SEC Filing | Berry Corporation (bry)

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bry-20220930

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, 2022


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

For the transition period from_______________ to _______________

Commission file number 001-38606

Berry Corporation (bry)

(Exact name of registrant as specified in its charter)


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

16000 Dallas Parkway, Suite 500

Dallas, Texas 75248

(661) 616-3900

(Address of principal executive offices, including zip code

Registrant’s telephone number, including area code)

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


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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐

Accelerated filer ☒

Non-accelerated filer ☐

Smaller reporting company ☐

Emerging Growth Company ☒

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

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

Shares of common stock outstanding as of October 31, 2022 76,767,503

Table of Contents


		Page
Part I – Financial Information
Item 1.	Financial Statements (unaudited)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Stockholders’ Equity	3
	Condensed Consolidated Statements of Cash Flows	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	67
Item 4.	Controls and Procedures	67

Part II – Other Information
Item 1.	Legal Proceedings	68
Item 1A.	Risk Factors	69
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities	69
Item 6.	Exhibits	71
	Glossary of Terms	72
	Signatures	80

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

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements (unaudited)

BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2022		December 31, 2021
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	41,473	$	15,283
Accounts receivable, net of allowance for doubtful accounts of $866 at September 30, 2022 and $866 at December 31, 2021	93,635		86,269
Derivative instruments	10,052		—

Other current assets	36,738		45,946
Total current assets	181,898		147,498
Noncurrent assets:
Oil and natural gas properties	1,658,008		1,537,894
Accumulated depletion and amortization	(434,447)		(340,328)
Total oil and natural gas properties, net	1,223,561		1,197,566
Other property and equipment	148,118		140,710
Accumulated depreciation	(51,699)		(36,927)
Total other property and equipment, net	96,419		103,783
Derivative instruments	11,588		1,070

Other noncurrent assets	10,886		6,562
Total assets	$	1,524,352	$	1,456,479
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	156,844	$	157,524
Derivative instruments	20,954		29,625


Total current liabilities	177,798		187,149
Noncurrent liabilities:
Long-term debt	395,432		394,566
Derivative instruments	4,245		18,577
Deferred income taxes	8,042		1,831
Asset retirement obligations	137,751		143,926
Other noncurrent liabilities	31,835		17,782
Commitments and Contingencies - Note 4
Stockholders' Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 86,350,771 and 85,590,417 shares issued; and 76,767,503 and 80,007,149 shares outstanding, at September 30, 2022 and December 31, 2021, respectively)	86		86
Additional paid-in-capital	852,568		912,471
Treasury stock, at cost (9,583,268 and 5,583,268 shares at September 30, 2022 and December 31, 2021, respectively)	(94,136)		(52,436)
Retained earnings (deficit)	10,731		(167,473)
Total stockholders' equity	769,249		692,648
Total liabilities and stockholders' equity	$	1,524,352	$	1,456,479

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

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BERRY CORPORATION (bry)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	203,585	$	161,058	$	654,007	$	444,098
Services revenue	48,594		—		134,608		—
Electricity sales	9,711		12,371		22,549		29,328
Gains (losses) on oil and gas sales derivatives	114,279		(30,864)		(88,237)		(140,021)
Marketing revenues	—		732		289		3,087
Other revenues	277		117		442		372
Total revenues and other	376,446		143,414		723,658		336,864
Expenses and other:
Lease operating expenses	79,141		60,930		214,720		168,756
Costs of services	37,628		—		107,809		—
Electricity generation expenses	6,055		7,128		16,640		19,488
Transportation expenses	1,277		1,806		3,543		5,139
Marketing expenses	—		715		299		2,986
General and administrative expenses	23,388		17,614		69,513		50,749
Depreciation, depletion, and amortization	39,506		35,902		117,338		105,592

Taxes, other than income taxes	7,335		13,420		25,154		34,580

Gains on natural gas purchase derivatives	(28,942)		(14,980)		(47,335)		(54,349)
Other operating expenses	623		3,986		4,745		4,827
Total expenses and other	166,011		126,521		512,426		337,768
Other (expenses) income:
Interest expense	(7,867)		(7,810)		(23,271)		(24,513)
Other, net	(24)		(5)		(79)		(156)
Total other expenses	(7,891)		(7,815)		(23,350)		(24,669)

Income (loss) before income taxes	202,544		9,078		187,882		(25,573)
Income tax expense (benefit)	10,884		(758)		9,678		(1,206)
Net income (loss)	$	191,660	$	9,836	$	178,204	$	(24,367)



Net income (loss) per share:
Basic	$	2.46	$	0.12	$	2.25	$	(0.30)
Diluted	$	2.34	$	0.12	$	2.13	$	(0.30)

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

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

Dividends declared on common stock, $0.04/share	—		(3,474)		—		—		(3,474)
Net loss	—		—		—		(21,322)		(21,322)
March 31, 2021	86		914,956		(49,995)		(173,253)		691,794
Shares withheld for payment of taxes on equity awards and other	—		(78)		—		—		(78)
Stock based compensation	—		3,042		—		—		3,042
Dividends declared on common stock, $0.04/share	—		(3,219)		—		—		(3,219)
Net loss	—		—		—		(12,881)		(12,881)
June 30, 2021	86		914,701		(49,995)		(186,134)		678,658
Shares withheld for payment of taxes on equity awards and other	—		(23)		—		—		(23)
Stock based compensation	—		3,672		—		—		3,672
Purchases of treasury stock	—		—		(2,441)		—		(2,441)
Dividends declared on common stock, $0.06/share	—		(4,806)		—		—		(4,806)
Net income	—		—		—		9,836		9,836
September 30, 2021	$	86	$	913,544	$	(52,436)	$	(176,298)	$	684,896

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, 2022
	Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Earnings (Deficit)		Total Stockholders’ Equity
	(in thousands)
December 31, 2021	$	86	$	912,471	$	(52,436)	$	(167,473)	$	692,648

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


Dividends declared on common stock, $0.06/share	—		(5,236)		—		—		(5,236)
Net loss	—		—		—		(56,810)		(56,810)
March 31, 2022	86		907,059		(52,436)		(224,283)		630,426
Shares withheld for payment of taxes on equity awards and other	—		(6)		—		—		(6)
Stock based compensation	—		4,720		—		—		4,720

Purchases of treasury stock	—		—		(22,760)		—		(22,760)
Dividends declared on common stock, $0.19/share	—		(14,965)		—		—		(14,965)
Net income	—		—		—		43,354		43,354
June 30, 2022	86		896,808		(75,196)		(180,929)		640,769
Shares withheld for payment of taxes on equity awards and other	—		(34)		—		—		(34)
Stock based compensation	—		4,625		—		—		4,625
Purchases of treasury stock	—		—		(18,940)		—		(18,940)
Dividends declared on common stock, $0.62/share	—		(48,831)		—		—		(48,831)
Net income	—		—		—		191,660		191,660
September 30, 2022	$	86	$	852,568	$	(94,136)	$	10,731	$	769,249

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,
	2022		2021
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	178,204	$	(24,367)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	117,338		105,592
Amortization of debt issuance costs	1,531		3,839

Stock-based compensation expense	12,623		10,219
Deferred income taxes	6,211		(1,231)
Decrease in allowance for doubtful accounts	—		(500)
Other operating (income) expenses	(120)		3,988

Derivative activities:
Total losses	40,902		85,672
Cash settlements on derivatives	(84,519)		(54,204)

Changes in assets and liabilities:
Increase in accounts receivable	(7,334)		(16,760)
Decrease (increase) in other assets	2,320		(19,062)
Decrease in accounts payable and accrued expenses	(11,281)		(11,343)
(Decrease) increase in other liabilities	(341)		415
Net cash provided by operating activities	255,534		82,258

Cash flows from investing activities:
Capital expenditures:
Capital expenditures	(102,523)		(105,046)


Changes in capital expenditures accruals	14,129		5,299

Acquisitions, net of cash received	(21,270)		(11,649)


Proceeds from sale of property and equipment and other	—		860

Net cash used in investing activities	(109,664)		(110,536)

Cash flows from financing activities:
Borrowings under 2021 RBL credit facility	206,000		—
Repayments on 2021 RBL credit facility	(206,000)		—
Borrowings under 2022 ABL credit facility	2,067		—
Repayments on 2022 ABL credit facility	(2,067)		—


Dividends paid on common stock	(73,844)		(6,686)
Purchase of treasury stock	(41,700)		(2,440)
Shares withheld for payment of taxes on equity awards and other	(4,136)		(1,543)

Debt issuance costs	—		(3,449)







Net cash used in financing activities	(119,680)		(14,118)
Net increase (decrease) in cash and cash equivalents	26,190		(42,396)
Cash and cash equivalents:
Beginning	15,283		80,557
Ending	$	41,473	$	38,161

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

Nature of Business

We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional oil and gas reserves in the San Joaquin basin of California and the Uinta basin of Utah, with well servicing and abandonment capabilities in California. Since October 1, 2021, we have operated in two business segments: (i) development and production (“D&P”) and (ii) well servicing and abandonment.

Berry Corp. was incorporated under Delaware law in February 2017 and its common stock began trading on NASDAQ under the symbol “bry” in July 2018. Berry Corp. operates through its three wholly owned subsidiaries. Berry LLC owns and operates our oil and gas assets (D&P segment). In January 2022, we divested our natural gas properties in the Piceance basin of Colorado. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which now constitutes our well servicing and abandonment segment, also referred to as “CJWS”.

Principles of Consolidation and Reporting

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

We prepared this report pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”) applicable to interim financial information, which permit the omission of certain disclosures to the extent they have not changed materially since the latest annual financial statements. We believe our disclosures are adequate to make the disclosed information not misleading. The results reported in these unaudited condensed consolidated financial statements may not accurately forecast results for future periods. This Quarterly Report on Form 10-Q should be read in conjunction with the consolidated financial statements and the notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2021.

New Accounting Standards Adopted

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is an update to the lease standard providing an optional transition approach for land easements allowing entities to evaluate only new or modified land easements. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842), which provided optional transition relief allowing a prospective approach in applying the new rules by not adjusting comparative period financial information for the effects of the new rules and not requiring disclosures for periods before the effective date. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers. During the second quarter of 2020, this adoption date was further delayed by

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

FASB until fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We adopted these rules in the first quarter of 2022 prospectively.

Note 2—Debt

The following table summarizes our outstanding debt:


	September 30, 2022		December 31, 2021		Interest Rate	Maturity	Security
	(in thousands)
2021 RBL Facility	$	—	$	—	variable rates 7.5% (2022) and 5.3% (2021)	August 26, 2025	Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets
2022 ABL Facility	—		n/a		variable rates 6.8% (2022)	June 5, 2025	Personal property assets, other than excluded accounts

2026 Notes	400,000		400,000		7.0%	February 15, 2026	Unsecured
Long-Term Debt - Principal Amount	400,000		400,000
Less: Debt Issuance Costs	(4,568)		(5,434)
Long-Term Debt, net	$	395,432	$	394,566

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At September 30, 2022 and December 31, 2021, debt issuance costs for the 2021 RBL Facility (as defined below) reported in “other noncurrent assets” on the balance sheet were approximately $4 million and $5 million net of amortization, respectively. At September 30, 2022 and December 31, 2021, debt issuance costs, net of amortization, for the unsecured notes due February 2026 (the “2026 Notes”) reported in “Long-Term Debt, net” on the balance sheet was approximately $5 million.

For each of the three month periods ended September 30, 2022 and 2021, the amortization expense for the 2021 RBL Facility, the 2017 RBL Facility (as defined below) and the 2026 Notes, combined, was approximately $1 million. For each of the nine month periods ended September 30, 2022 and 2021, the amortization expense for the 2021 RBL Facility, the 2017 RBL Facility and the 2026 Notes, combined, was approximately $2 million and $4 million, respectively. The amortization of debt issuance costs is presented in “interest expense” in 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, classified as Level 1, because the interest rates are variable and reflect market rates. The fair value of the 2026 Notes was approximately $359 million and $400 million at September 30, 2022 and December 31, 2021, respectively.

2021 RBL Facility

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Issuances of letters of credit reduce the borrowing availability for revolving loans under the 2021 RBL Facility on a dollar for dollar basis. The 2021 RBL Facility matures on August 26, 2025, unless terminated earlier in accordance with the 2021 RBL Facility terms. Borrowing base redeterminations generally become effective each May and November, although the borrower and the lenders may each make one interim redetermination between scheduled redeterminations. In December 2021, we completed the first scheduled semi-annual borrowing base redetermination and entered into that certain First Amendment to Credit Agreement (the “First Amendment”), which resulted in a reaffirmed borrowing base at $200 million and changes to the hedging covenants in respect of the exclusion of short puts or similar derivatives in the calculation of minimum and maximum hedging requirements.

In May 2022, Berry Corp., as a guarantor, and Berry LLC, as the borrower, entered into that certain Second Amendment to Credit Agreement and Limited Consent and Waiver (the “Second Amendment”) pursuant to which, among other things, the requisite lenders under the 2021 RBL Facility (i) consented to certain dividends and distributions and to certain investments made by Berry LLC in C&J and/or C&J Management, in each case, as further described therein, (ii) waived certain minimum hedging requirements for the time periods described therein, (iii) waived any breach, default or event of default which may have arisen as a result of any of the foregoing, (iv) amended the restricted payments covenant to give us additional flexibility to make restricted payments, subject to satisfaction of certain leverage and availability conditions and other conditions described below and in the Second Amendment and (v) amended the minimum hedging covenant to not, until October 1, 2022, require hedges for any full calendar month from and after January 1, 2025, as further described in the Second Amendment. In May 2022, we also completed our semi-annual borrowing base redetermination and entered into the Third Amendment to the Credit Agreement (the “Third Amendment”), which among other things (1) increased the borrowing base from $200 million to $250 million; (2) established the Aggregate Elected Commitment Amounts (as defined in the 2021 RBL Facility) at $200 million initially; and (3) converted all outstanding Eurodollar Loans (into Term Benchmark Loans (each as defined in the 2021 RBL Facility) with an initial interest period of one-month’s duration and otherwise give effect to the transition from the London interbank offered rate (“LIBOR”) to the secured overnight financing rate (“SOFR”) by replacing the adjusted LIBOR rate with the term SOFR rate for one, three or six months plus 0.1% (subject to a floor of 0.5%).

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

The outstanding borrowings under the revolving loan bear interest at a rate equal to either (i) a customary base rate plus an applicable margin ranging from 2.0% to 3.0% per annum, and (ii) a customary benchmark rate plus an applicable margin ranging from 3.0% to 4.0% per annum, and in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.5% on the average daily unused amount of the borrowing availability under the 2021 RBL Facility. We have the right to prepay any borrowings under the 2021 RBL Facility with prior notice at any time without a prepayment penalty.

The 2021 RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a leverage ratio of not more than 3.0 to 1.0 and (ii) a current ratio of not less than 1.0 to 1.0. As of September 30, 2022, our leverage ratio and current ratio were 1.2:1.0 and 2.3:1.0, respectively. In addition, the 2021 RBL Facility currently provides that, to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. We were in compliance with all financial covenants under the 2021 RBL Facility as of September 30, 2022.

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

The 2021 RBL Facility contains usual and customary events of default and remedies for credit facilities of a similar nature. The 2021 RBL Facility also places restrictions on the borrower and its restricted subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of the borrower’s senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

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

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

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

As of September 30, 2022, we had no borrowings outstanding, $7 million in letters of credit outstanding and approximately $193 million of available borrowing capacity under the 2021 RBL Facility.

2022 ABL Facility

On August 9, 2022, C&J and C&J Management, which are the two entities that constitute the well servicing and abandonment segment referred to as CJWS, as borrowers, entered into a credit agreement with Tri Counties Bank, as lender, that provides for a revolving loan facility, subject to satisfaction of customary conditions precedent to borrowing, of up to the lesser of (x) $15 million and (y) the borrowing base (“the “2022 ABL Facility”). The “borrowing base” is an amount equal to 80% percent of the balance due on eligible accounts receivable, subject to reserves that Tri Counties Bank may implement in its reasonable discretion. Interest on the outstanding principal amount of the revolving loans under the 2022 ABL Facility accrues at a per annum rate equal to 1.25% in excess of The Wall Street Journal Prime Rate. The “Wall Street Journal Prime Rate” is the variable rate of interest, on a per annum basis, which is announced and/or published in the “Money Rates” section of The Wall Street Journal from time to time as its “Prime Rate”. The rate will be redetermined whenever The Wall Street Journal Prime Rate changes. Interest is due quarterly, in arrears, starting on September 30, 2022 and will continue to be due and payable in arrears on the last day of each calendar quarter thereafter. On June 5, 2025 the entire unpaid principal balance of the revolving loans under the 2022 ABL Facility, and all unpaid interest thereon, will be due and payable. The 2022 ABL Facility provides a letter of credit sub-facility for the issuance of letters of credit in an aggregate amount not to exceed $7.5 million.

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

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The 2022 ABL Facility contains usual and customary events of default and remedies for credit facilities of a similar nature. The 2022 ABL Facility also places restrictions on CJWS with respect to additional indebtedness, liens, dividends and other distributions, investments, acquisitions, mergers, asset dispositions and other matters. CJWS’s obligations under the 2022 ABL Facility are not guaranteed by Berry Corp. or Berry LLC and Berry Corp. and Berry LLC do not and are not required to provide any credit support for such obligations. We were in compliance with all financial covenants under the 2022 ABL Facility as of September 30, 2022.

As of September 30, 2022, CJWS had no borrowings and no letters of credit outstanding with $15 million of available borrowing capacity under the 2022 ABL Facility.

2017 RBL Facility

On July 31, 2017, we entered into a credit agreement that provided for a revolving loan with up to $1.5 billion of commitment, subject to a reserve borrowing base (“2017 RBL Facility”). On August 26, 2021, we cancelled the 2017 RBL Facility agreement, which had a borrowing base of $200 million and there were no borrowings outstanding at the time of cancellation.

Debt Repurchase Program

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

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 the hedging requirements of the 2021 RBL Facility, we target covering our operating expenses and a majority of our fixed charges, which includes capital needed to sustain production levels, as well as interest and fixed dividends as applicable, with the oil and gas sales hedges for a period of up to three years out. Additionally, we target fixing the price for a large portion of our natural gas purchases used in our steam operations for up to three years. We have also entered into Utah gas transportation contracts to help reduce the price fluctuation exposure, however these do not qualify as hedges. We also, from time to time, have entered into agreements to purchase a portion of the natural gas we require for our operations, which we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions. We had no such transactions in the periods presented.

For fixed-price oil and gas sales swaps, we are the seller, so we make settlement payments for prices above the indicated weighted-average price per 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 long put spreads, in addition to any deferred premium payments, we would receive settlement payments for prices below the indicated highest price of the long put with the maximum payment received per bbl equal to the difference between the indicated prices of the long and short put. No payment would be made or received for prices above the highest indicated price of the long put. The short put spreads offset the long put spreads.

A Producer Collar is used for the sale of our produced oil and is the combination of buying a put option and selling a call option. We would receive settlement payments for prices below the indicated weighted-average price per bbl of the put option and we would make settlement payments for prices above the indicated weighted-average price of the call option. No payment would be made or received for prices in between the indicated weighted-average price of the put and call.

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A Consumer Collar is used for the purchase of fuel gas and is the combination of buying a call option and selling a put option. We would receive settlement payments for prices above the indicated weighted-average price of the call option and we would make settlement payments for prices below the indicated weighted-average price of the put option. No payment would be made or received for prices in between the indicated weighted-average price of the put and call.

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, 2022 we have net payable deferred premiums of approximately $6 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.

As of September 30, 2022, we had the following hedges for our crude oil production and natural gas purchases.


	Q4 2022		FY 2023		FY 2024		FY 2025
Brent - Crude Oil production
Swaps
Hedged volume (bbls)	1,288,000		3,433,528		1,917,000		—
Weighted-average price ($/bbl)	$	76.07	$	73.06	$	75.52	$	—

Put Spreads
Long $50/$40 Put Spread hedged volume (bbls)	414,000		2,555,000		1,647,000		—
Short $50/$40 Put Spread hedged volume (bbls)	46,000		365,000		366,000		—

Producer Collars							—
Hedged volume (bbls)	—		1,460,000		1,098,000		—
Weighted-average price ($/bbl)	$	—	$40.00/$106.00		$40.00/$105.00		$	—



Henry Hub - Natural Gas purchases



Consumer Collars
Hedged volume (mmbtu)	3,680,000		5,430,000		—		—
Weighted-average price ($/mmbtu)	$4.00/$2.75		$4.00/$2.75		$	—	$	—
NWPL - Natural Gas purchases
Swaps
Hedged volume (mmbtu)	1,220,000		12,800,000		7,320,000		6,080,000
Weighted-average price ($/mmbtu)	$	6.40	$	5.48	$	4.27	$	4.27

In addition to the table above, in October we added the following sold oil swaps (Brent): 3,750 bbl/d at $90.48 beginning November 2022 through December 2022, 4,000 bbl/d at $82.85 beginning January 2023 through December 2023, 1,500 bbl/d at $89.00 beginning January 2023 through June 2023, 3,335 bbl/d at $76.58 beginning January 2024 through December 2024, and 1,250 bbl/d at $77.95 beginning July 2024 through December 2024. Including these additional swaps, our swap position increased to 10,049,388 bbls at a weighted-average price of $76.70.

In October we also added Producer Collars (Brent) of 1,000 bbl/d for 2025 at $50.00/$98.50, which are in addition to the table above.

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Our commodity derivatives are measured at fair value using industry-standard models with various inputs including publicly available underlying commodity prices and forward curves, and all are classified as Level 2 in the required fair value hierarchy for the periods presented. These commodity derivatives are subject to counterparty netting. The following tables present the fair values (gross and net) of our outstanding derivatives as of September 30, 2022 and December 31, 2021:


	September 30, 2022
	Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
	(in thousands)
Assets:
Commodity Contracts	Current assets	$	36,857	$	(26,805)	$	10,052
Commodity Contracts	Non-current assets	43,435		(31,847)		11,588
Liabilities:
Commodity Contracts	Current liabilities	(47,759)		26,805		(20,954)
Commodity Contracts	Non-current liabilities	(36,092)		31,847		(4,245)
Total derivatives		$	(3,559)	$	—	$	(3,559)


	December 31, 2021
	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	$	5,360	$	(5,360)	$	—
Commodity Contracts	Non-current assets	29,828		(28,758)		1,070
Liabilities:
Commodity Contracts	Current liabilities	(34,985)		5,360		(29,625)
Commodity Contracts	Non-current liabilities	(47,335)		28,758		(18,577)
Total derivatives		$	(47,132)	$	—	$	(47,132)

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

We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, our 2021 RBL Facility prevents us from entering into hedging arrangements that are secured, except with our lenders and their affiliates that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A or A2 credit rating or better from Standards & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives which partially mitigates the counterparty nonperformance risk.

Note 4—Lawsuits, Claims, Commitments and Contingencies

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

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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, 2022 and December 31, 2021. 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, 2022, we are not aware of material indemnity claims pending or threatened against us.

Securities Litigation Matters

On November 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class action lawsuit (the “Torres Lawsuit”) in the United States District Court for the Northern District of Texas against Berry Corp. and certain of its current and former directors and officers (collectively, the “Defendants”). The complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933, and Sections 10(b) and 20(a) of the Exchange Act, on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.'s securities between July 26, 2018 and November 3, 2020 (the “Class Period”). In particular, the complaint alleges that the Defendants made false and misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined following release of its financial results for the third quarter of 2020 on November 3, 2020.

On January 21, 2021, multiple plaintiffs filed motions in the Torres Lawsuit seeking to be appointed lead plaintiff and lead counsel. After briefing and a stipulation between the remaining movants, the Court appointed Luis Torres and Allia DeAngelis as co-lead plaintiffs on August 18, 2021. On November 1, 2021, the co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on January 24, 2022, and on September 13, 2022, the Court issued an order denying that motion. The Defendants have moved for reconsideration and/or clarification of the September 13 order, and that motion is currently pending.

We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the preliminary stage of the case, and the legal standards that must be met for, among other things, class certification and success on the merits, we cannot reasonably estimate the possible loss or range of loss that may result from this action.

On October 20, 2022, a shareholder derivative lawsuit was filed in the United States District Court for the Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that piggy-backs on the securities class action referenced above and which is currently pending before the same Court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. The Company and the individual defendants believe the claims in the shareholder derivative action are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to this matter.

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(Unaudited)

Note 5—Equity

Cash Dividends

For the nine months ended September 30, 2022, our Board of Directors declared quarterly fixed cash dividends totaling $0.18 per share, as well as variable cash dividends of $0.69 per share which were based on the results of the first two quarters of 2022, for a total of $0.87 per share. In October 2022, the Board of Directors approved the fourth quarter $0.06 per share fixed cash dividend, as well as a variable dividend of $0.41 based on the third quarter results.

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

Stock Repurchase Program

We repurchased 2,000,000 shares during the three months ended September 30, 2022 for approximately $19 million. For the nine months ended September 30, 2022, we repurchased 4,000,000 shares for approximately $42 million. As of September 30, 2022, the Company had repurchased a total of 9,528,704 shares under the stock repurchase program for approximately $94 million in aggregate, which is 12% of outstanding shares. As previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company intends to allocate a portion of Discretionary Free Cash Flow to opportunistic share repurchases.

In April 2022, our Board of Directors approved an increase of $102 million to the Company’s stock repurchase authorization bringing the Company’s remaining share repurchase authority to $150 million. As of September 30, 2022, the Company’s remaining total share repurchase authority is $108 million, after the repurchases made in the second and third quarters of 2022. The Board’s authorization permits the Company to make purchases of its common stock from time to time in the open market and in privately negotiated transactions, subject to market conditions and other factors, up to the aggregate amount authorized by the Board. The Board’s authorization has no expiration date.

Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate the company to purchase shares during any period or at all. Any shares repurchased are reflected as treasury stock and any shares acquired will be available for general corporate purposes.

Stock-Based Compensation

In February 2022, the Company granted awards of approximately 1,300,000 shares of restricted stock units (“RSUs”), which will vest annually in equal amounts over three years. In March 2022, the Company granted awards of approximately 611,000 shares performance-based restricted stock units (“PSUs”), which will cliff vest, if at all, at the end of a three year performance period. The RSUs awarded are equity awards as they will be settled in stock. The PSUs awarded were accounted for as liability awards as of March 31, 2022, but converted to equity awards during the second quarter of 2022. The accounting of the awards was converted as a result of the 2022 Omnibus Incentive Plan (the “2022 Plan”) being approved by the stockholders in May 2022. The fair value of these awards was approximately $19 million on the date the 2022 Plan was approved and this will be the value of these awards through the date of their vesting.

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

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(Unaudited)

awards will vest, if at all, based on the consolidated Company's average cash returned on invested capital (“CROIC PSUs”) over the performance period. The PSUs awarded to certain CJWS employees in March 2022 will vest, if at all, based on the CJWS average cash returned on invested capital (“ROIC PSUs”) over the performance period. Depending on the results achieved during the three-year performance period, the actual number of shares that a grant recipient receives at the end of the period may range from 0% to 250% of the TSR PSUs granted and from 0% to 200% of the CROIC and ROIC PSUs granted.

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

Note 6—Supplemental Disclosures to the Financial Statements

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


	September 30, 2022		December 31, 2021
	(in thousands)
Prepaid expenses	$	20,362	$	26,840
Materials and supplies	10,068		9,533

Deposits	3,459		6,415

Oil inventories	2,623		2,933
Other	226		225
Total other current assets	$	36,738	$	45,946

Other non-current assets at September 30, 2022 included approximately $7 million of operating lease right-of-use assets, net of amortization and $4 million of deferred financing costs, net of amortization. At December 31, 2021 other non-current assets included approximately $5 million of deferred financing costs, net of amortization.

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


	September 30, 2022		December 31, 2021
	(in thousands)
Accounts payable-trade	$	19,987	$	17,699
Accrued expenses	70,038		62,962
Royalties payable	28,798		24,816
Greenhouse gas liability - current portion	—		7,513
Taxes other than income tax liability	11,303		8,273
Accrued interest	3,811		10,736
Dividends payable	—		4,800
Asset retirement obligations - current portion	20,000		20,000
Operating lease liability	1,749		—
Other	1,158		725
Total accounts payable and accrued expenses	$	156,844	$	157,524

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(Unaudited)

The decrease of $6 million in the long-term portion of the asset retirement obligations from $144 million at December 31, 2021 to $138 million at September 30, 2022 was due to $16 million of liabilities settled during the period, and a $1 million reduction related to property sales. These decreases were offset by $8 million of accretion and $3 million of liabilities incurred.

Other noncurrent liabilities at September 30, 2022 included approximately $26 million of greenhouse gas liability and $6 million of operating lease noncurrent liability. For December 31, 2021, we had $18 million in greenhouse gas liability.

Supplemental Information on the Statement of Operations

For the three months ended September 30, 2022, other operating expenses were less than $1 million. For the three months ended September 30, 2021, other operating expenses were $4 million and mainly consisted of expensing $3 million of unamortized debt issuance costs related to the termination of the 2017 RBL Facility.

For the nine months ended September 30, 2022, other operating expenses were $5 million and mainly consisted of over $2 million in royalty audit charges incurred prior to our emergence and restructuring in 2017, and approximately $2 million loss on the divestiture of the Piceance properties. For the nine months ended September 30, 2021, other operating expenses were $5 million and mainly consisted of approximately $3 million of unamortized debt issuance costs related to the termination of the 2017 RBL Facility, approximately $3 million of supplemental property tax assessments, royalty audit charges and tank rental costs and $1 million of various other costs such as abandonment costs and legal fees, partially offset by $2 million of income from employee retention credits.

Supplemental Cash Flow Information

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




	Nine Months Ended September 30,
	2022		2021
	(in thousands)


Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties	$	1,494	$	2,916
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	$	29,481	$	29,114
Income taxes payments	$	2,805	$	294

Note 7—Earnings Per Share

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

The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the three months ended September 30, 2022 and September 30, 2021, 4,001,000 and 2,656,000 incremental RSU and PSU shares were included in the diluted EPS calculation. For the nine months ended September 30, 2022, 4,168,000 incremental RSU and PSU shares were included in the diluted EPS calculation. For the nine months ended September 30, 2021, no incremental RSU or PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the “if converted” method.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)




	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(in thousands except per share amounts)
Basic EPS calculation
Net income (loss)	$	191,660	$	9,836	$	178,204	$	(24,367)




Weighted-average shares of common stock outstanding	78,044		80,242		79,304		80,277
Basic income (loss) per share	$	2.46	$	0.12	$	2.25	$	(0.30)
Diluted EPS calculation
Net income (loss)	$	191,660	$	9,836	$	178,204	$	(24,367)




Weighted-average shares of common stock outstanding	78,044		80,242		79,304		80,277
Dilutive effect of potentially dilutive securities(1)	4,001		2,656		4,168		—
Weighted-average common shares outstanding - diluted	82,045		82,898		83,472		80,277
Diluted income (loss) per share	$	2.34	$	0.12	$	2.13	$	(0.30)

__________

(1) We excluded approximately 2.4 million of combined RSUs and PSUs from the dilutive weighted-average common shares outstanding for the nine months ended September 30, 2021, because their effect was anti-dilutive.

Note 8—Revenue Recognition

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

The following table provides disaggregated revenue for the three and nine months ended September 30, 2022 and 2021:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(in thousands)
Oil sales	$	194,418	$	152,536	$	627,759	$	416,204
Natural gas sales	7,575		6,922		20,906		24,414
Natural gas liquids sales	1,592		1,600		5,342		3,480
Service revenue	48,594		—		134,608		—
Electricity sales	9,711		12,371		22,549		29,328
Marketing revenues	—		732		289		3,087
Other revenues	277		117		442		372
Revenues from contracts with customers	262,167		174,278		811,895		476,885
Gains (losses) on oil and gas sales derivatives	114,279		(30,864)		(88,237)		(140,021)
Total revenues and other	$	376,446	$	143,414	$	723,658	$	336,864

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(Unaudited)

Note 9—Acquisition and Divestiture

2022

Piceance Divestiture

In January 2022, we completed the divestiture of all of our natural gas properties in Colorado, which were in the Piceance basin. The divestiture closed with a loss of approximately $2 million. Our 2021 production from these properties was 1.2 mboe/d.

Antelope Creek Acquisition

In February 2022, we completed the acquisition of oil and gas producing assets in the Antelope Creek area of Utah for approximately $18 million. These assets are adjacent to our existing Uinta assets and prior to our acquisition produced approximately 0.6 mboe/d.

Note 10—Segment Information

As of October 1, 2021, we have operated in two business segments: (i) development and production and (ii) well servicing and abandonment. The development and production segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of an upstream well servicing and abandonment business in California, which became a reportable segment (well servicing and abandonment) under U.S. GAAP. Prior to October 1, 2021, we did not have more than one reportable segment, thus no prior period segment information has been presented.

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


	Three Months Ended September 30, 2022
	Development & Production		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues - excluding hedges	$	213,573	$	49,427	$	(833)	$	262,167
Net income (loss)	$	224,094	$	5,168	$	(37,602)	$	191,660
Adjusted EBITDA	$	102,763	$	7,726	$	(13,508)	$	96,981
Capital expenditures	$	38,312	$	1,726	$	779	$	40,817
Total assets	$	1,502,135	$	79,696	$	(57,479)	$	1,524,352


	Nine Months Ended September 30, 2022
	Development & Production		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues - excluding hedges	$	677,287	$	135,441	$	(833)	$	811,895
Net income (loss)	$	258,689	$	8,191	$	(88,676)	$	178,204
Adjusted EBITDA	$	325,354	$	17,225	$	(40,139)	$	302,440
Capital expenditures	$	96,883	$	3,420	$	2,220	$	102,523
Total assets	$	1,502,135	$	79,696	$	(57,479)	$	1,524,352

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Adjusted EBITDA is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources to and assessing performance of each segment. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. Adjusted EBITDA is calculated as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items. While Adjusted EBITDA is a non-GAAP measure, the amounts included in the calculations of Adjusted EBITDA, were computed in accordance with GAAP. This measure is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP and should not be considered as an alternative to, or more meaningful than, income and liquidity measures calculated in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.


	Three Months Ended September 30, 2022
	Development & Production		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	224,094	$	5,168	$	(37,602)	$	191,660
Add (Subtract):
Interest expense	—		4		7,863		7,867
Income tax expense	—		—		10,884		10,884
Depreciation, depletion, and amortization	35,198		3,249		1,059		39,506


Gains on derivatives	(143,221)		—		—		(143,221)
Net cash paid for scheduled derivative settlements	(14,739)		—		—		(14,739)
Other operating expenses (income)	1,077		(769)		315		623

Stock compensation expense	354		74		3,973		4,401


Adjusted EBITDA	$	102,763	$	7,726	$	(13,508)	$	96,981

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)


	Nine Months Ended September 30, 2022
	Development & Production		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	258,689	$	8,191	$	(88,676)	$	178,204
Add (Subtract):
Interest expense	—		4		23,267		23,271
Income tax expense	—		—		9,678		9,678
Depreciation, depletion, and amortization	104,628		9,445		3,265		117,338


Losses on derivatives	40,902		—		—		40,902
Net cash paid for scheduled derivative settlements	(84,519)		—		—		(84,519)
Other operating expenses (income)	4,601		(805)		949		4,745

Stock compensation expense	1,053		192		11,378		12,623
Non-recurring costs	—		198		—		198

Adjusted EBITDA	$	325,354	$	17,225	$	(40,139)	$	302,440

Note 11—Leases

In the first quarter of 2022, we adopted ASC 842 using the modified retrospective approach that requires us to determine our lease balances as of the date of adoption. Prior periods continue to be reported under accounting standards in effect for those periods.

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

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

The components of lease expense are as follows:


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	(in thousands)
Lease Cost
Operating lease cost	$	503	$	1,489

Total net lease cost	$	503	$	1,489

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

The following table presents supplemental interim consolidated balance sheet information related to leases as of September 30, 2022.


	As of September 30, 2022		Balance Sheet Classification
	(in thousands)
Leases
Assets

Operating lease assets	$	6,741	Other noncurrent assets

Total assets	$	6,741
Liabilities
Operating lease liability	$	1,749	Accounts payable and accrued expenses
Operating lease noncurrent liability	5,586		Other noncurrent liabilities

Total liabilities	$	7,335


	As of September 30, 2022
Long-Term and Discount Rate
Weighted-average remaining lease term:

Operating Lease	4.5 years
Weighted-average discount rate:

Operating Lease	5	%

The following table presents a schedule of future minimum lease payments required under all operating lease agreements as of September 30, 2022.


	As of September 30, 2022
	Operating Leases
	(in thousands)
2022	$	543
2023	1,963
2024	1,650
2025	1,542
2026	1,549
Thereafter	935
Total lease payments	8,182
Less imputed interest	(847)
Total lease obligations	7,335
Less current obligations	(1,749)
Long-term lease obligations	$	5,586

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BERRY CORPORATION (bry)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Supplemental unaudited interim consolidated cash flow information related to leases is as follows:


	Nine Months Ended September 30, 2022
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities

Operating cash flows from operating leases	$	1,590


ROU assets obtained in exchange for operating lease liabilities	$	7,956

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with our interim unaudited consolidated financial statements and related notes presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and related notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2021 (the “Annual Report”) filed with the Securities and Exchange Commission (“SEC”). When we use the terms “we,” “us,” “our,” “Berry,” the “Company” or similar words in this report, we are referring to, as the context may require, (i) for periods prior to October 1, 2021, Berry Corporation (bry), a Delaware corporation (formerly known as Berry Petroleum Corporation,“Berry Corp.”), together with its subsidiary Berry Petroleum, LLC, a Delaware limited liability company (“Berry LLC”); and (ii) for periods on or after October 1, 2021, Berry Corp. together with its subsidiaries, Berry LLC, CJ Berry Well Services Management, LLC, a Delaware limited liability company (“C&J Management”), and C&J Well Services, LLC, a Delaware limited liability company (“C&J”).

Our Company

The assets in our D&P business, in the aggregate, are characterized by high oil content (our California assets are 100% oil) and are predominantly located in rural areas with low population. In California, we focus on conventional, shallow oil reservoirs, the drilling and completion of which are relatively low-cost in contrast to unconventional resource plays. The California oil market has primarily Brent-influenced pricing which has typically realized premium pricing to WTI. All of our California assets are located in the oil-rich reservoirs in the San Joaquin basin, which has more than 150 years of production history and substantial oil remaining in place. As a result of the substantial data produced over the basin’s long history, its reservoir characteristics are well understood, which enables predictable, repeatable, low geological risk and low-cost development opportunities. We also have upstream assets in the low-operating cost, oil-rich reservoirs in the Uinta basin of Utah. In January 2022, we divested our natural gas properties in the Piceance basin of Colorado.

On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which operates as CJWS and now constitutes our well servicing and abandonment business segment. CJWS provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics. CJWS’ services include rig-based and coiled tubing-based well maintenance and workover services, recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, CJWS performs plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic growth opportunity for Berry. CJWS is a synergistic fit with the services required by our oil and gas operations and supports our commitment to be a responsible operator and reduce our emissions, including through the proactive plugging and abandonment of wells. Additionally, CJWS is critical to advancing our strategy to work with the State of California to reduce fugitive emissions - including methane and carbon dioxide - from idle wells. There are approximately 35,000 idle wells estimated to be in California according to third-party sources. We believe that CJWS is uniquely positioned to capture both state and federal funds to help remediate orphaned idle wells that are a burden of the State, in addition to helping third-party customers safely plug and abandon their idle wells.

Since our Initial Public Offering (IPO) in July 2018, we have demonstrated our commitment to maximizing shareholder value and returning a substantial amount of capital to shareholders through dividends and share purchases. In 2022, we reinforced this commitment by initiating a shareholder return model, which is further discussed below, designed to take advantage of our low decline rates and strong visibility into our cost structure to maximize total shareholder value. Under this well-defined shareholder return model, we have declared variable dividends of $1.10 per share in aggregate based on our Discretionary Free Cash Flow (defined and discussed below) generated in the first three quarters of 2022. We have also declared fixed dividends of $0.24 during 2022. Since our

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2018 IPO, we will have returned $282 million to our shareholders, which represents 256% of our IPO proceeds, consisting of $188 million paid in fixed and variable dividends and $94 million to repurchase 9.5 million shares representing 12% of our outstanding shares as of September 30, 2022.

As referenced above, our shareholder return model went into effect January 1, 2022. Like our business model, this shareholder return model is simple and further demonstrates our commitment to maximize total shareholder value. The model is based on our Discretionary Free Cash Flow, which is defined as cash flow from operations less regular fixed dividends and the capital needed to hold oil and gas production flat, and provides for the allocation of Discretionary Free Cash Flow on a quarterly basis as follows: (a) 60% predominantly in the form of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; (b) 40% in the form of discretionary capital, to be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. Discretionary Free Cash Flow is a non-GAAP financial measure used by management, as well as by external users of our financial statements. Please see “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for a reconciliation of Discretionary Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP.

We believe that the successful execution of our strategy across our low-declining, oil-weighted production base coupled with extensive inventory of identified drilling locations with attractive full-cycle economics will support our objectives to generate Discretionary Free Cash Flow to fund our operations and optimize capital efficiency, while maintaining a low leverage profile and focusing on attractive organic and strategic growth through commodity price cycles.

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

How We Plan and Evaluate Operations

We use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA; (b) Discretionary Free Cash Flow for shareholder returns; (c) operating expenses; (d) environmental, health & safety (“EH&S”) results; (e) general and administrative expenses; (f) production from our D&P business; 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 D&P business and CJWS. We also use Adjusted EBITDA in planning our capital allocation to sustain production levels and determining our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility (defined below in Liquidity and Capital Resources). Adjusted EBITDA is a non-GAAP financial measure that we define as earnings before interest expense; income taxes; depreciation, depletion, and amortization (“DD&A”); derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items. See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for reconciliation of Adjusted EBITDA to net (loss) income and to net cash provided by operating activities, our most directly comparable financial

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measures calculated and presented in accordance with GAAP. This supplemental non-GAAP financial measure is used by management, as well as by external users of our financial statements.

Shareholder Returns

As discussed in “Management’s Discussion and Analysis—Our Company,” commencing in 2022, we implemented a shareholder return model based on our Discretionary Free Cash Flow, which is a non-GAAP measure that we define as cash flow from operations less regular fixed dividends and the capital needed to hold production flat year-over-year (see “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for reconciliation of Discretionary Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP). Under the shareholder return model, we intend to allocate a significant portion of the Discretionary Free Cash Flow generated each quarter to pay variable quarterly cash dividends, with the remaining Discretionary Free Cash Flow expected to be allocated to fund opportunistic debt repurchases, opportunistic growth (including from our extensive inventory of drilling opportunities), advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention.

Our focus on shareholder returns is also demonstrated through our performance-based restricted stock awards, which include performance metrics based on the Company's average cash returned on invested capital and total stockholder return on both a relative and absolute basis. Our 2022 short-term incentive plan also includes Discretionary Free Cash Flow performance goals.

Operating Expenses

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

Environmental, Health & Safety (EH&S)

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

As part of our commitment to creating long-term stockholder value, we strive to conduct our operations in an ethical, safe and responsible manner, to protect the environment and to take care of our people and the communities in which we live and operate. We also seek proactive and transparent engagement with regulatory agencies, the communities in which we operate and our other stakeholders in order to realize the full potential of our resources in a timely fashion that safeguards people and the environment and complies with existing laws and regulations. We monitor our EH&S performance through various measures, and we hold our employees and contractors to high

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standards. Meeting corporate EH&S metrics, including with respect to EH&S incidents and spill prevention, is a part of our short-term incentive program for all employees.

General and Administrative Expenses

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

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.

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.

Business Environment, Market Conditions and Outlook

Our operating and financial results, and those of the oil and gas industry as a whole, are heavily influenced by commodity prices. Oil and gas prices, including the differentials between the relevant benchmarks and the prices we receive for our oil and natural gas production in our D&P business, have fluctuated, and may continue to fluctuate, significantly as a result of numerous market-related variables, including geopolitical and global economic conditions and third-party transportation and market takeaway infrastructure capacity. While oil prices have significantly improved in 2022 relative to the lows experienced in 2020 and recoveries through 2021, they are still subject to volatility. We utilize derivatives to hedge a portion of our forecasted oil and gas production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices; our 2021 RBL Facility (defined below in Liquidity and Capital Resources) also has hedging requirements.

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

The COVID-19 pandemic resulted in a severe decrease in demand for oil, which created significant volatility and uncertainty in the oil and gas industry during 2020 and 2021. When combined with an excess supply of oil and related products, oil prices declined significantly in the first half of 2020. Although there has been some volatility, overall oil prices have steadily improved since the lows experienced in 2020, in line with increasing demand despite the ongoing pandemic and uncertainties surrounding the COVID-19 variants. Oil and natural gas prices increased significantly during 2022, reaching a high of almost $128 per bbl during 2022, primarily due to global supply and demand imbalances. Brent prices were 13% lower and 33% higher for the three months ended September 30, 2022 as compared to the three months ended June 30, 2022 and September 30, 2021, respectively. Currently, global oil inventories are low relative to historical levels and supply from OPEC+ and other oil producing nations are not expected to be sufficient to meet forecasted oil demand growth for the next few years. It is believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected levels due to their lack of capital investments in developing incremental oil supplies over the past few years. In October 2022, OPEC+ determined to reduce production beginning in November 2022 through December 2023 by 2 million bbls per day,

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due to the uncertainty surrounding the global economic and oil market outlooks. Furthermore, sanctions and import bans on Russian oil have been implemented by various countries in response to the war in Ukraine, further impacting global oil supply. Still, oil and natural gas prices have recently declined from the highs experienced in second quarter of 2022 and could decrease or increase with any changes in demand due to, among other things, uncertainty and volatility from global supply chain disruptions attributable to the pandemic, the ongoing conflict in Ukraine, international sanctions, speculation as to future actions by OPEC+, developing COVID-19 variants and the potential for a widespread COVID-19 outbreak, higher gas prices, increasing inflation and government efforts to reduce inflation, and possible changes in the overall health of the global economy, including 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.

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 in Part I, Item 1A. “Risk Factors” in our Annual Report. We utilize derivatives to hedge a portion of our forecasted oil and gas production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices.

Average Brent oil prices, as noted below, decreased by $14.28, or 13% for the three months ended September 30, 2022 compared to the three months ended June 30, 2022 and increased by $24.47, or 33% compared to the three months ended September 30, 2021. Though the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics, including third-party transportation and market takeaway infrastructure capacity.

For our California steam operations, the price we pay for fuel gas purchases is generally based on the Kern, Delivered Index for the purchases made in California and based on the Northwest, Rocky Mountains Index for the purchases made in the Rockies. The high price from these indices was $15.96 per mmbtu and the low was $5.38 per mmbtu during the third quarter of 2022, while we paid an average of $8.16 per mmbtu in this period. The price we paid on average increased by $0.86 per mmbtu, or 12% for the three months ended September 30, 2022 compared to the three months ended June 30, 2022.

The following table presents the average Brent, WTI, Kern, Delivered, Northwest, Rocky Mountains, and Henry Hub prices for the three months ended September 30, 2022, June 30, 2022 and September 30, 2021 and for the nine months ended September 30, 2022 and September 30, 2021:



	Three Months Ended						Nine Months Ended
	September 30, 2022		June 30, 2022		September 30, 2021		September 30, 2022		September 30, 2021
Oil (bbl) – Brent	$	97.70	$	111.98	$	73.23	$	102.48	$	67.97
Oil (bbl) – WTI	$	91.96	$	108.71	$	70.63	$	98.39	$	64.87
Natural gas (mmbtu) – Kern, Delivered	$	8.74	$	7.36	$	5.75	$	6.99	$	5.65
Natural gas (mmbtu) – Northwest, Rocky Mountains	$	7.79	$	6.69	$	3.97	$	6.75	$	3.23
Natural gas (mmbtu) – Henry Hub	$	8.03	$	7.50	$	4.35	$	6.74	$	3.61

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

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should continue to allow us to realize positive cash margins in California over the cycle.

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

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

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.

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 contracts with terms ending in December 2023 through December 2026. The most significant input and cost of the cogeneration facilities is natural gas. We generally receive significantly more revenue from these cogeneration facilities in the summer months, most notably in June through September, due to negotiated capacity payments we receive.

Regulatory Matters

Like other companies in the oil and gas industry, both our D&P business and CJWS are subject to complex and stringent federal, state, and local laws and regulations, and California, where most of our operations and assets are located, is one of the most heavily regulated states in the United States with respect to oil and gas operations. A combination of federal, state and local laws and regulations govern most aspects of our activities in California. Collectively, the effect of the existing laws and regulations is to 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 regulate the amount of oil and natural gas that we can produce from our wells, potentially reducing below levels that would otherwise be possible. Additionally, the regulatory burden on the industry in the past has and in the future could result in increased costs and consequently may have an adverse effect upon operations, capital expenditures, earnings and our competitive position. Violations and liabilities with respect to these laws and regulations could also result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and future prospects. Our operations in California are particularly exposed to increased regulatory risks given the stringent environmental regulations imposed on the oil and gas industry, and current political and social trends in California continue to increase limitations on and impose additional permitting, mitigation, and emission control obligations, amongst others, upon the oil and gas industry. We cannot predict what new environmental laws or regulations California may impose upon our operations in the future; however, any such future laws or regulations

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could materially and adversely impact our business and results of operations. For additional information about the potential impact that government regulations, including those regarding environmental matters, may have upon our business, operations, capital expenditures, earnings and competitive position, please see Part I, Item 1 “Regulatory Matters,” as well as Part I, Item 1A. “Risk Factors” in our Annual Report.

Our oil and gas operations in California are subject to compliance with the California Environmental Quality Act (“CEQA”), and we cannot receive certain permits and other approvals required for our operations until we have demonstrated compliance with CEQA. There have been a number of developments at both the California state and local levels that have resulted in delays in the issuance of new drilling permits for oil and gas activities in Kern County where all of our California assets are located, as well as a more time- and cost- intensive permitting process. Most notably, in Kern County, we historically have satisfied CEQA by complying with the local oil and gas ordinance, which was supported by an Environmental Impact Report (an “EIR”) covering oil and gas operations in Kern County (“Kern County EIR”). In 2020, a lawsuit was filed challenging the Kern County EIR, and subsequently the California Fifth District Court of Appeals issued a ruling invalidating a portion of the Kern County EIR until Kern County made certain revisions to the Kern County EIR and recertified it (“Kern County Ruling”). To address the Kern County Ruling, Kern County prepared a supplemental EIR which was approved by the Kern County Board of Supervisors in March 2021. Following further challenges by plaintiffs, a Kern County Superior Court judge suspended use of the Kern County EIR as supplemented, stopping the issuance of new oil and gas permits by Kern County in October 2021 (the “Kern County Permit Suspension”), pending a determination by the Kern County Superior Court that the Kern County EIR complied with the CEQA requirements. In June 2022, the Kern County Superior Court ruled in favor of Kern County in part but also found that the supplemental Kern County EIR still failed to meet the minimum requirements of CEQA. In August 2022, the Kern County Board of Supervisors approved changes which addressed four discrete issues identified by the court in its June 2022 ruling. Following a hearing in September 2022, the Kern County Superior Court subsequently issued a ruling in October 2022 determining that the Kern County supplemental EIR was not decertified, but ordered Kern County to address the four discrete issues previously identified before the Kern County Permit Suspension could be lifted. These four discrete issues included requirements for the removal of offsite legacy equipment to mitigate agricultural land use impacts, revising emissions reduction requirements to address particulate matter, the establishment of a drinking water grant fund for disadvantaged communities in Kern County, and updating the local oil and gas ordinance to reflect these requirements. Kern County filed notice with the court of the changes on October 12, 2022. However, the plaintiffs have objected to the adequacy of Kern County’s changes and a final decision from the Kern County Superior Court remains pending. Although we are cautiously optimistic that this matter will be favorably resolved in the near term, at this time, we cannot predict the timing of the Kern County Superior Court’s ruling nor the outcome, including the extent to which the expected or other new additional requirements incorporated into the supplemental Kern County EIR may impact our business, financial condition, results of operation and future prospects. Importantly, neither the Kern County Ruling nor the Kern County Permit Suspension invalidated existing permits and, in part due to our contingency planning efforts, our operations have not been materially impacted to date.

Until Kern County is able to resume the ability to issue permits, our ability to obtain new permits and approvals to enable our future plans in Kern County requires demonstrating compliance with CEQA to CalGEM. We were able to secure some new drill permits from CalGEM in specific operational areas where the CEQA environmental analyses had already been completed by a predecessor entity, which CalGEM recognized as satisfying the CEQA compliance obligation. Demonstrating CEQA compliance without being able to reference the Kern County EIR (which we cannot currently do due to the Kern County Permit Suspension) or another CEQA-compliant environmental analysis is a more technical, time and cost intensive process and may, among other things, require that we conduct an extensive environmental impact review. As a result of the Kern County Permit Suspension, we together with other Kern County operators have experienced significant delays in the issuance of permits for new wells by CalGEM, in part due to the more intensive permitting process and CEQA compliance requirements for new wells, which we expect will continue to be the case until the Kern County Permit Suspension is resolved. We have submitted applications for additional permits that we believe, if received on a timely basis together with the permits already received, would enable us to execute our currently anticipated 2023 drilling program. However, there is no assurance that such additional permits will be approved in a timely manner or at all, even if the Kern County Permit Suspension is lifted. Fortunately, we have not experienced delays in the issuance of permits for the workover or recompletion of existing wells or other activities re-using existing well bores, for which the environmental review is

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expedited because the well already exists and the environmental impact analysis is simpler to conduct.

We timely submitted permit applications for the new wells contemplated by our 2022 capital development. However, due to the delays in permit issuance discussed above and insufficient permit inventory, beginning in the second quarter the execution of our remaining 2022 capital development program ultimately required an increase in workovers, recompletions and other activities re-using existing well bores and deployment of techniques to increase production from existing producing wells (referred to as our “base production”), and decrease in the number of new wells drilled in California contemplated by our initial program. Our plans for the remainder of the year will depend on whether and when we receive permits to drill new wells, as well as other key approvals (such as UIC permits to support water disposal) required to support planned activities. If we are unable to timely obtain those permits or approvals, our planned 2022 production could be adversely impacted and we may need to further modify our 2022 capital development program and alter our planned capital expenditures or deploy that capital to other activities. However, at this time we do not expect our planned 2022 production or results of operations to be materially impacted even if we are unable to timely obtain those permits and approvals because we currently believe we can continue to offset production from planned new wells with increased production from workover and other activities re-using existing well bores, as well as from our base production through field optimization initiatives. At this time we expect that approximately 94% of our planned 2022 production will come from our base production, with the remainder from workovers and other activities related to existing well bores, as well as from new wells drilled during the year.

Separately, on September 16, 2022, the Governor of California signed into law Senate Bill No. 1137 which establishes 3,200 feet as the minimum distance between new oil and gas production wells and certain sensitive receptors such as homes, schools or parks effective January 1, 2023. Additional provisions, among others, imposed EH&S controls applicable to wells located within this distance of sensitive receptors 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. These additional provisions are effective January 1, 2025. We are currently evaluating the impact of Senate Bill No. 1137 on our assets (specifically including reserves) and development plans while actively pursuing mitigation efforts with respect to the potential impacts on current and planned wells.

Additionally, President Biden signed the Inflation Reduction Act (“IRA”) into law on August 16, 2022 which, among other provisions, imposes a fee on the emissions of methane from certain sources in the oil and natural gas sector. Beginning in 2024, the IRA’s methane emissions charge imposes a fee on excess methane emissions from certain oil and gas facilities, starting at $900 per metric ton of leaked methane in 2024 and rising to $1,200 in 2025, and $1,500 in 2026 and thereafter. The imposition of this fee and other provisions of the IRA could increase our operating costs and accelerate the transition away from oil and gas, which could adversely affect our business and results of operations.

Inflation

The U.S. inflation rate has been steadily increasing since 2021 and throughout 2022. These inflationary pressures have resulted in and may result in additional increases to the costs of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could adversely affect our business and results of operations.

Seasonality

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

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Natural gas prices fluctuate based on seasonal and other market-related impacts. For example, natural gas prices increased significantly during the first three quarters of 2022, reflecting a premium driven by European instability which brought new demand for domestic production as a way to replace natural gas previously produced by Russia, as well as lower storage levels and damage to the Nord Stream pipeline connecting Russia to the rest of Europe for gas supplies. We purchase significantly more gas than we sell to generate steam and electricity in our cogeneration facilities for our production activities in our D&P business. As a result, our key exposure to gas prices is in our costs. We mitigate a substantial portion of this exposure by selling excess electricity from our cogeneration operations to third parties. The pricing of these electricity sales is closely tied to the purchase price of natural gas. These sales are generally higher in the summer months as they include seasonal capacity amounts. We also hedge a significant portion of the gas we expect to consume and in 2021 we entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our operations in California to help limit our exposure to fuel gas purchase price fluctuations.

Capital Expenditures

For the three and nine months ended September 30, 2022, our consolidated capital expenditures were approximately $41 million and $103 million, respectively, on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement spending. Approximately 47% and 42% of capital expenditures for the nine months ended September 30, 2022 was directed to California oil and Utah operations, respectively.

Our budget for 2022 capital expenditures for D&P operations and corporate activities was approximately $125 to $135 million, excluding $8 million for CJWS, the planned use of which was expected to keep our annual production relatively flat to 2021 after taking into account the impact of acquisitions and divestitures completed in late 2021 and early 2022. Based on activity to date and expected for the remainder of 2022, we currently anticipate our full year capital expenditures will be slightly more than our initial budget and will be between $140 and $145 million. We have adjusted our planned California capital program in late 2022 based on the success of recent development activity. To keep up the momentum into 2023, we are accelerating our development program during the fourth quarter of 2022. Additionally, due to the results achieved from mid-year workover and recompletion activity in Utah, we allocated incremental funding to perform additional workovers in Utah. The increase in full-year capital expenditures is also partially due to cost inflation in excess of our initial expectations, which we began to experience mid-year.

The amount and timing of capital expenditures are within our control and subject to our discretion, and due to the speed with which we are able to drill and complete our wells in California, capital may be adjusted quickly during the year depending on numerous factors, including permit inventory to support planned activities, commodity prices, storage and third-party transportation constraints, supply/demand considerations and attractive rates of return. We believe it is important to retain the flexibility to defer planned capital expenditures and may do so based on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the receipt and timing of required regulatory permits and approvals, the availability of necessary equipment, infrastructure and capital, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners, as well as general market conditions. Any postponement or elimination of our development program could result in a reduction of proved reserves volumes and materially affect our business, financial condition and results of operations.

Additionally and not included in the capital expenditures noted above, for the full year 2022, we plan to spend approximately $21 million to $24 million on plugging and abandonment activities, including 280 to 320 wells and satisfying our annual obligations under the California Idle Well Management Program. We spent approximately $5 million and $16 million for plugging and abandonment activities in the three months and nine months ended September 30, 2022, respectively. Our well servicing and abandonment segment expects to plug and abandon approximately 2,500 to 3,000 wells for their third-party customers in 2022, helping to safely address the environmental hazards and other risks from California’s number of idle wells. In the nine months ended September 30, 2022, our wells servicing and abandonment segment plugged and abandoned 2,100 wells for third-party customers.

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Summary by Area

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


	California (San Joaquin and Ventura basins)(3)
	Three Months Ended
	September 30, 2022			June 30, 2022			September 30, 2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales	$	175,245		$	204,706		$	140,160
Operating income(1)	$	57,864		$	63,608		$	26,652
Depreciation, depletion, and amortization (DD&A)	$	33,979		$	34,074		$	35,252

Average daily production (mboe/d)	20.8			21.0			21.8
Production (oil % of total)	100		%	100		%	100		%
Realized sales prices:
Oil (per bbl)	$	91.67		$	107.31		$	69.92
NGLs (per bbl)	$	—		$	—		$	—
Gas (per mcf)	$	—		$	—		$	—
Capital expenditures(2)	$	15,220		$	18,672		$	29,806


	Utah (Uinta basin)									Colorado (Piceance basin)(4)
	Three Months Ended									Three Months Ended
	September 30, 2022			June 30, 2022			September 30, 2021			September 30, 2022			June 30, 2022			September 30, 2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales	$	28,323		$	35,338		$	18,118		$	—		$	—		$	2,779
Operating income(1)	$	11,123		$	20,579		$	7,246		$	—		$	—		$	2,360
Depreciation, depletion, and amortization (DD&A)	$	2,278		$	964		$	611		$	—		$	—		$	38

Average daily production (mboe/d)	5.0			5.2			4.4			—			—			1.2
Production (oil % of total)	57		%	57		%	50		%	—		%	—		%	1		%
Realized sales prices:
Oil (per bbl)	$	73.83		$	94.47		$	60.09		$	—		$	—		$	66.97
NGLs (per bbl)	$	40.72		$	56.47		$	40.88		$	—		$	—		$	—
Gas (per mcf)	$	7.95		$	7.35		$	4.31		$	—		$	—		$	4.24
Capital expenditures(2)	$	21,196		$	11,563		$	5,728		$	—		$	—		$	—

__________

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

(2) Excludes corporate capital expenditures.

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

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

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Production and Prices

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



	Three Months Ended
	September 30, 2022		June 30, 2022		September 30, 2021
Average daily production:(1)
Oil (mbbl/d)	23.7		24.0		24.1
Natural Gas (mmcf/d)	10.4		11.0		17.6
NGL (mbbl/d)	0.4		0.4		0.4
Total (mboe/d)(2)	25.8		26.2		27.4
Total Production:
Oil (mbbl)	2,171		2,182		2,211
Natural gas (mmcf)	953		999		1,615
NGLs (mbbl)	39		37		39
Total (mboe)(2)	2,369		2,386		2,519
Weighted-average realized sales prices:
Oil without hedges ($/bbl)	$	89.54	$	105.70	$	69.01
Effects of scheduled derivative settlements ($/bbl)	$	(13.13)	$	(21.92)	$	(14.66)
Oil with hedges ($/bbl)	$	76.41	$	83.78	$	54.35
Natural gas ($/mcf)	$	7.95	$	7.35	$	4.29
NGL ($/bbl)	$	40.72	$	56.47	$	40.88
Average Benchmark prices:
Oil (bbl) – Brent	$	97.70	$	111.98	$	73.23
Oil (bbl) – WTI	$	91.96	$	108.71	$	70.63
Natural gas (mmbtu) – Kern, Delivered(3)	$	8.74	$	7.36	$	5.75
Natural gas (mmbtu) – Northwest, Rocky Mountains	$	7.79	$	6.69	$	3.97
Natural gas (mmbtu) – Henry Hub(4)	$	8.03	$	7.50	$	4.35

__________

(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, 2022, the average prices of Brent oil and Henry Hub natural gas were $97.70 per bbl and $8.03 per mmbtu.

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

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

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


	Three Months Ended
	September 30, 2022	June 30, 2022	September 30, 2021
Average daily production (mboe/d):(1)
California(2)	20.8	21.0	21.8
Utah	5.0	5.2	4.4
Colorado(3)	—	—	1.2

Total average daily production	25.8	26.2	27.4

__________

(1) Production represents volumes sold during the period.

(2) In October 2021, we divested our Placerita (California) properties, exclusively oil production, which had average production of 0.8 mbbl/d in the third quarter 2021.

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

On a sequential basis, our average daily production decreased by 0.4 mboe/d for the three months ended September 30, 2022, compared to the second quarter 2022. Our California production was 20.8 mboe/d for the third quarter of 2022, a decrease of 0.2 mboe/d from the second quarter 2022, which was largely due to fewer new wells added in the third quarter than in the second quarter, partially offset by workovers and other activities re-using existing well bores. Our Utah production decreased largely due to fewer wells completed and placed on production in the third quarter than in the second quarter.

Average daily production for the three months ended September 30, 2021 included properties that have since been divested, specifically, Placerita properties in California and Piceance properties in Colorado, which were our only assets in Colorado. The combined production from these properties was 2.0 mboe/d in the third quarter 2021 (1.2 mboe/d in Colorado and 0.8 mboe/d in California) and there was no production from these properties in the second and third quarters of 2022.

Average daily production in California for the three months ended September 30, 2022 decreased 0.2 mboe/d compared to the same period in 2021, when excluding the production from the Placerita properties for 2021. The decrease was due to decreased development activity in California during 2022. The year-over-year increase in the Utah production was driven by the addition of the Antelope Creek properties we acquired in February 2022.

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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, 2022		September 30, 2021
Average daily production:(1)
Oil (mbbl/d)	24.0		24.0
Natural Gas (mmcf/d)	11.0		17.3
NGL (mbbl/d)	0.4		0.4
Total (mboe/d)(2)	26.2		27.3
Total Production:
Oil (mbbl)	6,551		6,545
Natural gas (mmcf)	2,990		4,728
NGLs (mbbl)	111		105
Total (mboe)(2)	7,160		7,438
Weighted-average realized sales prices:
Oil without hedges ($/bbl)	$	95.83	$	63.59
Effects of scheduled derivative settlements ($/bbl)	$	(16.81)	$	(15.03)
Oil with hedges ($/bbl)	$	79.02	$	48.56
Natural gas ($/mcf)	$	6.99	$	5.16
NGL ($/bbl)	$	47.98	$	32.97
Average Benchmark prices:
Oil (bbl) – Brent	$	102.48	$	67.97
Oil (bbl) – WTI	$	98.39	$	64.87
Gas (mmbtu) – Kern, Delivered(3)	$	6.99	$	5.65
Natural gas (mmbtu) – Northwest, Rocky Mountains	$	6.75	$	3.23
Natural gas (mmbtu) – Henry Hub(4)	$	6.74	$	3.61

__________

(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, 2022, the average prices of Brent oil and Henry Hub natural gas were $102.48 per bbl and $6.74 per mmbtu respectively.

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

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

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


	Nine Months Ended
	September 30, 2022	September 30, 2021
Average daily production (mboe/d):(1)
California(2)	21.3	21.8
Utah	4.8	4.3
Colorado(3)	0.1	1.2

Total average daily production	26.2	27.3

__________

(1) Production represents volumes sold during the period.

(2) In October 2021, we divested our Placerita (California) properties, exclusively oil production, which had average production of 0.8 mbbl/d in the third quarter 2021.

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

Average daily production for the nine months ended September 30, 2022 included 0.9 mboe/d of production from the Antelope Creek (Utah) asset acquired in the first quarter of 2022 and 0.1 mboe/d of production from the Piceance (Colorado) asset, which was divested in the first quarter of 2022. The nine months ended September 30, 2021 included 1.2 mboe/d of production from the Colorado assets, as well as 0.8 mboe/d of production from the Placerita asset in California, which was divested in the fourth quarter of 2021.

On a comparable basis, when excluding the volumes from these acquisitions and divestitures, California produced 21.3 mboe/d for the nine months ended September 30, 2022, a 0.3 mboe/d increase when compared to the nine months ended September 30, 2021. When excluding the volumes from these transactions, our total production was essentially flat for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. We drilled 51 wells in California in the first nine months of 2022, of which 39 were producing wells, eight were delineation wells and four were observation wells. We also drilled 12 wells in Uinta, all of which were producing wells.

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Results of Operations

Three Months Ended September 30, 2022 compared to Three Months Ended June 30, 2022.


	Three Months Ended
	September 30, 2022		June 30, 2022		$ Change		% Change
	(in thousands)
Revenues and other:
Oil, natural gas and NGL sales	$	203,585	$	240,071	$	(36,486)	(15)	%
Service revenue	48,594		46,178		2,416		5	%
Electricity sales	9,711		7,419		2,292		31	%
Gain (losses) on oil and gas sales derivatives	114,279		(40,658)		154,937		n/a
Marketing and other revenues	277		120		157		131	%

Total revenues and other	$	376,446	$	253,130	$	123,316	49	%

Revenues and Other

Oil, natural gas and NGL sales decreased by $36 million, or 15%, to approximately $204 million for the three months ended September 30, 2022, compared to the three months ended June 30, 2022. The decrease was driven by $35 million lower unhedged oil prices, including the approximate $2 per bbl impact from discounts applied to approximately 25% of third quarter California volumes due to an unexpected third-party pipeline outage for unplanned repairs during most of the third quarter of 2022, as well as $1 million decrease due to lower oil volumes. The unplanned repairs on the pipeline are ongoing and the Company currently expects the outage to extend into the first quarter of 2023, which may require additional volumes to be sold at a discount until resolved.

Service revenue consisted entirely of revenue from the well servicing and abandonment business. Service revenue increased by $2 million or 5% to approximately $49 million in the third quarter 2022, due to increased activity, which is partially seasonal, and rate increases effective late second quarter to offset a portion of cost inflation.

Electricity sales represent sales to utilities and increased $2 million, or 31%, to approximately $10 million for the three months ended September 30, 2022 compared to the three months ended June 30, 2022. This increase was largely due to higher unit sales prices driven by higher natural gas prices.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement loss for the three months ended September 30, 2022 was $29 million and the loss for the three months ended June 30, 2022 was $48 million. The quarter-over-quarter decrease in settlement losses was driven by an approximately $14 per bbl decline in index prices. The mark-to-market non-cash gain was $143 million and $7 million for the three months ended September 30, 2022 and June 30, 2022, respectively, due to a narrower spread between future market prices and the fixed price at the end of the quarter compared to that of the respective previous quarter. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index create valuation gains (losses).

Marketing and other revenues, which included third-party marketing activities, were not material for the three months ended September 30, 2022 and June 30, 2022.

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	Three Months Ended				$ Change		% Change
	September 30, 2022		June 30, 2022
	(in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses	$	79,141	$	72,455	$	6,686	9	%
Costs of services	37,628		36,709		919		3	%
Electricity generation expenses	6,055		6,122		(67)		(1)	%
Transportation expenses	1,277		1,108		169		15	%

General and administrative expenses	23,388		23,183		205		1	%
Depreciation, depletion and amortization	39,506		38,055		1,451		4	%

Taxes, other than income taxes	7,335		11,214		(3,879)		(35)	%

(Gains) losses on natural gas purchase derivatives	(28,942)		10,661		(39,603)		n/a
Other operating expenses	623		353		270		76	%
Total expenses and other	166,011		199,860		(33,849)		(17)	%
Other (expenses) income:
Interest expense	(7,867)		(7,729)		(138)		2	%
Other, net	(24)		(42)		18		(43)	%

Total other (expenses) income	(7,891)		(7,771)		(120)		2	%
Income before income taxes	202,544		45,499		157,045		345	%
Income tax expense	10,884		2,145		8,739		407	%
Net income	$	191,660	$	43,354	$	148,306	342	%

Expenses per boe:(1)
Lease operating expenses	$	33.40	$	30.37	$	3.03	10	%
Electricity generation expenses	2.56		2.57		(0.01)		—	%
Electricity sales(1)	(4.10)		(3.11)		(0.99)		32	%
Transportation expenses	0.54		0.46		0.08		17	%
Transportation sales(1)	(0.12)		(0.05)		(0.07)		140	%


Derivatives settlements received for gas purchases(1)	(5.82)		(4.27)		(1.55)		36	%
Total operating expenses	$	26.46	$	25.97	$	0.49	2	%
Total unhedged operating expenses(2)	$	32.28	$	30.24	$	2.04	7	%

Total non-energy operating expenses(3)	$	17.59	$	16.10	$	1.49	9	%
Total energy operating expenses(4)	$	8.87	$	9.87	$	(1.00)	(10)	%

General and administrative expenses(5)	$	9.87	$	9.72	$	0.15	2	%
Depreciation, depletion and amortization	$	16.67	$	15.95	$	0.72	5	%
Taxes, other than income taxes	$	3.10	$	4.70	$	(1.60)	(34)	%

__________

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

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

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

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

(5) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.81 per boe and $1.77 per boe for the three months ended September 30, 2022 and June 30, 2022, respectively.

Expenses and Other

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

Operating expenses are defined above in “How We Plan and Evaluate Operations”, which include electricity, marketing and transportation revenues. On a hedged basis, operating expenses increased by $0.49 per boe, or 2%, to $26.46 for the third quarter of 2022 compared to the second quarter of 2022. During the third quarter, non-energy operating expenses increased $1.49 per boe due to higher seasonal power rates and other field operating costs. A portion of the increased costs in non-energy operating expenses were driven by inflation. Energy operating expense decreased $1.00 per boe in the third quarter compared to the second quarter of 2022 due to higher electricity sales. Higher gas purchase settlements mitigated the impact of higher purchase prices.

Unhedged lease operating expenses per boe increased by 10%, or $3.03, to $33.40 for the three months ended September 30, 2022, compared to $30.37 per boe for the three months ended June 30, 2022, generally for the same reasons noted above for non-energy expense. Unhedged average fuel purchase price per mmbtu increased 12% while consumption declined 3% in the third quarter compared to the second quarter, which when combined resulted in a $1.09 per boe higher unhedged higher fuel costs for our California steam operations.

Cost of services in 2022 consisted entirely of costs from the well servicing and abandonment business. Cost of services increased by $1 million, or 3%, to $38 million in the third quarter of 2022, mainly due to higher activity, which is partially driven by a seasonal impact.

Electricity generation expenses were relatively flat at $2.56 per boe for the three months ended September 30, 2022, compared to $2.57 per boe for the three months ended June 30, 2022.

Gains and losses on natural gas purchase derivatives resulted in a $29 million gain for the three months ended September 30, 2022 and a loss of $11 million in the three months ended June 30, 2022. Settlement gains for the three months ended September 30, 2022 and June 30, 2022 were $14 million, or $5.82 per boe, and $10 million, or $4.27 per boe, respectively, and increased due to higher index prices relative to the derivative fixed prices of settled positions in the third quarter of 2022 compared to the second quarter. The mark-to-market valuation gain was $15 million for the three months ended September 30, 2022 and a loss of $21 million for the three months ended June 30, 2022. 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.

General and administrative expenses were flat at $23 million for the three months ended September 30, 2022 and the three months ended June 30, 2022. For the three months ended September 30, 2022 and June 30, 2022, general and administrative expenses included non-cash stock compensation costs of approximately $4.3 million. We incurred no non-recurring costs for the three months ended September 30, 2022 and June 30, 2022. Less than 10% of our overhead is capitalized and thus excluded from general and administrative expenses.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, were $19 million for the three months ended September 30, 2022, and was flat compared to the three months ended June 30, 2022. See “—Non-GAAP Financial Measures” for a reconciliation of adjusted general and administrative expense to general and administrative expenses, the most directly comparable financial measures

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calculated and presented in accordance with GAAP.

DD&A increased 4% to $40 million for the three months ended September 30, 2022 compared to the three months ended June 30, 2022. The increase was driven by the mix of production in the D&P segment.

Taxes, Other Than Income Taxes



	Three Months Ended				$ Change		% Change
	September 30, 2022		June 30, 2022
	(per boe)
Severance taxes	$	1.45	$	1.54	$	(0.09)	(6)	%
Ad valorem and property taxes	1.48		1.49		(0.01)		(1)	%
Greenhouse gas allowances	0.17		1.67		(1.50)		(90)	%

Total taxes other than income taxes	$	3.10	$	4.70	$	(1.60)	(34)	%

Taxes, other than income taxes, decreased in the three months ended September 30, 2022 by $1.60 per boe, or 34%, to $3.10. The reduction in third quarter 2022 greenhouse gas (“GHG”) costs was a result of lower mark-to-market prices compared to the second quarter of 2022. Severance taxes were lower in the third quarter of 2022 due to lower revenue.

Other Operating Expenses

Other operating expenses were comparable for periods presented.

Interest Expense

Interest expense was relatively flat at $8 million for each of the three months ended September 30, 2022 and June 30, 2022.

Income Taxes

Our effective tax rate was comparable at approximately 5% for the three months ended September 30, 2022, and June 30, 2022.

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Three Months Ended September 30, 2022 compared to Three Months Ended September 30, 2021.



	Three Months Ended September 30,				$ Change		% Change
	2022		2021
	(in thousands)
Revenues and other:
Oil, natural gas and NGL sales	$	203,585	$	161,058	$	42,527	26	%
Service revenue	48,594		—		48,594		100	%
Electricity sales	9,711		12,371		(2,660)		(22)	%
Gains (losses) on oil and gas sales derivatives	114,279		(30,864)		145,143		n/a
Marketing and other revenues	277		849		(572)		(67)	%
Total revenues and other	$	376,446	$	143,414	$	233,032	162	%

Revenues and Other

Oil, natural gas and NGL sales increased by $43 million, or 26%, to approximately $204 million for the three months ended September 30, 2022 when compared to the three months ended September 30, 2021. This variance was principally the result of higher unhedged commodity prices.

Service revenue in the third quarter 2022 was $49 million and there was no corresponding revenue in the third quarter 2021 as we acquired this business on October 1, 2021.

Electricity sales represent sales to utilities, and decreased by approximately $3 million, or 22%, to approximately $10 million for the three months ended September 30, 2022 when compared to the three months ended September 30, 2021. The decrease was largely due to lower unit sales volumes driven by the sale of our Placerita asset, which included our largest electricity-generating cogeneration facility (“cogen”), in the fourth quarter 2021. For the three years prior to divestiture the Placerita cogen accounted for approximately 41% of our electrical sales.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement losses for the three months ended September 30, 2022 and the three months ended September 30, 2021 were $29 million and $32 million, respectively. The quarter-over-quarter decrease in settlement losses were driven by lower oil prices relative to our derivative fixed prices in the third quarter of 2022 than that of the same period in 2021. Notional volumes were 15 mbbl/d in the third quarter 2022 and 14 mbbls/d in the third quarter 2021. The mark-to-market non-cash gain was $143 million and $1 million for the three months ended September 30, 2022 and September 30, 2021, respectively, due to a narrower spread between future market prices and the fixed price at the end of the quarter compared to that of the respective previous quarter. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index create valuation gains (losses).

Marketing and other revenues were not material for the three months ended September 30, 2022 and September 30, 2021.

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	Three Months Ended September 30,				$ Change		% Change
	2022		2021
	(in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses	$	79,141	$	60,930	$	18,211	30	%
Costs of services	37,628		—		37,628		100	%
Electricity generation expenses	6,055		7,128		(1,073)		(15)	%
Transportation expenses	1,277		1,806		(529)		(29)	%
Marketing expenses	—		715		(715)		(100)	%
General and administrative expenses	23,388		17,614		5,774		33	%
Depreciation, depletion and amortization	39,506		35,902		3,604		10	%

Taxes, other than income taxes	7,335		13,420		(6,085)		(45)	%

Gains on natural gas purchase derivatives	(28,942)		(14,980)		(13,962)		93	%
Other operating expenses	623		3,986		(3,363)		(84)	%
Total expenses and other	166,011		126,521		39,490		31	%
Other (expenses) income:
Interest expense	(7,867)		(7,810)		(57)		1	%
Other, net	(24)		(5)		(19)		380	%

Total other (expenses) income	(7,891)		(7,815)		(76)		1	%
Income before income taxes	202,544		9,078		193,466		2,131	%
Income tax expense (benefit)	10,884		(758)		11,642		(1,536)	%
Net income	$	191,660	$	9,836	$	181,824	(1,849)	%



Expenses per boe:(1)
Lease operating expenses	$	33.40	$	24.20	$	9.20	38	%
Electricity generation expenses	2.56		2.83		(0.27)		(10)	%
Electricity sales(1)	(4.10)		(4.91)		0.81		(16)	%
Transportation expenses	0.54		0.72		(0.18)		(25)	%
Transportation sales(1)	(0.12)		(0.05)		(0.07)		140	%
Marketing expenses	—		0.28		(0.28)		(100)	%
Marketing revenues(1)	—		(0.29)		0.29		(100)	%
Derivatives settlements received for gas purchases(1)	(5.82)		(5.60)		(0.22)		4	%
Total operating expenses	$	26.46	$	17.18	$	9.28	54	%
Total unhedged operating expenses(2)	$	32.28	$	22.78	$	9.50	42	%

Total non-energy operating expenses(3)	$	17.59	$	13.59	$	4.00	29	%
Total energy operating expenses(4)	$	8.87	$	3.59	$	5.28	147	%

General and administrative expenses(5)	$	9.87	$	6.99	$	2.88	41	%
Depreciation, depletion and amortization	$	16.67	$	14.25	$	2.42	17	%
Taxes, other than income taxes	$	3.10	$	5.33	$	(2.23)	(42)	%

__________

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

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

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

(5) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.81 per boe and $1.66 per boe for the three months ended September 30, 2022 and September 30, 2021, respectively.

Expenses and Other

On a hedged basis, operating expenses, increased by 54%, or $9.28 per boe, to $26.46 per boe for the third quarter of 2022 compared to $17.18 per boe for the third quarter of 2021. This increase was due to higher energy operating expense of $5.28 per boe and non-energy operating expense of $4.00 per boe. Energy operating expense increased largely due to higher hedged natural gas purchase prices. Non-energy operating expense increased due to higher power rates and other field operating costs. A portion of the increased costs in non-energy operating expenses were driven by inflation.

Unhedged lease operating expenses were $33.40 per boe for the three months ended September 30, 2022, a 38% or $9.20 per boe increase compared to $24.20 for the three months ended September 30, 2021. Unhedged fuel costs for our California steam operations increased $4.97 per boe. Unhedged average fuel purchase price per mmbtu increased 41% in the third quarter of 2022 compared to the third quarter of 2021 and gas volumes purchased were down 11%. Non-fuel lease operating expense increased $4.23 per boe, generally for the same reasons noted above for non-energy operating expense.

Cost of services in the third quarter of 2022 were $38 million and there were no costs of services in the third quarter of 2021, as we acquired the well servicing and abandonment business on October 1, 2021.

Electricity generation expenses decreased approximately 10% to $2.56 per boe for the three months ended September 30, 2022 from $2.83 per boe for the same period in 2021 due to the Placerita properties sale, partially offset by higher natural gas costs. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements.

Gains and losses on natural gas purchase derivatives for the three months ended September 30, 2022 and September 30, 2021 resulted in a gain of $29 million and $15 million, respectively. Settlement gains for the three months ended September 30, 2022 and September 30, 2021 were $14 million in each period, or $5.82 per boe and $5.60 per boe, respectively. The mark-to-market non-cash gain was $15 million and $1 million for the three months ended September 30, 2022 and September 30, 2021, respectively, due to a larger spread between future market prices and the derivative fixed price at the end of the quarter compared to that of the respective previous quarter. Because we are the fixed price payer on these natural gas swaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses).

Transportation expenses decreased to $0.54 per boe for the three months ended September 30, 2022 compared to $0.72 per boe for the three months ended September 30, 2021, primarily due to the sale of our Piceance operations the first quarter of 2022.

Marketing expenses were not material for the three months ended September 30, 2022 and September 30, 2021.

General and administrative expenses increased $6 million, or 33%, to approximately $23 million for the three months ended September 30, 2022 compared to the three months ended September 30, 2021. For the three months ended September 30, 2022 and September 30, 2021, general and administrative expenses included non-cash stock

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compensation costs of approximately $4 million in each period. We incurred approximately $0.7 million related to the CJWS acquisition which have been categorized as non-recurring for the three months ended September 30, 2021. There were no non-recurring expenses in the same period of 2022. The third quarter of 2022 also included $3 million of general and administrative expenses from the well servicing and abandonment segment which had no corresponding amount in 2021 as we purchased CJWS in the fourth quarter of 2021.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, increased 46% to $19 million for the three months ended September 30, 2022 compared to $13 million for the three months ended September 30, 2021. The substantial majority of the increase was due to the acquisition of CJWS, as well as higher legal and other professional service expenses and employee costs.

DD&A for the third quarter of 2022 increased approximately $4 million to $40 million when compared to the third quarter of 2021 driven primarily by CJWS and slightly higher DD&A rates for the D&P segment, partially offset by lower production.

Taxes, Other Than Income Taxes



	Three Months Ended September 30,				$ Change		% Change
	2022		2021
	(per boe)
Severance taxes	$	1.45	$	0.80	$	0.65	81	%
Ad valorem and property taxes	1.48		1.73		(0.25)		(14)	%
Greenhouse gas allowances	0.17		2.80		(2.63)		(94)	%
Total taxes other than income taxes	$	3.10	$	5.33	$	(2.23)	(42)	%

Taxes, other than income taxes decreased 42% to $3.10 per boe for the three months ended September 30, 2022 compared to $5.33 per boe for the three months ended September 30, 2021. Severance taxes increased due to higher production and prices in Utah, while property taxes were lower due to the divestitures of Piceance and Placerita. GHG expense was significantly lower, largely due to lower emissions which resulted from the divestiture of Placerita and its cogeneration facility, as well as lower prices.

Other Operating Expenses (Income)

Other operating expenses decreased $3 million or 84% to less than $1 million for the three months ended September 30, 2022 when compared to the same quarter in 2021. The decrease is primarily due to $3 million of unamortized debt issuance costs related to the termination of the 2017 RBL facility incurred in three months ended September 30, 2021.

Interest Expense

Interest expense was comparable in the three months ended September 30, 2022 and September 30, 2021.

Income Taxes

Our effective tax rate was approximately 5% for the three months ended September 30, 2022 compared to (8)% for the three months ended September 30, 2021. The rates were impacted by changes in the valuation allowance recorded against deferred tax assets.

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Nine Months Ended September 30, 2022 compared to Nine Months Ended September 30, 2021.



	Nine Months Ended September 30,				$ Change		% Change
	2022		2021
	(in thousands)
Revenues and other:
Oil, natural gas and NGL sales	$	654,007	$	444,098	$	209,909	47	%
Service revenue	134,608		—		134,608		100	%
Electricity sales	22,549		29,328		(6,779)		(23)	%
Losses on oil and gas sales derivatives	(88,237)		(140,021)		51,784		(37)	%
Marketing and other revenues	731		3,459		(2,728)		(79)	%
Total revenues and other	$	723,658	$	336,864	$	386,794	115	%

Revenues and Other

Oil, natural gas and NGL sales increased by $210 million, or 47%, to approximately $654 million for the nine months ended September 30, 2022 when compared to the nine months ended September 30, 2021. The increase was driven by higher realized prices, partially offset by pricing discounts applied to approximately 25% of third quarter California volumes due to an unexpected third party pipeline outage for unplanned repairs during most of the third quarter of 2022.

Service revenue consisted entirely of revenue from the well servicing and abandonment business we acquired on October 1, 2021, thus no prior period revenue.

Electricity sales, which represent sales to utilities, decreased $7 million, or 23%, to $23 million for the nine months ended September 30, 2022 when compared to the nine months ended September 30, 2021. The decrease was primarily due to lower sales volume as a result of the sale of a cogeneration facility which was part of the Placerita divestiture in late 2021.

Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. We had settlement losses of $110 million and $96 million for the nine months ended September 30, 2022 and the nine months ended September 30, 2021, respectively. The period over period increase in settlement losses was driven by a wider spread between the settled derivative fixed prices and index oil prices in the nine months ended September 30, 2022 compared to the same period of 2021. Partially offsetting this effect, notional volumes decreased to 14 mbbl/d in the nine months ended September 30, 2022 from 17 mbbl/d in the nine months ended September 30, 2021. The mark-to-market non-cash gain of $22 million for the nine months ended September 30, 2022 was the result of lower futures prices relative to the derivative fixed prices. Conversely, the $44 million loss in the same period of 2021 was due to higher futures prices relative to the derivative fixed prices, as measured at the end of their respective periods. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index create valuation gains (losses).

Marketing and other revenues decreased approximately $3 million for the nine months ended September 30, 2022 when compared to the nine months ended September 30, 2021 due to the sale of our Piceance Colorado operations in the fourth quarter of 2021, which included third-party marketing activities. Piceance has historically accounted for nearly all of our marketing revenues.

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	Nine Months Ended September 30,				$ Change		% Change
	2022		2021
	(in thousands, except expenses per boe)
Expenses and other:
Lease operating expenses	$	214,720	$	168,756	$	45,964	27	%
Costs of services	107,809		—		107,809		100	%
Electricity generation expenses	16,640		19,488		(2,848)		(15)	%
Transportation expenses	3,543		5,139		(1,596)		(31)	%
Marketing expenses	299		2,986		(2,687)		(90)	%
General and administrative expenses	69,513		50,749		18,764		37	%
Depreciation, depletion and amortization	117,338		105,592		11,746		11	%

Taxes, other than income taxes	25,154		34,580		(9,426)		(27)	%

Gains on natural gas purchase derivatives	(47,335)		(54,349)		7,014		(13)	%
Other operating expenses	4,745		4,827		(82)		(2)	%
Total expenses and other	512,426		337,768		174,658		52	%
Other (expenses) income:
Interest expense	(23,271)		(24,513)		1,242		(5)	%
Other, net	(79)		(156)		77		(49)	%

Total other (expenses) income	(23,350)		(24,669)		1,319		(5)	%
Income (loss) before income taxes	187,882		(25,573)		213,455		(835)	%
Income tax expense (benefit)	9,678		(1,206)		10,884		(902)	%
Net income (loss)	$	178,204	$	(24,367)	$	202,571	(831)	%



Expenses per boe:(1)
Lease operating expenses	$	29.99	$	22.69	$	7.30	32	%
Electricity generation expenses	2.32		2.62		(0.30)		(11)	%
Electricity sales(1)	(3.15)		(3.94)		0.79		(20)	%
Transportation expenses	0.49		0.69		(0.20)		(29)	%
Transportation sales(1)	(0.06)		(0.05)		(0.01)		20	%
Marketing expenses	0.04		0.40		(0.36)		(90)	%
Marketing revenues(1)	(0.04)		(0.42)		0.38		(90)	%
Derivatives settlements received for gas purchases(1)	(3.58)		(5.68)		2.10		(37)	%
Total operating expenses	$	26.01	$	16.31	$	9.70	59	%
Total unhedged operating expenses(2)	$	29.59	$	21.99	$	7.60	35	%

Total non-energy operating expenses(3)	$	15.74	$	13.02	$	2.72	21	%
Total energy operating expenses(4)	$	10.27	$	3.29	$	6.98	212	%

General and administrative expenses(5)	$	9.71	$	6.82	$	2.89	42	%
Depreciation, depletion and amortization	$	16.39	$	14.20	$	2.19	15	%
Taxes, other than income taxes	$	3.51	$	4.65	$	(1.14)	(25)	%

__________

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

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

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

(5) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.71 per boe and $1.43 per boe for the nine months ended September 30, 2022 and September 30, 2021, respectively.

Expenses and Other

On a hedged basis, operating expenses increased 59%, or $9.70 per boe, to $26.01 for the nine months ended September 30, 2022 from $16.31 per boe for the nine months ended September 30, 2021. This increase was due to higher energy operating expense of $6.98 per boe and non-energy operating expense of $2.72 per boe. Energy operating expense increased primarily due to higher hedged purchased natural gas costs. Non-energy operating expense increased largely due to higher power rates and other lease operating expenses noted below, including inflation, in the nine months ended September 30, 2022 compared to same period of 2021.

Unhedged lease operating expenses were $29.99 per boe for the nine months ended September 30, 2022, a 32% or $7.30 per boe increase compared to $22.69 for the nine months ended September 30, 2021, driven by higher unhedged fuel costs for our California steam operations. Unhedged average fuel purchase price per mmbtu increased 36% in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. Non-fuel lease operating expense increased $3.12 per boe in the nine months ended September 30, 2022 when compared to the same period of 2021. Key increases included higher workover and field monitoring activity associated with our field optimization program, and higher well and surface facilities maintenance and power costs. A portion of these higher costs were driven by inflation.

Cost of services in 2022 consisted entirely of costs from the well servicing and abandonment business we acquired on October 1, 2021, thus no prior period costs.

Electricity generation expenses decreased approximately 11% to $2.32 per boe for the nine months ended September 30, 2022 from $2.62 per boe for the same period in 2021 due to lower volumes sold resulting from the previously discussed sale of a cogeneration facility, more than offsetting the increase in fuel prices. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements.

Gains and losses on natural gas purchase derivatives for the nine months ended September 30, 2022 and September 30, 2021 consisted of gains of $47 million and $54 million, respectively. The settlement gain for the nine months ended September 30, 2022 was $26 million, or $3.58 per boe, compared to a gain of $42 million, or $5.68 per boe, for same period in 2021, driven by lower hedged volumes in 2022 compared to that of 2021. The mark-to-market valuation gain for the nine months ended September 30, 2022 was $22 million compared to $12 million for the same period in 2021 due to more open notional volumes at September 30, 2022 and higher futures prices relative to our derivative fixed prices compared to those at September 30, 2021. Because we are the fixed price payer on these natural gas swaps, generally, increases in the associated price index above the swap fixed price creates valuation gains.

Transportation expenses declined primarily due to the divestiture of our Piceance properties in early 2022.

Marketing expenses decreased approximately $3 million for the nine months ended September 30, 2022 when compared to the nine months ended September 30, 2021 due to the sale of our Piceance Colorado operations in the fourth quarter 2021, which included third-party marketing activities. Piceance has historically accounted for nearly all of our marketing revenues.

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General and administrative expenses increased $19 million, or 37%, to approximately $70 million for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. The majority of the increase was from the acquisition of CJWS in October of 2021; therefore, the comparable period of last year had no such expenses. For the nine months ended September 30, 2022 and September 30, 2021, general and administrative expenses included non-cash stock compensation costs of approximately $12 million and $10 million, respectively. We incurred approximately $0.7 million related to the CJWS acquisition which have been categorized as non-recurring for the nine months ended September 30, 2021. There was approximately $0.2 million of non-recurring expenses in the same period of 2022.

Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, increased $17 million, or 42%, to $57 million for the nine months ended September 30, 2022 compared to $40 million for the nine months ended September 30, 2021. A substantial majority of the year-over-year increase was due to the CJWS acquisition, as well as employee cost inflation and higher professional services expenses.

DD&A increased $12 million, or 11%, to approximately $117 million for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. The CJWS acquisition increased depreciation by $9 million with the balance of the increase from slightly higher depletion rates in the D&P segment.

Taxes, Other Than Income Taxes



	Nine Months Ended September 30,				$ Change		% Change
	2022		2021
	(per boe)
Severance taxes	$	1.42	$	0.92	$	0.50	54	%
Ad valorem and property taxes	1.49		1.91		(0.42)		(22)	%
Greenhouse gas allowances	0.60		1.82		(1.22)		(67)	%
Total taxes other than income taxes	$	3.51	$	4.65	$	(1.14)	(25)	%

Taxes, other than income taxes decreased 25% to $3.51 per boe for the nine months ended September 30, 2022 compared to $4.65 per boe for the nine months ended September 30, 2021. Severance taxes increased due to higher production and prices in Utah, while property taxes were lower due to the divestitures of Piceance and Placerita. GHG expense decreased due to lower emissions from the divestiture of Placerita and its cogeneration facility and allowances we acquired at comparatively lower prices.

Other Operating Expenses (Income)

For the nine months ended September 30, 2022, other operating expenses were $5 million and mainly consisted of over $2 million in royalty audit charges incurred prior to our emergence and restructuring in 2017 and approximately $2 million loss on the divestiture of the Piceance properties. For the nine months ended September 30, 2021, other operating expenses were $5 million and mainly consisted of approximately $3 million of unamortized debt issuance costs related to the termination of the 2017 RBL Facility, approximately $3 million of supplemental property tax assessments, royalty audit charges and tank rental costs and $1 million of various other costs such as abandonment costs and legal fees, partially offset by $2 million of income from employee retention credits.

Interest Expense

Interest expense decreased 5% in the nine months ended September 30, 2022 compared to the same period in 2021 as we had lower intra-period working capital borrowings on the 2021 RBL Facility in 2022.

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Income Taxes

Our effective tax rate was 5% for the nine months ended September 30, 2022 and September 30, 2021, respectively. The rates were impacted by changes in the valuation allowance recorded against deferred tax assets.

Non-GAAP Financial Measures

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

Adjusted Net Income (Loss) is not a measure of net income (loss), and Discretionary Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA is not a measure of either, in all cases, as determined by GAAP. Adjusted EBITDA, Adjusted Net Income (Loss) and Discretionary Free Cash Flow 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 allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility.

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

We define Discretionary Free Cash Flow as cash flow from operations less regular fixed dividends and the capital needed to hold production flat. We expect to allocate 60% of Discretionary Free Cash Flow predominantly in the form of cash variable dividends, as well as opportunistic debt repurchases. The remaining 40% will be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. Our management believes Discretionary Free Cash Flow provides useful information in assessing our financial condition, and is the primary metric to determine the quarterly variable dividend.

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

We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature.

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

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

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



	Three Months Ended						Nine Months Ended
	September 30, 2022		June 30, 2022		September 30, 2021		September 30, 2022		September 30, 2021
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	191,660	$	43,354	$	9,836	$	178,204	$	(24,367)
Add (Subtract):
Interest expense	7,867		7,729		7,810		23,271		24,513
Income tax expense (benefit)	10,884		2,145		(758)		9,678		(1,206)
Depreciation, depletion and amortization	39,506		38,055		35,902		117,338		105,592


(Gains) losses on derivatives	(143,221)		51,319		15,885		40,902		85,672
Net cash paid for scheduled derivative settlements	(14,739)		(37,628)		(17,622)		(84,519)		(54,204)
Other operating expenses	623		353		3,986		4,745		4,827
Stock compensation expense	4,401		4,420		3,580		12,623		10,219
Non-recurring costs	—		—		705		198		705

Adjusted EBITDA	$	96,981	$	109,747	$	59,324	$	302,440	$	151,751


	Three Months Ended						Nine Months Ended
	September 30, 2022		June 30, 2022		September 30, 2021		September 30, 2022		September 30, 2021
	(in thousands)
Adjusted EBITDA reconciliation to net cash provided by operating activities:
Net cash provided by operating activities	$	95,762	$	111,242	$	22,399	$	255,534	$	82,258
Add (Subtract):
Cash interest payments	14,493		449		14,189		29,481		29,114
Cash income tax payments	321		2,484		294		2,805		294

Non-recurring costs	—		—		705		198		705

Other changes in operating assets and liabilities	(13,595)		(4,428)		21,737		14,422		39,380

Adjusted EBITDA	$	96,981	$	109,747	$	59,324	$	302,440	$	151,751

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


	Three Months Ended				Nine Months Ended
	September 30, 2022		June 30, 2022		September 30, 2022
	(in thousands)
Discretionary Free Cash Flow:
Operating cash flow(1)	$	95,762	$	111,242	$	255,534
Subtract:
Maintenance capital(2)(3)	(38,312)		(32,134)		(96,883)
Fixed dividends(4)	(4,726)		(4,726)		(14,688)
Discretionary Free Cash Flow	$	52,724	$	74,382	$	143,963

__________

(1) On a consolidated basis.

(2) D&P business only.

(3) Maintenance capital is the capital required to keep annual production flat, calculated as the capital expenditures for the D&P business during the period presented.

(4) Represents fixed dividends declared which are included in the “Dividends declared on common stock” line in the the consolidated statement of stockholders’ equity.

Discretionary Free Cash Flow was $53 million in the third quarter of 2022 compared to $74 million in the second quarter of 2022. The key drivers of the lower Discretionary Free Cash Flow in the third quarter included the $14 million semi-annual interest payment and a $6 million increase in maintenance capital. The quarterly variable dividend is 60% of Discretionary Free Cash Flow based on our shareholder return model which began in 2022.

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


	Three Months Ended						Nine Months Ended
	September 30, 2022		June 30, 2022		September 30, 2021		September 30, 2022		September 30, 2021
	(in thousands)
Adjusted Net Income (Loss) reconciliation to net income (loss):
Net income (loss)	$	191,660	$	43,354	$	9,836	$	178,204	$	(24,367)

Add (Subtract):
(Gains) losses on derivatives	(143,221)		51,319		15,885		40,902		85,672
Net cash paid for scheduled derivative settlements	(14,739)		(37,628)		(17,622)		(84,519)		(54,204)
Other operating expenses	623		353		3,986		4,745		4,827

Non-recurring costs	—		—		705		198		705

Total additions, net	(157,337)		14,044		2,954		(38,674)		37,000
Income tax benefit (expense) of adjustments and discrete income tax items	11,192		(4,262)		(1,254)		1,992		(1,765)
Adjusted Net Income	$	45,515	$	53,136	$	11,536	$	141,522	$	10,868

Basic EPS on Adjusted Net Income	$	0.58	$	0.67	$	0.14	$	1.78	$	0.14
Diluted EPS on Adjusted Net Income	$	0.55	$	0.64	$	0.14	$	1.70	$	0.13

Weighted average shares of common stock outstanding - basic	78,044		79,596		80,242		79,304		80,277
Weighted average shares of common stock outstanding - diluted	82,045		83,015		82,898		83,472		82,715

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


	Three Months Ended						Nine Months Ended
	September 30, 2022		June 30, 2022		September 30, 2021		September 30, 2022		September 30, 2021
	(in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
General and administrative expenses	$	23,388	$	23,183	$	17,614	$	69,513	$	50,749
Subtract:
Non-cash stock compensation expense (G&A portion)	(4,281)		(4,263)		(3,467)		(12,250)		(9,899)
Non-recurring costs	—		—		(705)		(198)		(705)
Adjusted general and administrative expenses	$	19,107	$	18,920	$	13,442	$	57,065	$	40,145

Development and production segment, and corporate	$	15,783	$	15,635	$	13,442	$	47,386	$	40,145
Development and production segment, and corporate per $/boe	$	6.66	$	6.55	$	5.34	$	6.62	$	5.40
Well servicing and abandonment segment	$	3,324	$	3,285	$	—	$	9,679	$	—

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Liquidity and Capital Resources

Currently, we expect to fund the remainder of our 2022 capital expenditures with cash flows from our operations. As of September 30, 2022, we had liquidity of $256 million, consisting of $48 million cash on hand, $193 million available for borrowings under our 2021 RBL Facility and $15 million available for borrowings under our 2022 ABL Facility (as defined below). We also have $400 million in aggregate principal amount 7% senior unsecured notes due February 2026 (the “2026 Notes”) outstanding as further discussed below.

In accordance with our shareholder return model, which went into effect January 1, 2022, we increased cash returns to our shareholders, further demonstrating our commitment to be a leading returner of capital to our shareholders. The model is based on our Discretionary Free Cash Flow, which is defined as cash flow from operations less regular fixed dividends and the capital needed to hold oil and gas production flat. See “Management’s Discussion and Analysis—Non-GAAP Financial Measures” for reconciliation of Discretionary Free Cash Flow to cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. Under this model, the company intends to allocate Discretionary Free Cash Flow on a quarterly basis as follows: (a) 60% predominantly in the form of variable cash dividends to be paid quarterly, as well as opportunistic debt repurchases; (b) 40% in the form of discretionary capital, to be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention.

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

2021 RBL Facility

On August 26, 2021, Berry Corp, as a guarantor, together with Berry LLC, as the borrower, entered into a credit agreement that provided for a revolving loan with up to $500 million of commitment, subject to a reserve borrowing base (as amended by the First Amendment, the Second Amendment and the Third Amendment, each as defined below, the “2021 RBL Facility”). Our initial borrowing base was $200 million. The 2021 RBL Facility provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $20 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the 2021 RBL Facility on a dollar for dollar basis. The 2021 RBL Facility matures on August 26, 2025, unless terminated earlier in accordance with the 2021 RBL Facility terms. Borrowing base redeterminations generally become effective each May and November, although the borrower and the lenders may each make one interim redetermination between scheduled redeterminations. In December 2021, we completed the first scheduled semi-annual borrowing base redetermination and entered into that certain First Amendment to Credit Agreement (the “First Amendment”), which resulted in a reaffirmed borrowing base at $200 million and changes to the hedging covenants in respect of the exclusion of short puts or similar derivatives in the calculation of minimum and maximum hedging requirements.

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Credit Agreement (the “Third Amendment”), which among other things (1) increased the borrowing base from $200 million to $250 million; (2) established the Aggregate Elected Commitment Amounts (as defined in the 2021 RBL Facility) at $200 million initially; and (3) converted all outstanding Eurodollar Loans (into Term Benchmark Loans (each as defined in the 2021 RBL Facility) with an initial interest period of one-month’s duration and otherwise give effect to the transition from the London interbank offered rate (“LIBOR”) to the secured overnight financing rate (“SOFR”) by replacing the adjusted LIBOR rate with the term SOFR rate for one, three or six months plus 0.1% (subject to a floor of 0.5%).

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

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As of September 30, 2022, we had no borrowings outstanding, $7 million in letters of credit outstanding and approximately $193 million of available borrowing capacity under the 2021 RBL Facility.

2022 ABL Facility

As of September 30, 2022, CJWS had no borrowings and no letters of credit outstanding with $15 million of available borrowing capacity under the 2022 ABL Facility.

Hedging

We have protected a significant portion of our anticipated cash flows in 2022 through 2024, using our commodity hedging program, including swaps, puts, calls and collars. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge natural gas purchases to protect against price increases. In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. Our generally low-decline production base, coupled with our stable operating cost environment, affords an ability to hedge a material amount of our future expected production. We expect our operations to generate sufficient cash flows at current commodity prices including our current hedging positions. For information regarding risks related to our hedging program, see “Item 1A. Risk Factors—Risks Related to Our Operations and Industry” in our Annual Report.

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


	Q4 2022		FY 2023		FY 2024		FY 2025
Brent
Swaps
Hedged volume (bbls)	1,516,750		5,165,028		3,367,610		—
Weighted-average price ($/bbl)	$	78.24	$	76.67	$	76.07	$	—

Put Spreads



Hedged volume (bbls)	368,000		2,190,000		1,281,000		—
Weighted-average price ($/bbl)	$50.00/$40.00		$50.00/$40.00		$50.00/$40.00		$	—




Producer Collars
Hedged volume (bbls)	—		1,460,000		1,098,000		365,000
Weighted-average price ($/bbl)	$	—	$40.00/$106.00		$40.00/$105.00		$50.00/$98.50
Henry Hub - Natural Gas purchases



Consumer Collars
Hedged volume (mmbtu)	3,680,000		5,430,000		—		—
Weighted-average price ($/mmbtu)	$4.00/$2.75		$4.00/$2.75		$	—	$	—
NWPL - Natural Gas purchases
Swaps
Hedged volume (mmbtu)	1,220,000		12,800,000		7,320,000		6,080,000
Weighted-average price ($/mmbtu)	$	6.40	$	5.48	$	4.27	$	4.27

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



	Three Months Ended						Nine Months Ended
	September 30, 2022		June 30, 2022		September 30, 2021		September 30, 2022		September 30, 2021
Crude Oil (per bbl):
Realized sales price, before the effects of derivative settlements	$	89.54	$	105.70	$	69.01	$	95.83	$	63.59
Effects of derivative settlements	$	(13.13)	$	(21.92)	$	(14.66)	$	(16.81)	$	(15.03)
Oil with hedges ($/bbl)	$	76.41	$	83.78	$	54.35	$	79.02	$	48.56
Purchased Natural Gas (per mmbtu):
Purchase price, before the effects of derivative settlements	$	8.16	$	7.30	$	5.79	$	7.24	$	5.32
Effects of derivative settlements	$	(2.53)	$	(1.89)	$	(2.30)	$	(1.53)	$	(2.34)
Purchased Natural Gas with hedges	$	5.63	$	5.41	$	3.49	$	5.71	$	2.98

Cash Dividends

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The following table represents the regular fixed cash dividends on our common stock and variable dividends approved by our Board of Directors.




	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year-to-Date
Fixed Dividends	$	0.06	$	0.06	$	0.06	$	0.06	$	0.24
Variable Dividends(1)	0.13		0.56		0.41		—		1.10
Total	$	0.19	$	0.62	$	0.47	$	0.06	$	1.34

__________

(1) Variable Dividends are declared the quarter following the period of results (the period used to determine the variable divided based on the shareholder return model). The table notes total dividends earned in each quarter.

Stock Repurchase Program

Debt Repurchase Program

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Statements of Cash Flows

The following is a comparative cash flow summary:



	Nine Months Ended September 30,
	2022		2021
	(in thousands)
Net cash:
Provided by operating activities	$	255,534	$	82,258
Used in investing activities	(109,664)		(110,536)
Used in financing activities	(119,680)		(14,118)
Net increase (decrease) in cash and cash equivalents	$	26,190	$	(42,396)

Operating Activities

Cash provided by operating activities increased for the nine months ended September 30, 2022 by approximately $173 million when compared to the nine months ended September 30, 2021, and the most significant increases were sales of $210 million, an increase in working capital of $29 million, an increase of $17 million related to the net margin for CJWS, and a decrease in taxes, other than income taxes of $9 million, partially offset by an increase of $55 million in operating expenses, an increase of $30 million in derivative settlements paid, and an increase of $7 million in general and administrative expenses (excluding CJWS).

Investing Activities

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



	Nine Months Ended September 30,
	2022		2021
	(in thousands)
Capital expenditures:
Capital expenditures	$	(102,523)	$	(105,046)

Changes in capital expenditures accruals	14,129		5,299

Acquisitions, net of cash received	(21,270)		(11,649)
Proceeds from sale of properties and equipment and other	—		860

Cash used in investing activities	$	(109,664)	$	(110,536)

Cash used in investing activities decreased $1 million for the nine months ended September 30, 2022 when compared to the same period in 2021, primarily due to a decrease in cash used for capital expenditures and related accruals, partially offset by an increase in cash used for acquisitions.

Financing Activities

Cash used by financing activities in 2022 was primarily for dividends paid of $74 million, for the purchase of treasury stock of $42 million, and for taxes on equity awards of $4 million. In 2021, the cash used was primarily for dividends paid of $7 million, debt issuance cost write-off related to the 2017 RBL Facility of $3 million, purchase of treasury stock of $2 million, and shares withheld for payment of taxes on equity awards and other of $2 million.

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Guarantor Financial Information

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

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

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


	Nine Months Ended
	September 30, 2022
	(in thousands)
	(unaudited)
Revenue from third parties	$	677,287
Expenses from operations (unhedged)	$	433,280



Net income	$	172,934


	September 30, 2022		December 31, 2021
	(in thousands)
	(unaudited)
Receivables from non-guarantor subsidiaries	$	—	$	16,792
Other current assets	131,345		114,983
Total current assets	$	131,345	$	131,775
Noncurrent assets	$	1,356,704	$	1,317,241


Current liabilities due to non-guarantor subsidiaries	$	18	$	—
Other current liabilities	158,778		179,691
Total current liabilities	$	158,796	$	179,691

Other noncurrent liabilities	$	575,329	$	576,681

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Balance Sheet Analysis

The changes in our balance sheet from December 31, 2021 to September 30, 2022 are discussed below.



	September 30, 2022		December 31, 2021
	(in thousands)
Cash and cash equivalents	$	41,473	$	15,283
Accounts receivable, net	$	93,635	$	86,269
Derivative instruments assets - current and long-term	$	21,640	$	1,070


Other current assets	$	36,738	$	45,946
Property, plant & equipment, net	$	1,319,980	$	1,301,349

Other noncurrent assets	$	10,886	$	6,562
Accounts payable and accrued expenses	$	156,844	$	157,524
Derivative instruments liabilities - current and long-term	$	25,199	$	48,202

Long-term debt	$	395,432	$	394,566
Deferred income taxes liability - long-term	$	8,042	$	1,831
Asset retirement obligations - long-term	$	137,751	$	143,926
Other noncurrent liabilities	$	31,835	$	17,782
Stockholders’ equity	$	769,249	$	692,648

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

The $7 million increase in accounts receivable was attributable to $7 million in higher sales from the well servicing and abandonment segment.

The $9 million decrease in other current assets is primarily due to a $3 million refund of prepaid permitting fees, a $3 million refund of letter of credit collateral, $3 million for the expensing of prepaid expenses, mostly insurance, for both the development and production segment and the well servicing and abandonment segment, partially offset by prepaying $2 million in property taxes in the third quarter.

The $19 million increase in property, plant and equipment was primarily due to $107 million in capital investments and $21 million of acquisitions, primarily the Antelope Creek oil and gas properties in Utah, offset by year to date depreciation of $109 million.

The $4 million increase in other noncurrent assets was primarily due to the adoption of new lease accounting rules in the first quarter for $6 million, net of accumulated amortization, partially offset by amortization of debt issuance costs of $1 million and $1 million in the well servicing and abandonment segment.

The $1 million decrease in accounts payable and accrued expenses included decreases of $8 million in greenhouse gas emissions obligation which was reclassified to long-term liabilities based on the expected due date, $7 million in accrued interest, $6 million in accounts payable related to the D&P segment, $5 million in dividends payable, partially offset by increases of $8 million in the well servicing and abandonment segment payables, $7 million in accrued expenses, $4 million in royalties payable, $3 million in taxes other than income taxes, and $2 million in operating lease liability.

The $44 million decrease in net derivative liabilities, which includes the derivative assets, is due to the change from a net liability of $47 million at December 31, 2021 to a net liability of $4 million as of September 30, 2022. 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 $1 million increase in long-term debt reflects the year-to-date amortization of debt issuance costs.

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The $6 million increase in deferred income tax liability was driven by accelerated tax deductions.

The $6 million decrease in the long-term portion of the asset retirement obligations from $144 million at December 31, 2021 to $138 million at September 30, 2022 was due to $16 million of liabilities settled during the period and $1 million reduction due to property sales offset by $8 million of accretion expense and $3 million of liabilities incurred.

The $14 million increase in other noncurrent liabilities was due to $8 million of non-current greenhouse gas liabilities incurred, and $6 million for the long term portion of lease liability based on the adoption of new lease accounting rules in the first quarter of 2022.

The $77 million increase in stockholders’ equity was due to the net income of $178 million and $13 million of stock-based equity awards, net of taxes, offset by decreases of $69 million of common stock dividends declared, $42 million for the purchase of treasury stock and $4 million of shares withheld for payment of taxes on equity awards.

Lawsuits, Claims, Commitments, and Contingencies

Securities Litigation Matters

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alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on January 24, 2022, and on September 13, 2022, the Court issued an order denying that motion. The Defendants have moved for reconsideration and/or clarification of the September 13 order, and that motion is currently pending.

Contractual Obligations

The following is a summary of our commitments and contractual obligations as of September 30, 2022:


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







Off-Balance Sheet arrangements:
Transportation contracts(1)	$	90,297	$	10,719	$	17,840	$	16,180	$	45,558

Other purchase obligations(2)	17,100		6,600		10,500		—		—
Total contractual obligations	$	107,397	$	17,319	$	28,340	$	16,180	$	45,558

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(1) Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure pipeline transportation of natural gas to market and between markets.

(2) Amounts include a drilling commitment in California, for which we are required to drill 57 wells with a minimum commitment of $17.1 million by October 2023. In May 2022, the drilling commitment was revised to move the deadline for 27 wells from December 2022 to October 2023, which moved approximately $8 million from a short-term commitment to a long-term commitment. Per the revised agreement, 22 wells, with a minimum commitment of $6.6 million are still required to be drilled by December 2022.

Critical Accounting Policies and Estimates

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

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Cautionary Note Regarding Forward-Looking Statements

The information included or incorporated by reference in this Quarterly Report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this Quarterly Report that address plans, activities, events, objectives, goals, strategies, or developments that the Company expects, believes or anticipates will or may occur in the future, such as those regarding our financial position, liquidity, cash flows (including, but not limited to, Discretionary Free Cash Flow), financial and operating results, capital program and development and production plans, operations and business strategy, potential acquisition and other strategic opportunities, reserves, hedging activities, capital expenditures, return of capital, our shareholder return model and the payment of future dividends, future repurchases of stock or debt, capital investments, our ESG strategy and the initiation of new projects or business in connection therewith, recovery factors, and other guidance, are forward-looking statements. These statements are based upon various assumptions, many of which are based, in turn, upon further assumptions. Although we believe that these assumptions were reasonable when made, these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control. Therefore, such forward-looking statements involve significant risks and uncertainties that could materially affect our expected financial position, financial and operating results, liquidity, cash flows (including, but not limited to, Discretionary Free Cash Flow), and business prospects. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect us are discussed below in Part II, Item 1A. “Risk Factors” in this Quarterly Report, as well as in Part I, Item 1A. “Risk Factors” our most recent Annual 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, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;

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

•the length, scope and severity of the ongoing COVID-19 pandemic or the emergence of a new pandemic, including the effects of related public health concerns and the impact of actions taken by governmental authorities and other third parties in response to the pandemic and its impact on commodity prices, supply and demand considerations, global supply chain disruptions and labor constraints;

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

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

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•those resulting from the COVID-19 pandemic;

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

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

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

•supply of and demand for oil, natural gas and NGLs, including due to the actions of foreign producers, importantly including OPEC+ and change in OPEC+'s production levels;

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

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

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

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

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

•concerns about climate change and other air quality issues;

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

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

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

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

•changes in tax laws;

•effects of competition;

•uncertainties and liabilities associated with acquired and divested assets;

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

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

•asset impairments from commodity price declines;

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

•geographical concentration of our operations;

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

•impact of derivatives legislation affecting our ability to hedge;

•failure of risk management and ineffectiveness of internal controls;

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•catastrophic events, including wildfires, earthquakes and pandemics;

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

•potential liability resulting from pending or future litigation;

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

•information technology failures or cyberattacks; and.

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

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

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

As of September 30, 2022, there have been no material changes in the information required to be provided under Item 305 of Regulation S-K included under the caption Management’s Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A)- Quantitative and Qualitative Disclosures About Market Risk, in the 2021 Annual Report, except as discussed below.

Price Risk

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

We have historically hedged a large portion of our expected crude oil and our natural gas production, as well as our natural gas purchase requirements to reduce exposure to fluctuations in commodity prices. We use derivatives such as swaps, calls, puts and collars to hedge. We do not enter into derivative contracts for speculative trading purposes and we have not accounted for our derivatives as cash-flow or fair-value hedges. We continuously consider the level of our oil production and gas purchases that is appropriate to hedge based on a variety of factors, including, among other things, current and future expected commodity prices, our expected capital and operating costs, our overall risk profile, including leverage, size and scale, as well as any requirements for, or restrictions on, levels of hedging contained in any credit facility or other debt instrument applicable at the time.

We determine the fair value of our oil and gas sales and natural gas purchase derivatives using valuation techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We validate data provided by third parties by understanding the valuation inputs used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. At September 30, 2022, the fair value of our hedge positions was a net liability of approximately $4 million. A 10% increase in the oil and natural gas index prices above the September 30, 2022 prices would result in a net liability of approximately $44 million; conversely, a 10% decrease in the oil and natural gas index prices below the September 30, 2022 prices would result in a net asset of approximately $37 million. For additional information about derivative activity, see Note 3, Derivatives, in the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this report.

Actual gains or losses recognized related to our derivative contracts depend exclusively on the price of the underlying commodities on the specified settlement dates provided by the derivative contracts. Additionally, we cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our cash flows could be negatively impacted.

Item 4. Controls and Procedures

Our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, they each concluded that our disclosure controls and procedures were effective as of September 30, 2022.

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

Other Matters.

For additional information regarding legal proceedings, see Note 4 to the condensed consolidated financial statements in Part I of this Form 10-Q and Note 5 to our consolidated financial statements for the year ended December 31, 2021 included in the Annual Report.

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Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading “Item 1A. Risk Factors” in our most recent Annual Report.

The methane emissions charge and excise tax on repurchases of corporate stock included in the Inflation Reduction Act of 2022 could increase our tax burden and influence our share repurchase decisions.

President Biden signed the Inflation Reduction Act (“IRA”) into law on August 16, 2022 which, among other provisions, imposes a fee on the emissions of methane from certain sources in the oil and natural gas sector. Beginning in 2024, the IRA’s methane emissions charge imposes a fee on excess methane emissions from certain oil and gas facilities, starting at $900 per metric ton of leaked methane in 2024 and rising to $1,200 in 2025, and $1,500 in 2026 and thereafter. The imposition of this fee and other provisions of the IRA could increase our operating costs and accelerate the transition away from oil and gas, which could adversely affect our business and results of operations.

Additionally, the IRA includes a 1% stock buyback excise tax on certain publicly traded corporations that repurchase stock from their shareholders after December 31, 2022. The amount subject to the excise tax is the fair market value of stock repurchased by a corporation net of the fair market value of any stock issued by such corporation during such taxable year. Although the application of this excise tax is not entirely clear, any redemptions made after December 31, 2022 in connection with our stock repurchase program, or otherwise, may be subject to this excise tax. There can be no assurance that there will be sufficient new issuances during the same taxable year to offset the fair market value of the redemptions. Consequently, if we are subject to this excise tax, it could influence our share repurchase decisions and increase our tax burden.

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

Stock Repurchase Program

In April 2022, our Board of Directors approved an increase of $102 million to the Company’s stock repurchase authorization bringing the Company’s remaining share repurchase authority to $150 million. As of September 30, 2022, the Company’s remaining total share repurchase authority is $108 million, after the repurchases made in the second quarter of 2022. The Board’s authorization permits the Company to make purchases of its common stock from time to time in the open market and in privately negotiated transactions, subject to market conditions and other factors, up to the aggregate amount authorized by the Board. The Board’s authorization has no expiration date.

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Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
July 1 - 31, 2022	—	$	—	—	$	—
August 1 - 31, 2022	2,000,000	$	9.47	2,000,000	$	107,864,000
September 1 - 30, 2022	—	$	—	—	$	—
Total	2,000,000	$	—	2,000,000	$	107,864,000

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Item 6. Exhibits


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

__________

(*) Filed herewith.

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GLOSSARY OF COMMONLY USED TERMS

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

“Absolute TSR” means absolute total stockholder return.

“AROs” means asset retirement obligations.

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

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

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

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

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

“bbl” 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.

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

“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.

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

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

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

“CEQA” 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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“EOR” means enhanced oil recovery.

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

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“EPS” is an abbreviation for earnings per share.

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

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

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

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

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

“FIP” is an abbreviation for Federal Implementation Plan.

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

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

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

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

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

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

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

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

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

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

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

“ICE” means Intercontinental Exchange.

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

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

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“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.

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

“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.

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

“MW” means megawatt.

“MWHs”means megawatt hours.

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

“NASDAQ” means Nasdaq Global Select Market.

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

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

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

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

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

“NRI” is an abbreviation for net revenue interest.

“NYMEX” means New York Mercantile Exchange.

“Oil” means crude oil or condensate.

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

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

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

“OTC” means over-the-counter

“PALs” is an abbreviation for project approval letters.

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

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

“PDP” is an abbreviation for proved developed producing.

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

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

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

“PPA” is an abbreviation for power purchase agreement.

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

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

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

“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

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

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

“QF” means qualifying facility.

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

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

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

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

“Relative TSR” means relative total stockholder return.

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

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

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

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

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

“RSUs” is an abbreviation for restricted stock units.

“SARs” is an abbreviation for stock appreciation rights.

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

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

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

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

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

“Steamflood” means cyclic or continuous steam injection.

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

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“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 CERLCA.

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

“Unconventional resource plays” means a resource play that uses methods other than traditional vertical well extraction. Unconventional resources are trapped in reservoirs with low permeability, meaning little to no ability for the oil or natural gas to flow through the rock and into a wellbore. Examples of unconventional oil resources include oil shales, oil sands, extra-heavy oil, gas-to-liquids and coal-to-liquids.

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

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

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

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

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

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

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

“WST” is an abbreviation for well stimulation treatment.

“WTI” means West Texas Intermediate.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.




		Berry Corporation (bry)
		(Registrant)

Date:	November 2, 2022	/s/ Cary Baetz
		Cary Baetz
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer)


Date:	November 2, 2022	/s/ M. S. Helm
		Michael S. Helm
		Chief Accounting Officer
		(Principal Accounting Officer)

Document

EXHIBIT 31.1

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

PURSUANT TO §302 OF THE SARBANES-OXLEY ACT OF 2002

I, A. T. “Trem” Smith, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Berry Corporation (bry) (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date: November 2, 2022			/s/ A. T. Smith
			A. T. “Trem” Smith
			President and Chief Executive Officer

Document

EXHIBIT 31.2

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

PURSUANT TO §302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cary Baetz, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Berry Corporation (bry) (the “registrant”);

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date: November 2, 2022			/s/ Cary Baetz
			Cary Baetz
			Executive Vice President and Chief Financial Officer

Document

EXHIBIT 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO

18 U.S.C. § 1350,

AS ADOPTED PURSUANT TO

§ 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report on Form 10-Q of Berry Corporation (bry) (the “Company”) for the fiscal period ended September 30, 2022, as filed with the Securities and Exchange Commission on November 2, 2022 (the “Report”), A. T. “Trem” Smith, as Chief Executive Officer of the Company, and Cary Baetz, as Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section § 1350, as adopted pursuant to Section § 906 of the Sarbanes-Oxley Act of 2002, to the best of our knowledge that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Date:	November 2, 2022	/s/ A. T. Smith
		A. T. “Trem” Smith
		President and Chief Executive Officer


Date:	November 2, 2022	/s/ Cary Baetz
		Cary Baetz
		Executive Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Berry Corporation (bry) and will be retained by Berry Corporation (bry) and furnished to the Securities and Exchange Commission or its staff upon request.

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.