary Note Regarding Forward-Looking Statements
The information included 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, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. All statements other than statements of historical facts included in this Quarterly Report that address plans, activities, events, objectives, goals, strategies or developments that the Company expects, believes or anticipates will or may occur in the future, such as those regarding our financial position, liquidity, our ability to refinance our indebtedness; our ability to satisfy our debt obligations and comply with all covenants, agreements and conditions under our 2024 Term Loan Agreement; cash flows (including, but not limited to, Free Cash Flow), financial and operating results, capital program and development and production plans and expectations (including about potential results and impact), operations and business strategy, potential acquisition and other strategic opportunities, reserves, hedging activities, capital expenditures, return of capital, the payment of future dividends, future repurchases of stock or debt, capital investments, our ESG strategy and the initiation of new projects or business in connection therewith, recovery factors and other guidance, are forward-looking statements. 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 (but not all the factors) that could cause results to differ include among others:
•the regulatory environment, including availability or timing of, and conditions imposed on, obtaining and/or maintaining permits and approvals, including those necessary for drilling and/or development projects;
•the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government activities, including those related to permitting, drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, GHGs or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;
•our ability to satisfy our debt obligations and comply with all covenants, agreements and conditions under our 2024 Term Loan Agreement;
•our ability to refinance or pay, when due, the principal of, interest or other amounts due in respect of our indebtedness, including our 2024 Term Loan Credit Agreement, 2026 Notes and/or our 2021 RBL Facility;
•inflation levels and government efforts to reduce inflation, including related interest rate determinations;
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•overall domestic and global political and economic trends, geopolitical risks and general economic and industry conditions, such as inflation, high interest rates, increased volatility in financial and credit markets, global supply chain disruptions, government interventions into the financial markets and economy and volatility related to recent and upcoming elections in the United States and other major economies;
•the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions, including the ongoing conflict in Ukraine, the ongoing conflict in the Middle East, or a prolonged recession, among other factors;
•volatility of oil, natural gas and NGL prices, including as a result of political instability, armed conflicts or economic sanctions;
•the California and global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues, the transition to a low-emission economy and the expected role of different energy sources;
•supply of and demand for oil, natural gas and NGLs, including due to the actions of foreign producers, importantly including OPEC+ and change in OPEC+'s production levels;
•risks related to our public statements with respect to sustainability matters that may be subject to heightened scrutiny from the public and governmental authorities related to the risk of potential "greenwashing";
•disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver our oil and natural gas and other processing and transportation considerations;
•inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures, meet our working capital requirements or fund planned investments;
•price fluctuations and availability of natural gas and electricity and the cost of steam;
•competition and consolidation in the oil and gas E&P industry;
•our ability to use derivative instruments to manage commodity price risk;
•our ability to meet our planned drilling schedule, including due to our ability to obtain permits on a timely basis or at all, and to successfully drill wells that produce oil and natural gas in commercially viable quantities;
•concerns about climate change and air quality issues;
•uncertainties associated with estimating proved reserves and related future cash flows;
•our ability to replace our reserves through exploration and development activities or acquisitions;
•drilling and production results, lower-than-expected production, reserves or resources from development projects or higher-than-expected decline rates;
•our ability to obtain timely and available drilling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating wells;
•changes in tax laws;
•uncertainties and liabilities associated with acquired and divested assets;
•our ability to make acquisitions and successfully integrate any acquired businesses;
•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;
•market fluctuations in electricity prices and the cost of steam;
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•asset impairments from commodity price declines, regulatory changes, permitting delays or other factors;
•large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;
•geographical concentration of our operations;
•the creditworthiness and performance of our counterparties with respect to our hedges;
•impact of derivatives legislation affecting our ability to hedge;
•failure of risk management and ineffectiveness of internal controls;
•catastrophic events, including wildfires, earthquakes, 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;
•our ability to recruit and/or retain key members of our senior management and key technical employees;
•information technology failures or cyberattacks; and
•governmental actions and political conditions, as well as 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, 2024, 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, 2024, the fair value of our hedge positions was a net asset of approximately $22 million. A 10% increase in the oil and natural gas index prices above the September 30, 2024 prices would result in a net liability of approximately $75 million; conversely, a 10% decrease in the oil and natural gas index prices below the September 30, 2024 prices would result in a net asset of approximately $120 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, 2024, the fair value of our emission allowances required by California's cap-and-trade program was $28 million. A 10% increase or decrease in the market price would result in a change in expense by approximately $3 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 and Chief Accounting Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the 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, 2024.
The Company's disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC. The Company's disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company's management, including the Chief Executive Officer and the Vice President, Chief Financial Officer and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.
There were no changes in the Company's internal control over financial reporting during the third quarter of 2024 that materially affected, or were reasonably likely to materially affect, the Company's internal control over financial reporting.
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Part II - Other Information
Item 1. Legal Proceedings
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
Securities Litigation Matter
In November 2020, a putative securities class action (the "Securities Class Action") was filed in the United States District Court for the Northern District of Texas, claiming that Berry Corp. and certain of its current and former directors and officers violated the Securities Act of 1933 and the Exchange Act of 1934 by allegedly making 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.
While the motion for class certification was still pending before the court, the parties reached an agreement-in-principle to settle all claims in the Securities Class Action for an aggregate sum of $2.5 million. Following notice to the class and an opt-out and objection process, the Court granted final approval of the settlement on February 6, 2024, and terminated the case. The Defendants continue to maintain that the claims were without merit and admitted no liability in connection with the settlement.
While the Securities Class Action is now concluded, certain related shareholder derivative actions remain pending. 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 piggy-backs on the Securities Class Action and is currently pending before the same court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the Securities Class Action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27, 2023, the court granted the parties' joint stipulated request to stay the Assad Lawsuit pending resolution of the Securities Class Action.
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, again piggy-backing on the Securities Class Action. This complaint, 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 securities violations alleged in the Securities Class Action. In addition, the complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry's 2022 proxy statement was false and misleading in that it suggested the Company's internal controls were sufficient and the Board of Directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case. On February 13, 2023, the court granted the parties' joint stipulated request to stay the Karp Lawsuit pending further developments in the Securities Class Action.
The settlement of the Securities Class Action did not resolve the Shareholder Derivative Actions, which remain pending. The defendants continue to believe the claims in the Shareholder Derivative Actions are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to these matters.
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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.
Other Matters
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.
The recent definitive implementation of SB 1137 to restrict the production of oil and gas in certain setback areas is expected to negatively impact our reserves and could result in decreased demand for fossil fuels within the states where we operate.
In September 2022, the Governor of California signed into law SB 1137 which prohibits CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or rework is within 3,200 feet of certain sensitive receptors such as homes, schools or parks, originally effective as of January 1, 2023. Additional provisions of SB1137, include, among others, the imposition of HSE controls applicable to wells located within the setback areas related to noise, light, and dust pollution controls and air emission monitoring, and the immediate suspension of operations at production facilities determined not to be in compliance with certain air emission requirements. However, in December 2022, proponents of a voter referendum (the "Referendum") collected more than the number of signatures required to put SB 1137 on the November 2024 ballot. On February 3, 2023, the Secretary of State of California certified the signatures and confirmed that the Referendum qualified for the November 2024 ballot and SB 1137 was stayed pending a vote of the California General Election in November 2024. However, in June 2024, the ballot proposal was withdrawn with the proposal's sponsors instead indicating a view to challenging SB 1137 in court. Accordingly, the provisions of SB 1137 went into immediate effect in June 2024. Then on September 30, 2024, the Governor signed into law AB 218, which delayed the deadline for compliance with CalGEM's regulations implementing SB 1137 until July 1, 2026 and further delays compliance with certain other requirements of SB 1137 by up to three years. See Part II, Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations-Regulatory Matters-Setbacks-SB 1137" in this Quarterly Report.
As a result of the June 2024 effectiveness of SB 1137's permitting restrictions, we recorded a non-cash pre-tax asset impairment charge of $44 million ($33 million after-tax) on unproved oil and gas properties in certain California locations during the second quarter of 2024. The impairment represents approximately 2% of our total oil and natural gas properties. The majority of our production is in rural areas in the San Joaquin basin and is unlikely to be affected by SB 1137 as supplemented by AB 218. Approximately 13% of our production for the nine months ended September 30, 2024 was within setback zones subject to SB 1137 and subject to these requirements. We do not expect this law to result in any material change to our overall existing proved developed producing reserves or current production rates. See Note 10-Oil and Natural Gas Properties to the Financial Statements.
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Following the passage of AB 218 in September 2024 which extended the deadline for certain compliance requirements of SB 1137, all wells and facilities within a setback must be in compliance with specific health, safety and environmental requirements pursuant to SB 1137 by July 1, 2026, with leak detection and response plans developed and submitted to CalGEM for agency approval by July 1, 2028. CalGEM must approve these plans by July 1, 2029 and, beginning on July 1, 2030, operators are required to suspend operations within setback areas unless they have a CalGEM-approved leak detection and response plan that has been fully implemented. This plan must be updated every five years, and operators must annually report on implementation of these plans as well as the results of baseline water quality testing. We cannot predict CalGEM's timeline for approving these plans, whether CalGEM will require more stringent mitigation in connection with final approval of such plans, or whether circumstances may arise in the future that could adversely impact production within setback zones. Additionally, failure to comply with the requirements of SB 1137 may result in enforcement action and the imposition of substantial fines and penalties. While we are still assessing the impact and additional costs associated with compliance with SB 1137, the impact and costs are expected to be immaterial.
We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation.
On September 25, 2024, the California Governor signed Assembly Bill 3233 (AB 3233) into law, which explicitly authorizes local governments to limit methods for, or even prohibit, oil and gas operations or development within its jurisdiction, including with respect to existing operations. This legislation specifically overrides a prior California Supreme Court decision that found limits on the authority of local governments to regulate oil and gas operations on the basis of preemption because of existing state law providing CalGEM with sole authority to regulate the methods for oil and gas production. Certain jurisdictions within California, including Monterey and Los Angeles, had previously taken steps to limit oil and gas operations that were struck down by that now invalidated California Supreme Court decision and it is possible that they or other local governments in California may pass similar legislation following AB 3233. We currently only operate in Kern County and at this time we are not aware of any local governments within Kern County that to seek to materially limit or otherwise prohibit oil and gas operations within its jurisdiction. However, it is difficult to predict how local governments in California may choose to exercise their new authority under AB 3233. While there may be future legal challenges to AB 3233 and any local ordinances enacted thereunder, we cannot predict whether or not such challenges will be successful, or if AB 3233 or any ordinances enacted pursuant to it will be stayed pending the outcome of such challenges. Notwithstanding any potential claims for regulatory takings we may have in the event local jurisdictions seek to prohibit any of our existing operations, any restrictions that materially limit or prohibit oil and gas production in the areas where we operate could materially impact our operations and financial condition.
We may not be successful in refinancing, repaying or extending the maturity of our 2026 Notes or our 2021 RBL Facility, and any such refinancing may not be obtainable on terms favorable to us.
The 2021 RBL Facility matures on August 26, 2025 and the 2026 Notes mature on February 15, 2026. The 2021 RBL Facility is classified as current debt on our balance sheet, and if we are not able to refinance the 2026 Notes, the 2026 Notes will be classified as current debt as of February 15, 2025. Management's ongoing assessment of the Company's ability to repay the 2021 RBL Facility and our 2026 Notes upon maturity could result in a going concern qualification with respect to our annual audited financial statements. Although we have entered into the 2024 Term Loan Credit Agreement which provides for commitments that we may use to refinance the 2026 Notes and the 2021 RBL Facility, we may not be able to borrow under such commitments if a condition precedent to funding is not satisfied or if the lenders thereunder default under their commitments. As a result, we may be unable to repay the 2021 RBL Facility or the 2026 Notes on their respective maturity dates and could be forced to sell assets, undergo a recapitalization or raise additional equity capital or seek bankruptcy protection.
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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 three and nine months ended September 30, 2024. As of September 30, 2024, 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 16% of outstanding shares as of September 30, 2024.
As of September 30, 2024, 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.
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
(c) Trading Plans
On September 5, 2024, Fernando Araujo, Chief Executive Officer and Director, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c) for the sale of up to 62,286 shares of the Company's common stock until August 30, 2025.
On August 27, 2024, Danielle Hunter, President, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense of Rule 10b5-1(c) for the sale of up to 200,000 shares of the Company's common stock until December 31, 2025.
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Item 6. Exhibits
Exhibit Number Description
3.1
3.2
3.3
3.4
10.1*
Senior Secured Term Loan Credit Agreement, dated as of November 6, 2024, among Berry Corporation (Bry), the guarantors party thereto, the lenders party thereto, and Breakwall Credit Management LLC, as administrative agent for the lenders
10.2
31.1*
Section 302 Certification of Chief Executive Officer
31.2*
Section 302 Certification of Chief Financial Officer
32.1*
Section 906 Certification of Chief Executive Officer and Chief Financial Officer
101.INS*
Inline XBRL Instance Document (the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
101.SCH*
Inline XBRL Taxonomy Extension Schema Document
101.CAL*
Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
Inline XBRL Taxonomy Extension Label Linkbase Data Document
101.PRE*
Inline XBRL Taxonomy Extension Presentation Linkbase Document
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
__________
(*) Filed herewith.
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GLOSSARY OF COMMONLY USED TERMS
The following are abbreviations and definitions of certain terms that may be used in this report, which are commonly used in the oil and natural gas industry:
"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 business segment in California.
"Clean Water Rule" refers to the rule issued in August 2015 by the EPA and U.S. Army Corps of Engineers which expanded the scope of the federal jurisdiction over wetlands and other types of waters.
"Completion" means the installation of permanent equipment for the production of oil or natural gas.
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"Condensate" means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
"CPUC" is an abbreviation for the California Public Utilities Commission.
"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.
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"Horizontal drilling" means a wellbore that is drilled laterally.
"Hydraulic fracturing" means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability.
"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.
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"Net Acres" or "Net Wells" is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.
"Net revenue interest" means all of the working interests, less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.
"NGA" is an abbreviation for the Natural Gas Act.
"NGL" or "NGLs" means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
"NRI" is an abbreviation for net revenue interest.
"NYMEX" means New York Mercantile Exchange.
"Oil" means crude oil or condensate.
"OPEC" is an abbreviation for the Organization of the Petroleum Exporting Countries.
"Operator" means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.
"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.
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"Proved developed producing reserves" means reserves that are being recovered through existing wells with existing equipment and operating methods.
"Proved reserves" means the estimated quantities of oil, gas and gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
"Proved undeveloped drilling location" means a site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
"Proved undeveloped reserves" or "PUDs" means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
"PSUs" means performance-based restricted stock units
"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
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results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
"Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
"Resources" means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
"Royalty" means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
"Royalty interest" means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.
"RSUs" is an abbreviation for restricted stock units.
"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.
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"Unconventional resource plays" means a resource play that uses methods other than traditional vertical well extraction. Unconventional resources are trapped in reservoirs with low permeability, meaning little to no ability for the oil or natural gas to flow through the rock and into a wellbore. Examples of unconventional oil resources include oil shales, oil sands, extra-heavy oil, gas-to-liquids and coal-to-liquids.
"Undeveloped acreage" means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.
"Unit" means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
"Unproved reserves" means reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.
"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 8, 2024
/s/ Fernando Araujo
Fernando Araujo
Chief Executive Officer
(Principal Executive Officer)
Date: November 8, 2024
/s/ Michael S. Helm
Michael S. Helm
Vice President, Chief Financial Officer and
Chief Accounting Officer
(Principal Financial Officer and
Principal Accounting Officer)
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