0001705873-23-000026 | 10-K | XBRL Viewer

Income Taxes

12 Months Ended

Dec. 31, 2022

Income TaxesThe change in our effective rate from (10.0)% in the year ended December 31, 2021 to (20.4)% for the year ended December 31, 2022 is primarily due to recognition of U.S. federal general business credits in 2022 related to the 2021 tax period and release of the valuation allowance. The credits are available to offset future federal income tax liabilities. The change in our effective rate from 2.8% in the year ended December 31, 2020 to (10.0)% for the year ended December 31, 2021 is primarily due to nondeductible stock compensation, adjustments to our tax credit carryforward balances and changes in the valuation allowance.

Income tax expense (benefit) consisted of the following:


	Year Ended December 31,
	2022		2021		2020
	(in thousands)
Current taxes:
Federal	$	642	$	—	$	—
State	1,597		581		828
Total current taxes	2,239		581		828
Deferred taxes:
Federal	(44,053)		832		2,653
State	(622)		—		(10,699)
Total deferred taxes	(44,675)		832		(8,046)
Total current and deferred taxes	$	(42,436)	$	1,413	$	(7,218)

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:


	Year Ended December 31,
	2022		2021		2020
Federal statutory rate	21.0	%	21.0	%	21.0	%
State, net of federal tax benefit	6.2	%	3.7	%	6.3	%
Nondeductible compensation	1.8	%	(24.5)	%	—	%
Effect of permanent differences	(0.3)	%	(4.7)	%	(0.6)	%
Tax credits - Prior Year	(11.5)	%	(29.5)	%	4.9	%
Tax credits - Current Year	—	%	21.5	%	1.1	%
State return to provision	(0.3)	%	(0.2)	%	(1.1)	%

Change in valuation allowance	(37.3)	%	2.7	%	(28.8)	%
Effective tax rate	(20.4)	%	(10.0)	%	2.8	%

Significant components of the deferred tax assets and liabilities are as follows:


	Year Ended December 31,
	2022		2021
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	22,402	$	40,846
Accruals	10,728		11,731
Asset retirement obligations	48,994		44,437
Derivative instruments	2,280		12,776
Tax credits	88,908		61,044

Other	2,882		3,551
Subtotal	176,194		174,385
Valuation allowance	—		(77,546)
Total deferred tax assets	176,194		96,839
Deferred tax liabilities:
Book tax differences in property basis	(133,350)		(98,670)

Total deferred tax liabilities	(133,350)		(98,670)
Net deferred tax asset (liability)	$	42,844	$	(1,831)

As of December 31, 2022, the Company had approximately $107 million of federal net operating loss (“NOL”) carryforwards and no state net operating loss carryforwards. The federal net operating loss carryovers have no expiration date. In addition, as of December 31, 2022, the Company had US federal general business tax credit carryforwards totaling $82 million and state tax credits of $8 million ($7 million net of federal benefit), which, if unused, will expire after taxable years ended 2037 and 2033, respectively.

In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those deferred income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and projected future income for this determination. As of December 31, 2022, due to the positive evidence of current year income, fair value of proved reserves and related future income projections, commodity price forecasts based on published market quotes, and the reversal of existing federal and state temporary differences, and based on the preponderance of that evidence, we determined there is sufficient positive evidence to conclude that is is more likely than not that our deferred tax assets are realizable. Therefore, we have fully released the valuation allowance in 2022, resulting in an income tax benefit of $78 million. We previously recorded a valuation allowance on our deferred tax assets for the year ended December 31, 2021 in the amount of $78 million.

We had no material uncertain tax positions at December 31, 2022 or 2021. We do not believe that the total unrecognized benefits will significantly increase within the next 12 months.

We are subject to taxation in the United States and various state jurisdictions. We are not currently under audit by any federal or state income tax authority. The 2019 through 2022 federal and 2018 through 2022 state tax years generally remain open to examination under the respective statute of limitations.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

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+ Details

Oil and Natural Gas Properties and Other Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2022

Extractive Industries [Abstract]

Schedule of Aggregate Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:


	Year Ended December 31,
	2022		2021
	(in thousands)
Proved properties	$	1,477,791	$	1,246,380
Unproved properties	248,073		291,514
Total proved and unproved properties	1,725,864		1,537,894
Less accumulated depletion and amortization	(465,889)		(340,328)
Total proved and unproved properties, net	$	1,259,975	$	1,197,566

Schedule of Other Property and Equipment

Other property and equipment consisted of the following:


	Year Ended December 31,
	2022		2021
	(in thousands)
Cogeneration facilities, natural gas plants and pipelines	$	58,357	$	54,237
Vehicles and service equipment(1)	65,195		55,521
Furniture and equipment	23,779		22,665
Land	6,102		6,101
Buildings and leasehold improvements	2,186		2,186
Total other property and equipment	155,619		140,710
Less: accumulated depreciation	(55,781)		(36,927)
Total other property and equipment, net	$	99,838	$	103,783

__________

(1) Includes CJWS vehicles and service equipment.

Defined Contribution Plan	12 Months Ended
Defined Contribution Plan	Dec. 31, 2022
Retirement Benefits [Abstract]
Defined Contribution Plan	Defined Contribution Plan We sponsor a defined contribution retirement plan under section 401(k) of the Internal Revenue Code to assist all full-time employees in providing for retirement or other future financial needs. Employees are eligible to participate in the 401(k) plan on their date of hire. The 401(k) plan provided for a matching contribution of up to 6% of an employee’s eligible compensation until June 2020 when the Company temporarily suspended matching due to COVID-19. As of January 2021, the Company reinstated the Plan's matching contributions to 100% of the first 3% of compensation deferred by the participant. As of July 2021, the Company increased the Plan's matching contributions to 100% of the first 6% of compensation deferred by the participant. We expensed approximately $6.2 million, $1.6 million, and $1.0 million for the years ended December 31, 2022, 2021, and 2020, respectively, under the provisions of the 401(k) plan.

- Definition

The entire disclosure for retirement benefits.

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+ Details

Debt

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Debt

The following table summarizes our outstanding debt:


	December 31, 2022		December 31, 2021		Interest Rate	Maturity	Security
	(in thousands)

2021 RBL Facility	$	—	$	—	variable rates 9.5% (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 8.3% (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	(4,265)		(5,434)
Long-Term Debt, net	$	395,735	$	394,566

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At December 31, 2022 and 2021, debt issuance costs for the 2021 RBL Facility and the 2022 ABL Facility (each as defined below) reported in “other noncurrent assets” on the balance sheet were approximately $4 million and $5 million, net of amortization, respectively. In 2021, we expensed $3 million of unamortized debt issuance costs related to the modification of the 2017 RBL Facility and also incurred approximately $4 million of legal and bank fees related to the issuance of the 2021 RBL Facility. At December 31, 2022 and 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 were approximately $4 million and $5 million, respectively.

For the years ended December 31, 2022, 2021, and 2020, the amortization expense for the 2021 RBL Facility, 2022 ABL Facility, the 2017 RBL Facility and the 2026 Notes combined, was approximately $2 million, $4 million, and $5 million, respectively. The amortization of debt issuance costs is presented in “interest expense” on the consolidated statements of operations.

Fair Value

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

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 commitments, 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 is $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.

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%).

In December 2022, we completed our scheduled semi-annual borrowing base redetermination, which resulted in a reaffirmed borrowing base at $250 million and $200 million elected commitment amount.

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 December 31, 2022, our leverage ratio and current ratio were 1.2 to 1.0 and 1.7 to 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 December 31, 2022.

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.

We can repurchase equity or make other distributions to our equity holders in an amount equal to (i) 100% of Free Cash Flow (as defined under the 2021 RBL Facility) for the fiscal quarter most recently ended prior to such repurchase or distribution minus (ii) the amount of certain investments made, so long as, in addition to other conditions and limitations as described in the 2021 RBL Facility, availability is equal to or greater than 20% of the elected commitments or borrowing base, whichever is in effect, 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 December 31, 2022, we had no borrowings outstanding, $7 million in letters of credit outstanding, and approximately $193 million of available borrowings 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. As of December 31, 2022, CJWS had a ratio of total liabilities to tangible net worth of 0.2 to 1.0, no advances outstanding, and net income for fiscal year end 2022 was $15 million.

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. CJWS was in compliance with all financial covenants under the 2022 ABL Facility as of December 31, 2022.

As of December 31, 2022, CJWS had no borrowings and $2 million letters of credit outstanding with $13 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.

Senior Unsecured Notes

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

The 2026 Notes are Berry LLC’s senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The 2026 Notes are fully and unconditionally guaranteed on a senior unsecured basis by Berry Corp. and will also be guaranteed by certain of our future subsidiaries; C&J Management and C&J are not guarantors. The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our 2021 RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any subsidiaries that do not guarantee the 2026 Notes, including the obligations of C&J Management and C&J under the 2022 ABL Facility.

Berry LLC may, at its option, redeem all or a portion of the 2026 Notes at any time. If we experience certain kinds of changes of control, holders of the 2026 Notes may have the right to require us to repurchase their notes at 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any

The indenture governing the 2026 Notes contains restrictive covenants that may limit our ability to, among other things:

•incur or guarantee additional indebtedness or issue certain types of preferred stock;

•pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

•transfer, sell or dispose of assets;

•make investments;

•create certain liens securing indebtedness;

•enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

•consolidate, merge or transfer all or substantially all of our assets; and

•engage in transactions with affiliates.

The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain of our subsidiaries. We were in compliance with all covenants as of December 31, 2022.

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 does 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.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (h)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-Section S99
-Paragraph 1
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+ Details

Acquisitions and Divestitures - Pro Forma Revenue (Details) - C&J Well Services Acquisition - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Revenue	$ 664,549	$ 657,796
Net income (loss)	$ 740	$ (250,884)

Commitments and Contingencies

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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

We accrue for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at December 31, 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 December 31, 2022, we are not aware of material indemnity claims pending or threatened against us.

Securities Litigation Matter

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 November 1, 2021, the court-appointed co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not quantify the alleged losses but seeks to recover all damages

sustained by the putative class as a result of these alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on January 24, 2022 and on September 13, 2022, the Court issued an order denying that motion. The case is now in discovery.

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

On October 20, 2022, a shareholder derivative lawsuit was filed in the United States District Court for the Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that piggy-backs on the securities class action referenced above and which is currently pending before the same Court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27, 2023, the court granted the parties’ joint stipulated request to stay the derivative action pending resolution of the related securities class action. 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.

On January 20, 2023, a second shareholder derivative lawsuit was filed, this time in the United States District Court for the District of Delaware, by putative stockholder Molly Karp allegedly on behalf of the Company, again piggy-backing on the securities class action referenced above. This complaint, similar to the first derivative complaint, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the securities violations alleged in the securities class action. In addition, the complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry’s 2022 Proxy Statement was false and misleading in that it suggested the Company’s internal controls were sufficient and the board of directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case. The defendants believe the claims in the shareholder derivative 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.

Other Commitments

In the ordinary course of our business, we enter into certain firm commitments to secure transportation of our production and third-party natural gas to market as well as processing which require a minimum monthly charge regardless of whether the contracted capacity is used or not. At December 31, 2022, future net minimum payments for non-cancelable purchase obligations (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance expense) were as follows:


	2023		2024		2025		2026		2027		Thereafter		Total
	(in thousands)
Processing and transportation contracts(1)	$	11,343	$	9,553	$	8,234	$	8,082	$	8,083	$	43,521	$	88,816
Drilling commitment(2)	8,400		8,700		—		—		—		—		17,100
Total	$	19,743	$	18,253	$	8,234	$	8,082	$	8,083	$	43,521	$	105,916

__________

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

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

Income Taxes - Reconciliation of the Federal Statutory Tax Rate to the Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Federal statutory rate	21.00%	21.00%	21.00%
State, net of federal tax benefit	6.20%	3.70%	6.30%
Nondeductible compensation	1.80%	(24.50%)	0.00%
Effect of permanent differences	(0.30%)	(4.70%)	(0.60%)
Tax credits - Prior Year	(11.50%)	(29.50%)	4.90%
Tax credits - Current Year	0.00%	21.50%	1.10%
State return to provision	(0.30%)	(0.20%)	(1.10%)
Change in valuation allowance	(37.30%)	2.70%	(28.80%)
Effective tax rate	(20.40%)	(10.00%)	2.80%

Debt (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Schedule of Outstanding Debt

The following table summarizes our outstanding debt:


	December 31, 2022		December 31, 2021		Interest Rate	Maturity	Security
	(in thousands)

2021 RBL Facility	$	—	$	—	variable rates 9.5% (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 8.3% (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	(4,265)		(5,434)
Long-Term Debt, net	$	395,735	$	394,566

Commitments and Contingencies - Future Net Minimum Payments for Purchase Obligations and Operating Leases (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Nov. 30, 2022 well	Dec. 31, 2022 USD ($) well
Total
2023		$ 19,743
2024		18,253
2025		8,234
2026		8,082
2027		8,083
Thereafter		43,521
Total		$ 105,916
Drilling commitment, number of wells \| well		57
Drilling commitment, revised total of number of wells by 2023 \| well	28
Processing, transportation and storage contracts
Minimum purchase obligations
2023		$ 11,343
2024		9,553
2025		8,234
2026		8,082
2027		8,083
Thereafter		43,521
Total		88,816
Drilling commitment
Minimum purchase obligations
2023		8,400
2024		8,700
2025		0
2026		0
2027		0
Thereafter		0
Total
Total		$ 17,100

Segment Information

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Segment Information

As of October 1, 2021, we have operated in two business segments: (i) E&P and (ii) well servicing and abandonment. The E&P 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 businesses in California, which became a reportable segment (wells 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 well servicing and abandonment segment occasionally provides services to our E&P segment, as such, we recorded an intercompany elimination of $3 million in revenue and expense during consolidation. The intercompany elimination in 2021 was immaterial.

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.


	Year Ended December 31, 2022
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues(1)	$	874,190	$	184,448	$	(3,188)	$	1,055,450
Net income (loss) before income taxes	$	303,178	$	14,747	$	(110,193)	$	207,732
Adjusted EBITDA	$	411,811	$	26,113	$	(57,976)	$	379,948
Capital expenditures	$	141,930	$	8,455	$	2,536	$	152,921
Total assets	$	1,563,251	$	83,461	$	(15,682)	$	1,631,030


	Year Ended December 31, 2021
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues(1)	$	665,509	$	35,840	$	—	$	701,349
Net income (loss) before income taxes	$	82,826	$	1	$	(96,956)	$	(14,129)
Adjusted EBITDA	$	251,146	$	4,310	$	(43,310)	$	212,146
Capital expenditures	$	129,479	$	1,029	$	2,211	$	132,719
Total assets	$	1,450,157	$	81,093	$	(74,771)	$	1,456,479

__________

(1) These revenues do not include hedge settlements.

Adjusted EBITDA is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources to and assessing performance of each segment. 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.


	Year Ended December 31, 2022
			Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	303,178	$	14,747	$	(67,757)	$	250,168
Add (Subtract):
Interest expense	—		23		30,894		30,917
Income tax benefit	—		—		(42,436)		(42,436)
Depreciation, depletion, and amortization	139,886		12,548		4,413		156,847
Losses on derivatives	48,314		—		—		48,314
Net cash paid for scheduled derivative settlements	(88,023)		—		—		(88,023)
Other operating expenses (income)	3,827		(1,690)		1,585		3,722
Stock compensation expense	1,361		287		15,325		16,973
Non-recurring costs(1)	3,268		198		—		3,466
Adjusted EBITDA	$	411,811	$	26,113	$	(57,976)	$	379,948

__________

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


	Year Ended December 31, 2021
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	82,825	$	1	$	(98,368)	$	(15,542)
Add (Subtract):
Interest expense	—		—		31,964		31,964
Income tax expense	—		—		1,413		1,413
Depreciation, depletion, and amortization	136,915		2,974		4,606		144,495
Losses on derivatives	117,822		—		—		117,822
Net cash paid for scheduled derivative settlements	(87,625)		—		—		(87,625)
Other operating expenses	109		—		2,992		3,101
Stock compensation expense	1,100		—		12,683		13,783
Non-recurring costs(1)	—		1,335		1,400		2,735
Adjusted EBITDA	$	251,146	$	4,310	$	(43,310)	$	212,146

__________

(1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the fourth quarter of

2021.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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+ Details

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($)	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings (Accumulated Deficit)
Beginning balance at Dec. 31, 2019	$ 972,448,000	$ 85,000	$ 901,830,000	$ (49,995,000)	$ 120,528,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares withheld for payment of taxes on equity awards	(1,039,000)		(1,039,000)
Stock based compensation	15,086,000		15,086,000
Purchase of treasury stock	0
Dividends declared on common stock	(9,564,000)				(9,564,000)
Net income (loss)	(262,895,000)				(262,895,000)
Ending balance at Dec. 31, 2020	714,036,000	85,000	915,877,000	(49,995,000)	(151,931,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares withheld for payment of taxes on equity awards	(1,543,000)		(1,543,000)
Stock based compensation	14,434,000		14,434,000
Issuance of common stock	1,000	1,000
Purchase of treasury stock	(2,441,000)			(2,441,000)
Dividends declared on common stock	(16,297,000)		(16,297,000)
Net income (loss)	(15,542,000)				(15,542,000)
Ending balance at Dec. 31, 2021	692,648,000	86,000	912,471,000	(52,436,000)	(167,473,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares withheld for payment of taxes on equity awards	(4,136,000)		(4,136,000)
Stock based compensation	17,762,000		17,762,000
Purchase of treasury stock	(51,303,000)			(51,303,000)
Dividends declared on common stock	(104,654,000)		(104,654,000)
Net income (loss)	250,168,000				250,168,000
Ending balance at Dec. 31, 2022	$ 800,485,000	$ 86,000	$ 821,443,000	$ (103,739,000)	$ 82,695,000

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

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- Definition

Total of all stockholders' equity (deficit) items, net of receivables from officers, directors, owners, and affiliates of the entity which are attributable to the parent. The amount of the economic entity's stockholders' equity attributable to the parent excludes the amount of stockholders' equity which is allocable to that ownership interest in subsidiary equity which is not attributable to the parent (noncontrolling interest, minority interest). This excludes temporary equity and is sometimes called permanent equity.

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Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Principles of Consolidation and Reporting	Principles of Consolidation and ReportingThe consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”), which requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We eliminated all significant intercompany transactions and balances upon consolidation. For oil and gas E&P joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements.
Segment Reporting	Segment Reporting The Company has two reportable segments. Reportable segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker (“CODM”), our Chief Executive Officer, in deciding how to allocate resources and assess performance. The E&P segment consists of the development and production of onshore, low geologic risk, long-lived conventional oil and gas reserves, primarily located in California, as well as Utah. The well servicing and abandonment segment provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics.
Use of Estimates	Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP required management of the Company to make informed estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. Estimates that are particularly significant to the financial statements include estimates of our reserves of oil and gas; future cash flows from oil and gas properties; depreciation, depletion and amortization; asset retirement obligations; fair values of commodity derivatives; stock-based compensation; fair values of assets acquired and liabilities assumed; and income taxes.
Cash Equivalents	Cash Equivalents We consider all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.
Inventories	Inventories Inventories were included in other current assets. Oil and natural gas inventories were valued at the lower of cost or net realizable value. Materials and supplies were valued at their weighted-average cost and are reviewed periodically for obsolescence.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Proved Properties We account for oil and natural gas properties in accordance with the successful efforts method. Under this method, all acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves. All development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved developed reserves. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in the current period. Gains or losses from the disposal of other properties are recognized in the current period. For assets acquired, we base the capitalized cost on fair value at the acquisition date. We expense expenditures for maintenance and repairs necessary to maintain properties in operating condition, as well as annual lease rentals, as they are incurred. Estimated dismantlement and abandonment costs are capitalized at their estimated net present value and amortized over the remaining lives of the related assets. Interest is capitalized only during the periods in which these assets are brought to their intended use. The amount of capitalized interest was approximately $1 million, $2 million and $1 million in 2022, 2021 and 2020, respectively. We only capitalize the interest on borrowed funds related to our share of costs associated with qualifying capital expenditures. The amount of capitalized exploratory well costs was zero for all periods and the amount of capitalized overhead was approximately $6 million, $7 million and $6 million in 2022, 2021 and 2020, respectively. We evaluate the impairment of our proved oil and natural gas properties and other property and equipment generally on a field-by-field basis or at the lowest level for which cash flows are identifiable, whenever events or changes in circumstance indicate that the carrying value may not be recoverable. We reduce the carrying values of proved properties to fair value when the expected undiscounted future cash flows are less than net book value. We measure the fair values of proved properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount rate. These inputs require significant judgments and estimates by our management at the time of the valuation which can change significantly over time. The underlying commodity prices are embedded in our estimated cash flows and are the product of a process that begins with the relevant forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors our management believes will impact realizable prices. The fair value was estimated using inputs characteristic of a Level 3 fair value measurement. Unproved Properties A portion of the carrying value of our oil and gas properties was attributable to unproved properties. At December 31, 2022 and 2021, the net capitalized costs attributable to unproved properties was approximately $248 million and $292 million, respectively. The unproved amounts were not subject to depreciation, depletion and amortization until they were classified as proved properties and amortized on a unit-of-production basis. We evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, adverse change in regulatory environment, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. Impairment In 2022 and 2021, we did not record any impairment charges for proved and unproved properties. As of March 31, 2020, we performed impairment tests with respect to our proved and unproved oil and gas properties and other property and equipment as a result of significant declines in oil prices during the latter part of the first quarter 2020. We recorded a non-cash pre-tax asset impairment charge of $289 million during the first quarter of 2020 on proved properties in Utah and certain California locations and other property and equipment. We evaluated our proved properties in accordance with accounting guidance and fair value techniques utilizing the period-end forward price curve, as well as assessing projects we determine we would not pursue in the foreseeable future given the current environment. We determined based on plans and exploration and development efforts no impairment was necessary for our unproved property balance in 2020.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, cogeneration facilities, buildings, well servicing and abandonment vehicles and equipment, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost, depreciated using the straight-line method based on expected useful lives ranging from 15 to 39 years for buildings and improvements, 20 to 30 years for cogeneration facilities, natural gas plants and pipelines, 1 to 10 years for furniture and equipment, 1 to 10 years for well servicing and abandonment vehicles and equipment and other equipment, and the salvage value is considered as applicable. Other property and equipment assets are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
Business Combinations	Business Combinations The Company records business combinations using the acquisition method of accounting. Under the acquisition method of accounting, identifiable assets acquired and liabilities assumed are recorded at their acquisition-date fair values. The excess of the purchase price over the estimated fair value, if any, is recorded as goodwill. Changes in the estimated fair values of net assets recorded for acquisitions prior to the finalization of more detailed analysis, but not to exceed one year from the date of acquisition, will adjust the amount of the purchase price allocations accordingly. Measurement period adjustments are reflected in the period in which they occur. We account for acquisitions of businesses using the acquisition method of accounting, which requires the allocation of the purchase price consideration based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. Our estimates and judgments of the fair value of acquired businesses could prove to be inexact, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price consideration to acquired assets and liabilities, which could result in asset impairments, the recording of previously unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets and liabilities is increased during periods of economic uncertainty.
Asset Retirement Obligation	Asset Retirement Obligation We recognize the fair value of asset retirement obligations (“AROs”) in the period in which a determination is made that a legal obligation exists to dismantle an asset and remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts were based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalized the cost by increasing the related property, plant and equipment (“PP&E”) balances. If the estimated future cost of the AROs changes, we record an adjustment to both the ARO and PP&E. Over time, the liability is increased and the capitalized cost is depreciated over the useful life of the asset. Accretion expense is also recognized over time as the discounted liabilities are accreted to their expected settlement value and is included in depreciation, depletion and amortization in the statement of operations.
Revenue Recognition	Revenue RecognitionThe majority of the Company's revenue is from the E&P business, which includes the sale of crude oil, natural gas and NGLs, as well as electricity from its cogeneration plants. The remaining revenue is generated from the well servicing and abandonment business. We account for revenue in accordance with the Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers, using the modified retrospective method. The performance obligations that are unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these are wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation as well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation. We derive revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with the remaining 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 primarily generated from well servicing and abandonment business. The following is a description of our principal activities from which we generate revenue. Revenues are recognized when a customer obtains control of promised goods or services, in an amount that reflects the consideration we expect to receive in exchange for those goods or services. Oil, Natural Gas and NGLs We recognize revenue from the sale of our oil, natural gas and NGL production when delivery has occurred and control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our NGL contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the amount that we expect to receive once we are able to adequately estimate the consideration (i.e., when market prices are known or estimated). Our contracts with customers typically require payment within 30 days following invoicing. Service Revenue We recognize service revenue from the well servicing and abandonment business upon delivery of the service to the customer. These services are consumed by our customers when they are provided on their sites. Revenue is recognized as performance obligations have been completed on a daily basis, when all of the proper customer approvals are obtained. We do not have any long-term service contracts; nor do we have revenue expected to be recognized in any future year related to remaining performance obligations or contracts with variable consideration related to undelivered performance obligations. Our contracts with customers typically require payment within 30-60 days following invoicing. Electricity Sales The electrical output of our cogeneration facilities that is not used in our operations is sold to the California market based on market pricing, which includes capacity payments. The portion sold from our cogeneration facilities is sold under contracts to California utility companies, based on the market pricing. Revenue is recognized over time when obligations under the terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the electricity. Revenue is measured as the amount of consideration we expect to receive based on average index pricing with payment due the month following delivery. Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on seasonality, which is consistent with how we earn the capacity payment. Capacity payments are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the case of capacity payments. We report electricity revenue as electricity sales on our consolidated statements of operations. Marketing Revenue Marketing revenue primarily includes our activities associated with transporting and marketing third-party volumes. These sales are made under the same agreements with the same purchaser as our natural gas sales discussed above. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Revenues are presented excluding costs incurred prior to transferring control of these volumes to the customer, or the costs to purchase these volumes when we are acting as the principal. The revenues and expenses related to the sale and purchase of third-party volumes are presented separately as marketing revenue and marketing expenses on the consolidated statements of operations. In January 2022, we sold our Piceance Colorado operations, which included third-party marketing activities. Historically, these activities accounted for nearly all of our marketing revenues.
Fair Value Measurements	Fair Value Measurements We have categorized our assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level 3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period. We primarily apply the market approach for recurring fair value measurement, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management’s judgments regarding expectations of projected cash flows and discounts those cash flows using a risk-adjusted discount rate. The only item on our balance sheet that would be affected by recurring fair value measurements is derivatives. 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 classify these measurements as Level 2. We use market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When we are required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the income approach is based on management’s best assumptions regarding expectations of future net cash flows. PP&E is written down to fair value if we determine that there has been an impairment in its value. The fair value is determined as of the date of the assessment using discounted cash flow models based on management’s expectations for the future. Inputs include estimates of future production, prices based on commodity forward price curves as of the date of the estimate, estimated future operating and development costs and a risk-adjusted discount rate. However, assumptions used reflect assets highest and best use and a market participant’s view of long-term prices, costs and other factors and are consistent with assumptions used in our business plans and investment decisions. We classify these measurements as Level 3.
Stock-based Compensation	Stock-based Compensation We have issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units (“PSUs”) that include (i) awards with a market objective measured against both absolute total stockholder return (“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR PSUs”) over the performance period and (ii) awards based on the Company's average cash returned on invested capital (“CROIC PSUs” and “ROIC PSUs”) over the performance period. CROIC PSUs are awarded to certain Berry employees, while ROIC PSUs are awarded to certain CJWS employees. The fair value of the stock-based awards is determined at the date of grant and is not remeasured. The fair value of the RSUs, CROIC PSUs and ROIC PSUs was determined using the grant date stock price. The fair value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the peer group over the performance periods. Estimates used in the Monte Carlo valuation model are considered highly complex and subjective. Compensation expense, net of actual forfeitures, for the RSUs and PSUs is recognized on a straight-line basis over the requisite service periods, which is over the awards’ respective vesting or performance periods which range from one to three years.
Other Loss Contingencies	Other Loss Contingencies In the normal course of business, we are involved in lawsuits, claims and other environmental and legal proceedings and audits. We accrue reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, we disclose, if material, in aggregate, our exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. We review our loss contingencies on an ongoing basis. Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors.
Electricity Cost Allocation	Electricity Cost Allocation We own several cogeneration facilities. Our investment in cogeneration facilities has been for the express purpose of lowering steam costs in our heavy oil operations in California and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power, extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. We allocate steam and electricity costs to lease operating expenses based on the conversion efficiency of the cogeneration facilities plus certain direct costs of producing steam. We also allocate a portion of the electricity production costs related to the power we sell to third parties, which is reported in “electricity generation expenses” in the statement of operations.
Income Taxes	Income Taxes Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit).
Earnings per Share	Earnings per Share Basic earnings (loss) per share is calculated as net income (loss) divided by the weighted-average shares of common stock outstanding during the period. Diluted earnings (loss) per share is calculated by dividing net income (loss) by the weighted-average shares of common stock outstanding, including the effect of potentially dilutive securities. For basic earnings per share (“EPS”), the weighted-average number of common stock outstanding excludes outstanding shares related to unvested restricted stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding potentially dilutive securities, unless their effect is anti-dilutive. We did not have any participating securities in the periods presented. We compute basic and diluted EPS using the two-class method required for participating securities. Common stock awards are considered participating securities when such shares have non-forfeitable dividend rights at the same rate as common stock. Our dividend rights are forfeitable, and are not considered participating securities. Under the two-class method, undistributed earnings allocated to participating securities are subtracted from net income attributable to common stock in determining net income attributable to common stockholders. In loss periods, no allocation is made to participating securities because the participating securities do not share in losses.
Business and Credit Concentration	Business and Credit Concentrations We maintain our cash in bank deposit accounts which, at times, may exceed federally insured amounts. We have not experienced any losses in such accounts. We believe we are not exposed to any significant credit risk on our cash. We sell oil, natural gas and NGLs to various types of customers, including pipelines, refineries and other oil and natural gas companies and electricity to utility companies. We also perform well servicing and abandonment for oil and natural gas companies. Based on the current demand for oil, natural gas, NGLs, as well as our well servicing and abandonment services and the availability of other purchasers, we believe that the loss of any one of our major purchasers would not have a material adverse effect on our financial condition, results of operations or net cash provided by operating activities.
Recently Adopted Accounting Standards and New Accounting Standards Issued, But Not Yet Adopted	Recently Adopted Accounting StandardsIn 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 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. The impacts of adoption were immaterial

Derivatives - Gains and Losses of Derivatives Instruments in Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
(Losses) gains on derivatives	$ (48,314)	$ (117,822)	$ 116,746
Oil, natural gas and natural gas liquid sales
Derivative [Line Items]
(Losses) gains on derivatives	(137,109)	(156,399)	117,781
Natural gas sales
Derivative [Line Items]
(Losses) gains on derivatives	$ 88,795	$ 38,577	$ (1,035)

Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Total revenue, excluding assessed tax	$ 1,055,450	$ 701,349	$ 406,052
(Losses) gains on derivatives	(137,109)	(156,399)	117,781
Total revenues and other	918,341	544,950	523,833
Oil sales
Disaggregation of Revenue [Line Items]
Total revenue, excluding assessed tax	806,631	587,613	362,976
Natural gas sales
Disaggregation of Revenue [Line Items]
Total revenue, excluding assessed tax	29,515	32,679	14,041
Natural gas liquids sales
Disaggregation of Revenue [Line Items]
Total revenue, excluding assessed tax	6,303	5,183	1,646
Service revenue
Disaggregation of Revenue [Line Items]
Total revenue, excluding assessed tax	181,400	35,840	0
Electricity sales
Disaggregation of Revenue [Line Items]
Total revenue, excluding assessed tax	30,833	35,636	25,813
Marketing revenues
Disaggregation of Revenue [Line Items]
Total revenue, excluding assessed tax	289	3,921	1,426
Other revenues
Disaggregation of Revenue [Line Items]
Total revenue, excluding assessed tax	$ 479	$ 477	$ 150

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

Schedule of Earnings Per Share


	Year Ended December 31,
	2022		2021		2020
	(in thousands except per share amounts)
Basic EPS calculation
Net income (loss)	$	250,168	$	(15,542)	$	(262,895)
Weighted-average shares of common stock outstanding	78,517		80,209		79,802
Basic income (loss) per share	$	3.19	$	(0.19)	$	(3.29)
Diluted EPS calculation
Net income (loss)	$	250,168	$	(15,542)	$	(262,895)
Weighted-average shares of common stock outstanding	78,517		80,209		79,802
Dilutive effect of potentially dilutive securities(1)	4,069		—		—
Weighted-average common shares outstanding - diluted	82,586		80,209		79,802
Diluted income (loss) per share	$	3.03	$	(0.19)	$	(3.29)

__________(1) We excluded 3.3 million and 0.1 million of combined RSUs and PSUs from the diluted weighted-average common shares outstanding because their effect was anti-dilutive for the years ended December 31, 2021 and 2020, respectively

Basis of Presentation and Significant Accounting Policies - Narrative (Details)	3 Months Ended		9 Months Ended	12 Months Ended			15 Months Ended
	Dec. 31, 2021 USD ($) business	Mar. 31, 2020 USD ($)	Sep. 30, 2022 business	Dec. 31, 2022 USD ($) segment	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2022 USD ($) segment
Public Utilities, General Disclosures [Line Items]
Number of reportable segments \| segment				2
Business segments	2		1				2
Capitalized interest				$ 1,000,000	$ 2,000,000	$ 1,000,000
Capitalized exploratory well costs	$ 0			0	0	0	$ 0
Capitalized overhead	7,000,000			6,000,000	7,000,000	6,000,000	6,000,000
Net capitalized costs attributable to unproved properties	292,000,000			248,000,000	292,000,000		248,000,000
Impairment of oil and gas properties				0	0	$ 289,085,000
Asset retirement obligation, noncurrent	$ 143,926,000			$ 158,491,000	$ 143,926,000		$ 158,491,000
Largest customers \| Sales \| Customer one \| E&P
Public Utilities, General Disclosures [Line Items]
Concentration risk				33.00%	30.00%	44.00%
Largest customers \| Sales \| Customer two \| E&P
Public Utilities, General Disclosures [Line Items]
Concentration risk				16.00%	16.00%	20.00%
Largest customers \| Sales \| Customer three \| E&P
Public Utilities, General Disclosures [Line Items]
Concentration risk				10.00%	14.00%	12.00%
Largest customers \| Sales \| Customer four \| E&P
Public Utilities, General Disclosures [Line Items]
Concentration risk					12.00%
Largest customers \| Trade accounts receivable \| Customer one
Public Utilities, General Disclosures [Line Items]
Concentration risk				33.00%	28.00%
Largest customers \| Trade accounts receivable \| Customer two
Public Utilities, General Disclosures [Line Items]
Concentration risk				16.00%	13.00%
Largest customers \| Trade accounts receivable \| Customer three
Public Utilities, General Disclosures [Line Items]
Concentration risk				13.00%	11.00%
Buildings and leasehold improvements \| Minimum
Public Utilities, General Disclosures [Line Items]
Expected useful life				15 years
Buildings and leasehold improvements \| Maximum
Public Utilities, General Disclosures [Line Items]
Expected useful life				39 years
Plant and pipeline \| Minimum
Public Utilities, General Disclosures [Line Items]
Expected useful life				20 years
Plant and pipeline \| Maximum
Public Utilities, General Disclosures [Line Items]
Expected useful life				30 years
Furniture and office equipment \| Minimum
Public Utilities, General Disclosures [Line Items]
Expected useful life				1 year
Furniture and office equipment \| Maximum
Public Utilities, General Disclosures [Line Items]
Expected useful life				10 years
Vehicles \| Minimum
Public Utilities, General Disclosures [Line Items]
Expected useful life				1 year
Vehicles \| Maximum
Public Utilities, General Disclosures [Line Items]
Expected useful life				10 years
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs) \| Minimum
Public Utilities, General Disclosures [Line Items]
Vesting period				1 year
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs) \| Maximum
Public Utilities, General Disclosures [Line Items]
Vesting period				3 years
Unproved Oil and Gas Properties
Public Utilities, General Disclosures [Line Items]
Impairment of oil and gas properties						$ 0
Proved Oil and Gas Properties
Public Utilities, General Disclosures [Line Items]
Impairment of oil and gas properties		$ 289,000,000

Oil and Natural Gas Properties and Other Property and Equipment - Aggregate Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Proved properties	$ 1,477,791	$ 1,246,380
Unproved properties	248,073	291,514
Oil and natural gas properties	1,725,864	1,537,894
Less accumulated depletion and amortization	(465,889)	(340,328)
Total oil and natural gas properties, net	$ 1,259,975	$ 1,197,566

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Acquisitions and Divestitures

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.

Purchases of Various Oil and Gas Properties

During 2022, we also acquired various oil and gas properties, most of which consisted of unproved properties for approximately $8 million in aggregate.

2021

C&J Well Services Acquisition

On October 1, 2021, we acquired one of the largest well servicing and abandonment businesses in California, which operates as CJWS. The purchase price was $53 million, including closing adjustments mainly related to

working capital, which we funded with cash on hand of $51 million in 2021 and $2 million in 2022. The CJWS transaction costs were approximately $3 million. The acquired business activities are owned and operated by C&J Well Services, a wholly-owned subsidiary of Berry Corp. formed for the purposes of acquiring these businesses and establishing an independent well services and abandonment company.

The CJWS transaction was accounted for as a business combination under the acquisition method of accounting. When determining the fair values of assets acquired and liabilities assumed, management made significant estimates, judgments and assumptions. The assets acquired and liabilities assumed are included in the well servicing and abandonment segment.

The unaudited pro forma information presented below has been prepared to give effect to the CJWS acquisition as if it had occurred at the beginning of the periods presented. The unaudited pro forma information includes the effects from the allocation of the acquisition purchase price on depreciation and amortization as well as the CJWS acquisition costs charged to earnings during the 2021 period. The unaudited pro forma information is presented for illustration purposes only and is based on estimates and assumptions the Company deemed appropriate. The following unaudited pro forma information is not necessarily indicative of the results that would have been achieved if the CJWS acquisition had occurred in the past, and should not be relied upon as an indication of the operating results that the Company would have achieved if the acquisition had occurred at the beginning of the periods presented, and our operating results, or the future results.


	Pro Forma
	Year Ended December 31,
	2021		2020
	(unaudited) (in thousands)
Revenue	$	664,549	$	657,796
Net income (loss)	$	740	$	(250,884)

Placerita Divestiture

In October 2021, our E&P segment completed the sale of our Placerita Field property in the Ventura Basin in Los Angeles County, California for approximately $14 million. We recorded a gain on the sale of approximately $2 million in 2021.

2020

In May 2020, we acquired approximately 740 net acres in the North Midway Sunset Field for approximately $5 million. We paid $2 million at closing and the remaining $3 million was paid following our first production from this property, in the fourth quarter 2020. This property is adjacent to, and extends, our existing producing area and we have identified numerous future drilling locations. We believe additional opportunities exist in other productive reservoirs of this property. We also acquired all existing idle wells on this property, some of which we plan to return to production in the near future as price and strategy dictate. We will plug and abandon the remaining idle wells pursuant to our California idle well management plan. We recorded a $6 million liability for asset retirement obligations of the existing wells on this property.

We also acquired approximately 267 acres in McKittrick Field which will allow us to continue development of the 21Z mineral fee and leases without requiring written approval from a third party surface fee owner for infrastructure on or across the surface fee property. The purchase price was not material.

Oil and Natural Gas Properties and Other Property and Equipment

12 Months Ended

Dec. 31, 2022

Extractive Industries [Abstract]

Oil and Natural Gas Properties and Other Property and Equipment

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:


	Year Ended December 31,
	2022		2021
	(in thousands)
Proved properties	$	1,477,791	$	1,246,380
Unproved properties	248,073		291,514
Total proved and unproved properties	1,725,864		1,537,894
Less accumulated depletion and amortization	(465,889)		(340,328)
Total proved and unproved properties, net	$	1,259,975	$	1,197,566

Other Property and Equipment

Other property and equipment consisted of the following:


	Year Ended December 31,
	2022		2021
	(in thousands)
Cogeneration facilities, natural gas plants and pipelines	$	58,357	$	54,237
Vehicles and service equipment(1)	65,195		55,521
Furniture and equipment	23,779		22,665
Land	6,102		6,101
Buildings and leasehold improvements	2,186		2,186
Total other property and equipment	155,619		140,710
Less: accumulated depreciation	(55,781)		(36,927)
Total other property and equipment, net	$	99,838	$	103,783

__________

(1) Includes CJWS vehicles and service equipment.

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows

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


	Year Ended December 31,
	2022		2021
	(in thousands)
Prepaid expenses	$	12,330	$	26,840

Materials and supplies	8,976		9,533
Prepaid deposits	7,266		6,415
Oil inventories	4,036		2,933
Other	1,117		225
Total other current assets	$	33,725	$	45,946

Other non-current assets at December 31, 2022 included approximately $6 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 consolidated balance sheets included the following:


	Year Ended December 31,
	2022		2021
	(in thousands)
Accounts payable - trade	$	40,286	$	17,699
Accrued expenses	85,360		62,962
Royalties payable	38,264		24,816

Greenhouse gas liability - current portion	—		7,513
Taxes other than income tax liability	6,640		8,273
Accrued interest	10,885		10,736
Dividends payable	—		4,800
Asset retirement obligation - current portion	20,000		20,000
Operating lease liability	1,666		—
Other	—		725
Total accounts payable and accrued expenses	$	203,101	$	157,524

At December 31, 2022 other non-current liabilities included approximately $23 million non-current greenhouse gas liability, which is due 2024, and $5 million of non-current operating lease liability. At December 31, 2021 we had $18 million non-current greenhouse gas liability, which is due in 2024.

Supplemental Information on the Statement of Operations

For the years ended December 31, 2022, 2021, and 2020 other operating expenses were $4 million, $3 million, and $6 million respectively. For the year ended December 31, 2022, other operating expenses mainly consisted of approximately $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 year ended December 31, 2021, other operating expenses mainly consisted of expensing $3 million of unamortized debt issuance costs related to the 2017 RBL facility, approximately $3 million of supplemental property tax assessments, royalty audit charges and tank rental costs, and $2 million of various other costs such as excess abandonment costs and legal fees, partially

offset by approximately $2 million on gain on the sale of properties and over $2 million of income from employee retention credits. For the year ended December 31, 2020, other operating expenses included of $3 million of excess abandonment costs, $2 million of oil tank storage fees, and $1 million of drilling rig standby charges.

Supplemental Cash Flow Information

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


	Year Ended December 31,
	2022		2021		2020
	(in thousands)
Supplemental Disclosures of Significant Non-Cash Operating Activities:
Greenhouse gas liability - reclassification from current liability to long-term	$	8,000	$	—	$	—
Greenhouse gas liability - reclassification from long-term to current liability	$	—	$	—	$	33,376
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties	$	2,707	$	3,424	$	1,596
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	$	29,792	$	29,211	$	29,962
Income taxes payments	$	3,633	$	699	$	222

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Narrative (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Jan. 31, 2022	Oct. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reclassification [Line Items]
Operating lease assets			$ 6,325
Deferred financing costs, non-current, net of amortization			4,000	$ 5,000
Greenhouse gas liability, noncurrent			23,000	18,000
Operating lease noncurrent liability			5,213
Other operating expense (income)			3,722	3,101	$ 5,781
Supplemental property tax assessment			$ 2,000	3,000
Gain on sale				2,000
Income from employee retention credits				2,000
Other expenses				2,000
Excess abandonment costs					3,000
Oil tank storage fees					2,000
Drilling rig standby charges					$ 1,000
Placerita Field
Reclassification [Line Items]
Gain on sale		$ 2,000
Piceance Basin
Reclassification [Line Items]
Gain (loss) on disposition of oil and gas property	$ 2,000			2,000
Revolving credit facility \| 2017 RBL Facility \| Line of credit
Reclassification [Line Items]
Unamortized debt issuance costs				$ 3,000

Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2022

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

As a result of adoption of this standard, we are now required to disclose the following information regarding revenue from contracts with customers on a disaggregated basis.


	Year Ended December 31,
	2022		2021		2020
	(in thousands)
Oil sales	$	806,631	$	587,613	$	362,976
Natural gas sales	29,515		32,679		14,041
Natural gas liquids sales	6,303		5,183		1,646
Service revenue	181,400		35,840		—

Electricity sales	30,833		35,636		25,813
Marketing revenues	289		3,921		1,426
Other revenues	479		477		150
Revenues from contracts with customers	1,055,450		701,349		406,052
(Losses) gains on oil and gas sales derivatives	(137,109)		(156,399)		117,781
Total revenues and other	$	918,341	$	544,950	$	523,833

Leases (Tables)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Components of Lease Expense

The components of lease expense are as follows:


	Year Ended December 31, 2022
	(in thousands)
Lease Cost
Operating lease cost	$	1,992

Total net lease cost	$	1,992

Balance Sheet Information Related to Leases

The following table presents the consolidated balance sheet information related to leases as of December 31, 2022.


	As of December 31, 2022		Balance Sheet Classification
	(in thousands)
Leases
Assets

Operating lease assets	$	6,325	Other noncurrent assets

Total assets	$	6,325

Liabilities
Operating lease liability	$	1,666	Accounts payable and accrued expenses
Operating lease noncurrent liability	5,213		Other noncurrent liabilities

Total liabilities	$	6,879


	As of December 31, 2022
Long-Term and Discount Rate
Weighted-average remaining lease term:

Operating Lease	4.3 years
Weighted-average discount rate:

Operating Lease	5	%

Schedule of Maturity

The following table presents a schedule of future minimum lease payments required under all operating lease agreements as of December 31, 2022.


	As of December 31, 2022
	Operating Leases
	(in thousands)
2023	$	1,963
2024	1,650
2025	1,542
2026	1,549
2027	935

Total lease payments	7,639
Less imputed interest	(760)
Total lease obligations	6,879
Less current obligations	(1,666)
Long-term lease obligations	$	5,213

Cash Flow Information Related to Leases

Supplemental consolidated statement of cash flow information related to leases is as follows:


	Year Ended December 31, 2022
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities

Operating cash flows from operating leases	$	2,128


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

Leases - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Assets
Operating lease assets	$ 6,325
Total assets	$ 6,325
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent
Liabilities
Operating lease liability	$ 1,666	$ 0
Operating lease noncurrent liability	5,213
Total liabilities	$ 6,879
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accounts Payable and Accrued Liabilities, Current
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent
Weighted average remaining lease term (in years)	4 years 3 months 18 days
Weighted average discount rate	5.00%

Leases - Maturity Schedule (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
2023	$ 1,963
2024	1,650
2025	1,542
2026	1,549
2027	935
Total lease payments	7,639
Less imputed interest	(760)
Total liabilities	6,879
Less current obligations	(1,666)	$ 0
Operating lease noncurrent liability	$ 5,213

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income tax expense (benefit) consisted of the following:


	Year Ended December 31,
	2022		2021		2020
	(in thousands)
Current taxes:
Federal	$	642	$	—	$	—
State	1,597		581		828
Total current taxes	2,239		581		828
Deferred taxes:
Federal	(44,053)		832		2,653
State	(622)		—		(10,699)
Total deferred taxes	(44,675)		832		(8,046)
Total current and deferred taxes	$	(42,436)	$	1,413	$	(7,218)

Reconciliation of the Federal Statutory Tax Rate to the Effective Tax Rate

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:


	Year Ended December 31,
	2022		2021		2020
Federal statutory rate	21.0	%	21.0	%	21.0	%
State, net of federal tax benefit	6.2	%	3.7	%	6.3	%
Nondeductible compensation	1.8	%	(24.5)	%	—	%
Effect of permanent differences	(0.3)	%	(4.7)	%	(0.6)	%
Tax credits - Prior Year	(11.5)	%	(29.5)	%	4.9	%
Tax credits - Current Year	—	%	21.5	%	1.1	%
State return to provision	(0.3)	%	(0.2)	%	(1.1)	%

Change in valuation allowance	(37.3)	%	2.7	%	(28.8)	%
Effective tax rate	(20.4)	%	(10.0)	%	2.8	%

Schedule of Significant Components of Deferred Tax Assets and Liabilities

Significant components of the deferred tax assets and liabilities are as follows:


	Year Ended December 31,
	2022		2021
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	22,402	$	40,846
Accruals	10,728		11,731
Asset retirement obligations	48,994		44,437
Derivative instruments	2,280		12,776
Tax credits	88,908		61,044

Other	2,882		3,551
Subtotal	176,194		174,385
Valuation allowance	—		(77,546)
Total deferred tax assets	176,194		96,839
Deferred tax liabilities:
Book tax differences in property basis	(133,350)		(98,670)

Total deferred tax liabilities	(133,350)		(98,670)
Net deferred tax asset (liability)	$	42,844	$	(1,831)

Defined Contribution Plan (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended			18 Months Ended
Defined Contribution Plan (Details) - USD ($) $ in Millions	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2022
Retirement Benefits [Abstract]
Defined contribution plan, matching contribution, percentage of employee's gross pay (up to)	3.00%	6.00%				6.00%
Defined contribution plan, matching contribution percentage	100.00%					100.00%
Defined contribution plan, cost			$ 6.2	$ 1.6	$ 1.0

Derivatives

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

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

For fixed-price oil and gas sales swaps, we are the seller, so we make settlement payments for prices above the indicated weighted-average price per barrel and per mmbtu, respectively, and receive settlement payments for prices below the indicated weighted-average price per barrel 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.

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

For some of our options we paid or received a premium at the time the positions were created and for others, the premium payment or receipt is deferred until the time of settlement. As of December 31, 2022 we have net payable deferred premiums of approximately $5 million, which is reflected in the mark-to-market valuation and will be payable through December 31, 2024.

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


	Q1 2023		Q2 2023		Q3 2023		Q4 2023		FY 2024		FY 2025
Brent - Crude Oil Production
Swaps
Hedged volume (bbls)	1,385,278		1,387,750		1,211,717		1,196,000		3,392,048		—
Weighted-average price ($/bbl)	$	77.15	$	77.01	$	76.26	$	76.18	$	76.12	$	—

Put Spreads
Long $50/$40 Put Spread hedged volume (bbls)	630,000		637,000		644,000		644,000		1,647,000		—
Short $50/$40 Put Spread hedged volume (bbls)	90,000		91,000		92,000		92,000		366,000		—
Producer Collars
Hedged volume (bbls)	360,000		364,000		368,000		368,000		1,098,000		2,212,500
Weighted-average price ($/bbl)	$40.00/$106.00		$40.00/$106.00		$40.00/$106.00		$40.00/$106.00		$40.00/$105.00		$58.35/$91.45
Henry Hub - Natural Gas Purchases
Consumer Collars
Hedged volume (mmbtu)	2,110,000		1,820,000		—		—		—		—
Weighted-average price ($/mmbtu)	$4.00/$2.75		$4.00/$2.75		$	—	$	—	$	—	$	—
NWPL - Natural Gas Purchases
Hedged volume (mmbtu)	1,800,000		3,640,000		3,680,000		3,680,000		7,320,000		6,080,000
Weighted-average price ($/mmbtu)	$	6.40	$	5.34	$	5.34	$	5.34	$	4.27	$	4.27
Gas Basis Differentials
NWPL/HH - basis swaps
Hedged volume (mmbtu)	1,800,000		1,820,000		1,840,000		1,840,000		—		—
Weighted-average price ($/mmbtu)	$	1.12	$	1.12	$	1.12	$	1.12	$	—	$	—

In addition to the table above, in January 2023, we terminated the following basis swaps (NWPL/HH): 4,900,000 mmbtu (20,000 mmbtu/d) at $1.12 beginning March 2023 through October 2023, and 610,000 mmbtu (10,000 mmbtu/d) at $1.12 beginning November 2023 through December 2023.

In January 2023 we also added the following Producer Collars (Brent): 3,627 bbl (117 bbl/d) at $60.00/$88.50 for January 2025, 270,000 bbl (3,000 bbl/d) at $60.00/$88.35 for January 2025 through March of 2025, and 472,500 bbl (5,250 bbl/d) at $60.00/$82.21 for January 2026 through March of 2026, which are in addition to the table above. These Producer Collars (Brent) were cashless.

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 December 31, 2022 and 2021. The following tables present the fair values (gross and net) of our outstanding derivatives as of December 31, 2022 and 2021.


	December 31, 2022
	Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
	(in thousands)
Assets:
Commodity Contracts	Current assets	$	66,974	$	(30,607)	$	36,367
Commodity Contracts	Non-current assets	39,886		(39,810)		76
Liabilities:
Commodity Contracts	Current liabilities	(61,713)		30,607		(31,106)
Commodity Contracts	Non-current liabilities	(53,452)		39,810		(13,642)
Total derivatives		$	(8,305)	$	—	$	(8,305)


	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.

(Losses) Gains on Derivatives

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


	Year Ended December 31,
	2022		2021		2020
	(in thousands)
(Losses) gains on oil and gas sales derivatives	$	(137,109)	$	(156,399)	$	117,781
Gains (losses) on natural gas purchase derivatives	88,795		38,577		(1,035)

Total (losses) gains on derivatives	$	(48,314)	$	(117,822)	$	116,746

For the years ended December 31, 2022 and 2021 we paid net cash settlements of approximately $88 million and $92 million, respectively. For the year ended December 31, 2020, we received net cash scheduled settlements of approximately $142 million.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Stockholders' Equity [Abstract]
Common stock, dividends declared (in dollars per share)	$ 1.34	$ 0.20	$ 0.12

Basis of Presentation and Significant Accounting Policies - Asset Retirement Obligation (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	May 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 163,925	$ 160,192
Liabilities incurred including from acquisitions	$ 6,000	3,028	1,350
Settlements and payments		(19,558)	(17,900)
Accretion expense		10,848	10,936
Reduction due to property sales		(1,210)	(22,199)
Revisions		21,458	31,546
Ending balance		$ 178,491	$ 163,925

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 46,250	$ 15,283
Accounts receivable, net of allowance for doubtful accounts of $866 at December 31, 2022 and December 31, 2021	101,713	86,269
Derivative instruments	36,367	0
Other current assets	33,725	45,946
Total current assets	218,055	147,498
Noncurrent assets:
Oil and natural gas properties	1,725,864	1,537,894
Accumulated depletion and amortization	(465,889)	(340,328)
Total oil and natural gas properties, net	1,259,975	1,197,566
Other property and equipment	155,619	140,710
Accumulated depreciation	(55,781)	(36,927)
Total other property and equipment, net	99,838	103,783
Deferred income taxes	42,844	0
Derivative instruments	76	1,070
Other noncurrent assets	10,242	6,562
Total assets	1,631,030	1,456,479
Current liabilities:
Accounts payable and accrued expenses	203,101	157,524
Derivative instruments	31,106	29,625
Total current liabilities	234,207	187,149
Noncurrent liabilities:
Long-term debt	395,735	394,566
Derivative instruments	13,642	18,577
Deferred income taxes	0	1,831
Asset retirement obligation	158,491	143,926
Other noncurrent liabilities	28,470	17,782
Commitments and Contingencies - Note 5
Stockholders' Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 86,350,771 and 85,590,417 shares issued; and 75,767,503 and 80,007,149 shares outstanding, at December 31, 2022 and December 31, 2021, respectively)	86	86
Additional paid-in capital	821,443	912,471
Treasury stock, at cost (10,583,268 shares at December 31, 2022 and 5,583,268 shares at December 31, 2021)	(103,739)	(52,436)
Retained earnings (accumulated deficit)	82,695	(167,473)
Total stockholders' equity	800,485	692,648
Total liabilities and stockholders' equity	$ 1,631,030	$ 1,456,479

Leases

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Leases

In the first quarter of 2022, we adopted ASC 842, Leases 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:


	Year Ended December 31, 2022
	(in thousands)
Lease Cost
Operating lease cost	$	1,992

Total net lease cost	$	1,992

The following table presents the consolidated balance sheet information related to leases as of December 31, 2022.


	As of December 31, 2022		Balance Sheet Classification
	(in thousands)
Leases
Assets

Operating lease assets	$	6,325	Other noncurrent assets

Total assets	$	6,325

Liabilities
Operating lease liability	$	1,666	Accounts payable and accrued expenses
Operating lease noncurrent liability	5,213		Other noncurrent liabilities

Total liabilities	$	6,879


	As of December 31, 2022
Long-Term and Discount Rate
Weighted-average remaining lease term:

Operating Lease	4.3 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 December 31, 2022.


	As of December 31, 2022
	Operating Leases
	(in thousands)
2023	$	1,963
2024	1,650
2025	1,542
2026	1,549
2027	935

Total lease payments	7,639
Less imputed interest	(760)
Total lease obligations	6,879
Less current obligations	(1,666)
Long-term lease obligations	$	5,213

Supplemental consolidated statement of cash flow information related to leases is as follows:


	Year Ended December 31, 2022
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities

Operating cash flows from operating leases	$	2,128


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

Debt - Narrative (Details)			1 Months Ended			12 Months Ended
Debt - Narrative (Details)	Aug. 09, 2022 USD ($)	Aug. 26, 2021 USD ($)	Nov. 30, 2022 USD ($)	May 31, 2022 USD ($)	Feb. 28, 2018 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Feb. 29, 2020 USD ($)	Jul. 31, 2017 USD ($)
Debt Instrument [Line Items]
Debt issuance costs for the 2026 Senior Unsecured Notes						$ 4,265,000	$ 5,434,000
Amortization of debt issuance costs						2,590,000	4,430,000	$ 5,351,000
Net income (loss)						250,168,000	(15,542,000)	(262,895,000)
Bond repurchase program, authorized amount									$ 75,000,000
C&J Well Services
Debt Instrument [Line Items]
Net income (loss)						15,000,000
Interest expense
Debt Instrument [Line Items]
Amortization of debt issuance costs						2,000,000	4,000,000	$ 5,000,000
2026 Notes \| Unsecured debt
Debt Instrument [Line Items]
Fair value of debt						$ 369,000,000	400,000,000
Principal amount of debt issued					$ 400,000,000
Interest Rate					7.00%	7.00%
Issuance of 2026 Senior Unsecured Notes					$ 391,000,000
Redemption price in event of change in control					101.00%
Revolving credit facility \| RBL Facility \| Line of credit
Debt Instrument [Line Items]
Credit facility, issuance costs, net of amortization						$ 4,000,000	5,000,000
Revolving credit facility \| 2017 RBL Facility \| Line of credit
Debt Instrument [Line Items]
Unamortized debt issuance costs							3,000,000
Maximum borrowing capacity										$ 1,500,000,000
Borrowing base elected		$ 200,000,000
Borrowings outstanding		0
Revolving credit facility \| 2021 RBL Facility
Debt Instrument [Line Items]
Initial borrowing base, aggregate amount				$ 200,000,000
Revolving credit facility \| 2021 RBL Facility \| Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Debt Instrument [Line Items]
Applicable margin				0.10%
Revolving credit facility \| 2021 RBL Facility \| Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate \| Minimum
Debt Instrument [Line Items]
Applicable margin				0.50%
Revolving credit facility \| 2021 RBL Facility \| Line of credit
Debt Instrument [Line Items]
Professional fees							4,000,000
Maximum borrowing capacity		500,000,000
Borrowing base elected		$ 200,000,000	$ 250,000,000	$ 250,000,000			$ 200,000,000
Commitment fee amount			$ 200,000,000
Maximum borrowing capacity exceed, remediation period (within)		30 days
Maximum borrowing capacity exceed, cure deficiency period (within)		6 months
Consolidated cash balance trigger to prepay borrowing		$ 20,000,000
Commitment fee		0.50%
Leverage ratio (no more than)		3.0
Current ratio (at least)		1.0
Current ratio at period end						1.7
Reduction in borrowing base if unsecured indebtedness is incurred		25.00%
Minimum availability of borrowing base required which will permit repurchase of equity and indebtedness		20.00%
Maximum pro forma leverage ratio allowable which will permit repurchase of equity and indebtedness		2.0
Repurchase of equity and debt, percentage of maximum remaining borrowing capacity		75.00%
Repurchase of restricted payments of equity and debt		1.5
Free cash flow percentage		100.00%
Letters of credit outstanding						$ 7,000,000
Available borrowing capacity						$ 193,000,000
Revolving credit facility \| 2021 RBL Facility \| Line of credit \| Base Rate \| Minimum
Debt Instrument [Line Items]
Applicable margin		2.00%
Revolving credit facility \| 2021 RBL Facility \| Line of credit \| Base Rate \| Maximum
Debt Instrument [Line Items]
Applicable margin		3.00%
Revolving credit facility \| 2021 RBL Facility \| Line of credit \| Benchmark Rate \| Minimum
Debt Instrument [Line Items]
Applicable margin						3.00%
Revolving credit facility \| 2021 RBL Facility \| Line of credit \| Benchmark Rate \| Maximum
Debt Instrument [Line Items]
Applicable margin						4.00%
Revolving credit facility \| 2022 ABL Facility \| Line of credit
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 15,000,000
Percentage of borrowing capacity, line of credit facility	0.80
Borrowings outstanding						$ 0
Letters of credit outstanding						2,000,000
Available borrowing capacity						$ 13,000,000
Revolving credit facility \| 2022 ABL Facility \| Line of credit \| C&J Well Services
Debt Instrument [Line Items]
Maximum ratio of total liabilities to total net worth	1.5					0.2
Maximum percentage of revolving advances outstanding	0.90
Maximum net income before taxes	$ 1.00
Advances outstanding						$ 0
Revolving credit facility \| 2022 ABL Facility \| Line of credit \| Prime Rate
Debt Instrument [Line Items]
Basis spread on variable rate, with derivatives	1.25%
Letter of credit \| 2021 RBL Facility \| Line of credit
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 20,000,000
Letter of credit \| 2022 ABL Facility \| Line of credit
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 7,500,000
Line of credit \| RBL Facility
Debt Instrument [Line Items]
Leverage ratio at period end						1.2

Basis of Presentation and Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation and Significant Accounting Policies

“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 Management and C&J.

Nature of Business

We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional reserves in the San Joaquin basin of California (100% oil) and the Uinta basin of Utah (oil and gas), with well servicing and abandonment capabilities in California. Since October 1, 2021, we have operated in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment.

Principles of Consolidation and Reporting

The consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”), which requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We eliminated all significant intercompany transactions and balances upon consolidation. For oil and gas E&P joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements.

Segment Reporting

The Company has two reportable segments. Reportable segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker (“CODM”), our Chief Executive Officer, in deciding how to allocate resources and assess performance.

The E&P segment consists of the development and production of onshore, low geologic risk, long-lived conventional oil and gas reserves, primarily located in California, as well as Utah.

The well servicing and abandonment segment provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics.

Use of Estimates

The preparation of the accompanying consolidated financial statements in conformity with GAAP required management of the Company to make informed estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.

Estimates that are particularly significant to the financial statements include estimates of our reserves of oil and gas; future cash flows from oil and gas properties; depreciation, depletion and amortization; asset retirement obligations; fair values of commodity derivatives; stock-based compensation; fair values of assets acquired and liabilities assumed; and income taxes.

Cash Equivalents

We consider all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.

Inventories

Inventories were included in other current assets. Oil and natural gas inventories were valued at the lower of cost or net realizable value. Materials and supplies were valued at their weighted-average cost and are reviewed periodically for obsolescence.

Oil and Natural Gas Properties

Proved Properties

We account for oil and natural gas properties in accordance with the successful efforts method. Under this method, all acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves. All development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved developed reserves. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in the current period. Gains or losses from the disposal of other properties are recognized in the current period. For assets acquired, we base the capitalized cost on fair value at the acquisition date. We expense expenditures for maintenance and repairs necessary to maintain properties in operating condition, as well as annual lease rentals, as they are incurred. Estimated dismantlement and abandonment costs are capitalized at their estimated net present value and amortized over the remaining lives of the related assets. Interest is capitalized only during the periods in which these assets are brought to their intended use. The amount of capitalized interest was approximately $1 million, $2 million and $1 million in 2022, 2021 and 2020, respectively. We only capitalize the interest on borrowed funds related to our share of costs associated with qualifying capital expenditures. The amount of capitalized exploratory well costs was zero for all periods and the amount of capitalized overhead was approximately $6 million, $7 million and $6 million in 2022, 2021 and 2020, respectively.

We evaluate the impairment of our proved oil and natural gas properties and other property and equipment generally on a field-by-field basis or at the lowest level for which cash flows are identifiable, whenever events or changes in circumstance indicate that the carrying value may not be recoverable. We reduce the carrying values of proved properties to fair value when the expected undiscounted future cash flows are less than net book value. We measure the fair values of proved properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount rate. These inputs require significant judgments and estimates by our management at the time of the valuation which can change significantly over time. The underlying commodity prices are embedded in our estimated cash flows and are the product of a process that begins with the relevant forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors our management believes will impact realizable prices. The fair value was estimated using inputs characteristic of a Level 3 fair value measurement.

Unproved Properties

A portion of the carrying value of our oil and gas properties was attributable to unproved properties. At December 31, 2022 and 2021, the net capitalized costs attributable to unproved properties was approximately $248 million and $292 million, respectively. The unproved amounts were not subject to depreciation, depletion and amortization until they were classified as proved properties and amortized on a unit-of-production basis.

We evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, adverse change in regulatory environment, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results.

Impairment

In 2022 and 2021, we did not record any impairment charges for proved and unproved properties.

As of March 31, 2020, we performed impairment tests with respect to our proved and unproved oil and gas properties and other property and equipment as a result of significant declines in oil prices during the latter part of the first quarter 2020. We recorded a non-cash pre-tax asset impairment charge of $289 million during the first quarter of 2020 on proved properties in Utah and certain California locations and other property and equipment. We evaluated our proved properties in accordance with accounting guidance and fair value techniques utilizing the period-end forward price curve, as well as assessing projects we determine we would not pursue in the foreseeable future given the current environment. We determined based on plans and exploration and development efforts no impairment was necessary for our unproved property balance in 2020.

Other Property and Equipment

Other property and equipment includes natural gas gathering systems, pipelines, cogeneration facilities, buildings, well servicing and abandonment vehicles and equipment, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost, depreciated using the straight-line method based on expected useful lives ranging from 15 to 39 years for buildings and improvements, 20 to 30 years for cogeneration facilities, natural gas plants and pipelines, 1 to 10 years for furniture and equipment, 1 to 10 years for well servicing and abandonment vehicles and equipment and other equipment, and the salvage value is considered as applicable. Other property and equipment assets are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

Business Combinations

The Company records business combinations using the acquisition method of accounting. Under the acquisition method of accounting, identifiable assets acquired and liabilities assumed are recorded at their acquisition-date fair values. The excess of the purchase price over the estimated fair value, if any, is recorded as goodwill. Changes in the estimated fair values of net assets recorded for acquisitions prior to the finalization of more detailed analysis, but not to exceed one year from the date of acquisition, will adjust the amount of the purchase price allocations accordingly. Measurement period adjustments are reflected in the period in which they occur.

We account for acquisitions of businesses using the acquisition method of accounting, which requires the allocation of the purchase price consideration based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. Our estimates and judgments of the fair value of acquired businesses could prove to be inexact, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price consideration to acquired assets and liabilities, which could result in asset impairments, the recording of previously unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets and liabilities is increased during periods of economic uncertainty.

Asset Retirement Obligation

We recognize the fair value of asset retirement obligations (“AROs”) in the period in which a determination is made that a legal obligation exists to dismantle an asset and remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts were based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalized the cost by increasing the related property, plant and equipment (“PP&E”) balances. If the estimated future cost of the AROs changes, we record an adjustment to both the ARO and PP&E. Over time, the liability is increased and the capitalized cost is depreciated over the useful life of the asset. Accretion expense is also recognized over time as the discounted liabilities are accreted to their expected settlement value and is included in depreciation, depletion and amortization in the statement of operations.

The following table summarizes activity in our ARO account in which approximately $158 million and $144 million were included in long term liabilities as of December 31, 2022 and December 31, 2021, respectively, with the remaining current portion included in accrued liabilities:


	Year Ended December 31,
	2022		2021
	(in thousands)
Beginning balance	$	163,925	$	160,192
Liabilities incurred including from acquisitions	3,028		1,350
Settlements and payments	(19,558)		(17,900)

Accretion expense	10,848		10,936
Reduction due to property sales	(1,210)		(22,199)
Revisions	21,458		31,546

Ending balance	$	178,491	$	163,925

Revenue Recognition

The majority of the Company's revenue is from the E&P business, which includes the sale of crude oil, natural gas and NGLs, as well as electricity from its cogeneration plants. The remaining revenue is generated from the well servicing and abandonment business. See Note 12 for information regarding the Company’s revenue recognition policy.

Fair Value Measurements

We have categorized our assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level 3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period. We primarily apply the market approach for recurring fair value measurement, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management’s judgments regarding expectations of projected cash flows and discounts those cash flows using a risk-adjusted discount rate.

The only item on our balance sheet that would be affected by recurring fair value measurements is derivatives. 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 classify these measurements as Level 2.

We use market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When we are required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the income approach is based on management’s best assumptions regarding expectations of future net cash flows. PP&E is written down to fair value if we determine that there has been an impairment in its value. The fair value is determined as of the date of the assessment using discounted cash flow models based on management’s expectations for the future. Inputs include estimates of future production, prices based on commodity forward price curves as of the date of the estimate, estimated future operating and development costs and a risk-adjusted discount rate. However, assumptions used reflect assets highest and best use and a market participant’s view of long-term prices, costs and other factors and are consistent with assumptions used in our business plans and investment decisions. We classify these measurements as Level 3.

Stock-based Compensation

We have issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units (“PSUs”) that include (i) awards with a market objective measured against both absolute total stockholder return (“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR PSUs”) over the performance period and (ii) awards based on the Company's average cash returned on invested capital (“CROIC PSUs” and “ROIC PSUs”) over the performance period. CROIC PSUs are awarded to certain Berry employees, while ROIC PSUs are awarded to certain CJWS employees. The fair value of the stock-based awards is determined at the date of grant and is not remeasured. The fair value of the RSUs, CROIC PSUs and ROIC PSUs was determined using the grant date stock price. The fair value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the peer group over the performance periods. Estimates used in the Monte Carlo valuation model are considered highly complex and subjective. Compensation expense, net of actual forfeitures, for the RSUs and PSUs is recognized on a straight-line basis over the requisite service periods, which is over the awards’ respective vesting or performance periods which range from one to three years.

Other Loss Contingencies

In the normal course of business, we are involved in lawsuits, claims and other environmental and legal proceedings and audits. We accrue reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, we disclose, if material, in aggregate, our exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. We review our loss contingencies on an ongoing basis.

Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors.

Electricity Cost Allocation

We own several cogeneration facilities. Our investment in cogeneration facilities has been for the express purpose of lowering steam costs in our heavy oil operations in California and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power, extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. We allocate steam and electricity costs to lease operating expenses based on the conversion efficiency of the cogeneration facilities plus certain direct costs of producing steam. We also allocate a portion of the electricity production costs related to the power we sell to third parties, which is reported in “electricity generation expenses” in the statement of operations.

Income Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit).

Earnings per Share

Basic earnings (loss) per share is calculated as net income (loss) divided by the weighted-average shares of common stock outstanding during the period. Diluted earnings (loss) per share is calculated by dividing net income (loss) by the weighted-average shares of common stock outstanding, including the effect of potentially dilutive securities. For basic earnings per share (“EPS”), the weighted-average number of common stock outstanding excludes outstanding shares related to unvested restricted stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding potentially dilutive securities, unless their effect is anti-dilutive. We did not have any participating securities in the periods presented.

We compute basic and diluted EPS using the two-class method required for participating securities. Common stock awards are considered participating securities when such shares have non-forfeitable dividend rights at the same rate as common stock. Our dividend rights are forfeitable, and are not considered participating securities. Under the two-class method, undistributed earnings allocated to participating securities are subtracted from net income attributable to common stock in determining net income attributable to common stockholders. In loss periods, no allocation is made to participating securities because the participating securities do not share in losses.

Business and Credit Concentrations

We maintain our cash in bank deposit accounts which, at times, may exceed federally insured amounts. We have not experienced any losses in such accounts. We believe we are not exposed to any significant credit risk on our cash.

We sell oil, natural gas and NGLs to various types of customers, including pipelines, refineries and other oil and natural gas companies and electricity to utility companies. We also perform well servicing and abandonment for oil and natural gas companies. Based on the current demand for oil, natural gas, NGLs, as well as our well servicing and abandonment services and the availability of other purchasers, we believe that the loss of any one of our major purchasers would not have a material adverse effect on our financial condition, results of operations or net cash provided by operating activities.

For the year ended December 31, 2022, our three largest customers represented approximately 33%, 16%, and 10% of our sales. For the year ended December 31, 2021, our four largest customers represented 30%, 16%, 14%, and 12% of our sales. For the year ended December 31, 2020, our three largest customers represented approximately 44%, 20%, and 12% of our sales. All such customers were customers of our E&P segment.

At December 31, 2022, trade accounts receivable from three customers represented approximately 33%, 16%, and 13% of our receivables. At December 31, 2021, trade accounts receivable from three customers represented approximately 28%, 13%, and 11% of our receivables.

Recently Adopted Accounting Standards

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 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. The impacts of adoption were immaterial.

Stockholders' Equity - Stock Repurchase Program (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Feb. 27, 2023	Apr. 30, 2022
Equity, Class of Treasury Stock [Line Items]
Number of shares repurchased (in shares)	5,000,000
Repurchase of stock	$ 51,303,000	$ 2,441,000	$ 0
Shares repurchased or acquired (in shares)	10,528,704
Treasury stock, aggregate repurchase value	$ 104,000,000
Stock Repurchase Program
Equity, Class of Treasury Stock [Line Items]
Increased authorized amount on repurchased shares					$ 102,000,000
Authorized amount of repurchases	$ 98,000,000				$ 150,000,000
Stock Repurchase Program \| Subsequent Event
Equity, Class of Treasury Stock [Line Items]
Increased authorized amount on repurchased shares				$ 102,000,000
Authorized amount of repurchases				$ 200,000,000

Cover Page - USD ($) $ in Millions	12 Months Ended
Cover Page - USD ($) $ in Millions	Dec. 31, 2022	Jan. 31, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-38606
Entity Registrant Name	BERRY CORPORATION (bry)
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	81-5410470
Entity Address, Address Line One	16000 Dallas Parkway
Entity Address, Address Line Two	Suite 500
Entity Address, City or Town	Dallas
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75248
City Area Code	661
Local Phone Number	616-3900
Title of 12(b) Security	Common Stock, par value $0.001 per share
Trading Symbol	BRY
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	true
Entity Ex Transition Period	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float			$ 501.6
Entity Common Stock, Shares Outstanding		75,767,503
Documents Incorporated by Reference	The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 23, 2023) will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2022 and is incorporated by reference in Part III to the extent described herein.
Entity Central Index Key	0001705873
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current taxes:
Federal	$ 642	$ 0	$ 0
State	1,597	581	828
Total current taxes	2,239	581	828
Deferred taxes:
Federal	(44,053)	832	2,653
State	(622)	0	(10,699)
Total deferred taxes	(44,675)	832	(8,046)
Total current and deferred taxes	$ (42,436)	$ 1,413	$ (7,218)

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues and other:
(Losses) gains on oil and gas sales derivatives	$ (137,109,000)	$ (156,399,000)	$ 117,781,000
Total revenue, excluding assessed tax	1,055,450,000	701,349,000	406,052,000
Total revenues and other	918,341,000	544,950,000	523,833,000
Expenses and other:
Transportation expenses	4,564,000	6,897,000	6,938,000
Marketing expenses	299,000	3,811,000	1,380,000
General and administrative expenses	96,439,000	73,106,000	77,696,000
Depreciation, depletion and amortization	156,847,000	144,495,000	139,180,000
Impairment of oil and gas properties	0	0	289,085,000
Taxes, other than income taxes	39,495,000	46,500,000	35,572,000
(Gains) losses on natural gas purchase derivatives	(88,795,000)	(38,577,000)	1,035,000
Other operating expense	3,722,000	3,101,000	5,781,000
Total expenses and other	679,550,000	526,868,000	759,623,000
Other (expenses) income:
Interest expense	(30,917,000)	(31,964,000)	(34,295,000)
Other, net	(142,000)	(247,000)	(28,000)
Total other (expenses) income	(31,059,000)	(32,211,000)	(34,323,000)
Income (loss) before income taxes	207,732,000	(14,129,000)	(270,113,000)
Income tax (benefit) expense	(42,436,000)	1,413,000	(7,218,000)
Net income (loss)	$ 250,168,000	$ (15,542,000)	$ (262,895,000)
Earnings Per Share [Abstract]
Basic (in dollars per share)	$ 3.19	$ (0.19)	$ (3.29)
Diluted (in dollars per share)	$ 3.03	$ (0.19)	$ (3.29)
Oil, natural gas and natural gas liquid sales
Revenues and other:
Total revenue, excluding assessed tax	$ 842,449,000	$ 625,475,000	$ 378,663,000
Expenses and other:
Cost of goods sold	302,321,000	236,048,000	186,348,000
Service revenue
Revenues and other:
Total revenue, excluding assessed tax	181,400,000	35,840,000	0
Expenses and other:
Cost of goods sold	142,819,000	28,339,000	0
Electricity sales
Revenues and other:
Total revenue, excluding assessed tax	30,833,000	35,636,000	25,813,000
Expenses and other:
Cost of goods sold	21,839,000	23,148,000	16,608,000
Marketing revenues
Revenues and other:
Total revenue, excluding assessed tax	289,000	3,921,000	1,426,000
Other revenues
Revenues and other:
Total revenue, excluding assessed tax	$ 479,000	$ 477,000	$ 150,000

Derivatives - Fair Values (Gross and Net) of Outstanding Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative Liability [Abstract]
Derivative Assets (Liabilities), at Fair Value, Net, Total	$ (8,305)	$ (47,132)
Commodity Contracts \| Current assets
Derivative Asset [Abstract]
Gross Amounts Recognized at Fair Value	66,974	5,360
Gross Amounts Offset in the Balance Sheet	(30,607)	(5,360)
Derivative Asset, Total	36,367	0
Commodity Contracts \| Non-current assets
Derivative Asset [Abstract]
Gross Amounts Recognized at Fair Value	39,886	29,828
Gross Amounts Offset in the Balance Sheet	(39,810)	(28,758)
Derivative Asset, Total	76	1,070
Commodity Contracts \| Current liabilities
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	(61,713)	(34,985)
Derivative Liability, Fair Value, Gross Asset	30,607	5,360
Derivative Liability	(31,106)	(29,625)
Commodity Contracts \| Non-current liabilities
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	(53,452)	(47,335)
Derivative Liability, Fair Value, Gross Asset	39,810	28,758
Derivative Liability	$ (13,642)	$ (18,577)

Basis of Presentation and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Activity in ARO Account


	Year Ended December 31,
	2022		2021
	(in thousands)
Beginning balance	$	163,925	$	160,192
Liabilities incurred including from acquisitions	3,028		1,350
Settlements and payments	(19,558)		(17,900)

Accretion expense	10,848		10,936
Reduction due to property sales	(1,210)		(22,199)
Revisions	21,458		31,546

Ending balance	$	178,491	$	163,925

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
Income Taxes - Narrative (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Components Of Income Tax Expense (Benefit) [Line Items]
Effective tax rate	(20.40%)	(10.00%)	2.80%
Net operating loss carryforwards	$ 107,000,000
Income tax (benefit) expense	(42,436,000)	$ 1,413,000	$ (7,218,000)
Income tax benefit related to valuation allowance	78,000,000
Valuation allowance	0	77,546,000
Uncertain tax benefits	0	$ 0
Domestic \| General Business Tax Credit Carryforward
Components Of Income Tax Expense (Benefit) [Line Items]
Tax credit carryforwards	82,000,000
Income tax (benefit) expense	(7,000,000)
State and Local Jurisdiction
Components Of Income Tax Expense (Benefit) [Line Items]
Net operating loss carryforwards	0
State and Local Jurisdiction \| State Tax Credit Carryforward
Components Of Income Tax Expense (Benefit) [Line Items]
Tax credit carryforwards	$ 8,000,000

Segment Information - Schedule of Segment Information (Details) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended			15 Months Ended
	Dec. 31, 2021 USD ($) business	Sep. 30, 2022 business	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2022 USD ($) segment
Segment Reporting Information [Line Items]
Business segments	2	1				2
Total revenue, excluding assessed tax			$ 1,055,450	$ 701,349	$ 406,052
Expenses during consolidation			679,550	526,868	759,623
Net (loss) income before income taxes			207,732	(14,129)	(270,113)
Adjusted EBITDA			379,948	212,146
Capital expenditures			152,921	132,719	$ 76,480
Total assets	$ 1,456,479		1,631,030	1,456,479		$ 1,631,030
Intersegment Eliminations
Segment Reporting Information [Line Items]
Total revenue, excluding assessed tax			3,000
Expenses during consolidation			3,000
Corporate/Eliminations
Segment Reporting Information [Line Items]
Total revenue, excluding assessed tax			(3,188)	0
Net (loss) income before income taxes			(110,193)	(96,956)
Adjusted EBITDA			(57,976)	(43,310)
Capital expenditures			2,536	2,211
Total assets	(74,771)		(15,682)	(74,771)		(15,682)
E&P \| Operating Segments
Segment Reporting Information [Line Items]
Total revenue, excluding assessed tax			874,190	665,509
Net (loss) income before income taxes			303,178	82,826
Adjusted EBITDA			411,811	251,146
Capital expenditures			141,930	129,479
Total assets	1,450,157		1,563,251	1,450,157		1,563,251
Well Servicing and Abandonment \| Operating Segments
Segment Reporting Information [Line Items]
Total revenue, excluding assessed tax			184,448	35,840
Net (loss) income before income taxes			14,747	1
Adjusted EBITDA			26,113	4,310
Capital expenditures			8,455	1,029
Total assets	$ 81,093		$ 83,461	$ 81,093		$ 83,461

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaid expenses	$ 12,330	$ 26,840
Materials and supplies	8,976	9,533
Prepaid deposits	7,266	6,415
Oil inventories	4,036	2,933
Other	1,117	225
Total other current assets	$ 33,725	$ 45,946

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Disclosures of Significant Non-Cash Operating Activities:
Greenhouse gas liability - reclassification from current liability to long-term	$ 8,000	$ 0	$ 0
Greenhouse gas liability - reclassification from long-term to current liability	0	0	33,376
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties	2,707	3,424	1,596
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	29,792	29,211	29,962
Income taxes payments	$ 3,633	$ 699	$ 222

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
Net operating loss carryforwards	$ 22,402	$ 40,846
Accruals	10,728	11,731
Asset retirement obligations	48,994	44,437
Derivative instruments	2,280	12,776
Tax credits	88,908	61,044
Other	2,882	3,551
Subtotal	176,194	174,385
Valuation allowance	0	(77,546)
Total deferred tax assets	176,194	96,839
Deferred tax liabilities:
Book tax differences in property basis	(133,350)	(98,670)
Total deferred tax liabilities	(133,350)	(98,670)
Net deferred tax asset	$ 42,844
Net deferred tax liability		$ (1,831)

Derivatives - Derivative Transactions Resulting in Crude Oil Production and Gas Purchases Hedges (Details) - Forecast MMBTU in Thousands	1 Months Ended	2 Months Ended	3 Months Ended						8 Months Ended	12 Months Ended
	Jan. 31, 2025 $ / MMBoe bbl	Dec. 31, 2023 MMBTU $ / bbl $ / MMBtu	Mar. 31, 2026 $ / MMBoe bbl	Mar. 31, 2025 $ / MMBoe bbl	Dec. 31, 2023 MMBTU $ / bbl $ / MMBtu bbl	Sep. 30, 2023 MMBTU $ / bbl $ / MMBtu bbl	Jun. 30, 2023 MMBTU $ / bbl $ / MMBoe $ / MMBtu bbl	Mar. 31, 2023 MMBTU $ / bbl $ / MMBoe $ / MMBtu bbl	Oct. 31, 2023 MMBTU $ / MMBtu	Dec. 31, 2025 MMBTU $ / bbl $ / MMBtu bbl	Dec. 31, 2024 MMBTU $ / bbl $ / MMBtu bbl
Swaps
Derivative [Line Items]
Hedged volume (bbls) \| bbl					1,196,000	1,211,717	1,387,750	1,385,278		0	3,392,048
Weighted-average price ($/bbl)		76.18			76.18	76.26	77.01	77.15		0	76.12
Put Spread, Long
Derivative [Line Items]
Hedged volume (bbls) \| bbl					644,000	644,000	637,000	630,000		0	1,647,000
Put Spread, Short
Derivative [Line Items]
Hedged volume (bbls) \| bbl					92,000	92,000	91,000	90,000		0	366,000
Producer Collar, Purchased Puts
Derivative [Line Items]
Hedged volume (bbls) \| bbl	3,627		472,500	270,000	368,000	368,000	364,000	360,000		2,212,500	1,098,000
Consumer Collars
Derivative [Line Items]
Hedged volume (mmbtu) \| MMBTU					0	0	1,820	2,110		0	0
Weighted-average price ($/mmbtu) \| $ / MMBtu		0			0	0				0	0
NWPL - Natural Gas Purchases
Derivative [Line Items]
Hedged volume (mmbtu) \| MMBTU					3,680	3,680	3,640	1,800		6,080	7,320
Weighted-average price ($/mmbtu) \| $ / MMBtu		5.34			5.34	5.34	5.34	6.40		4.27	4.27
NWPL/HH - basis swaps
Derivative [Line Items]
Hedged volume (mmbtu) \| MMBTU					1,840	1,840	1,820	1,800		0	0
Weighted-average price ($/mmbtu) \| $ / MMBtu		1.12			1.12	1.12	1.12	1.12	1.12	0	0
Hedged volume, terminated \| MMBTU		610							4,900
Minimum \| Put Spread, Long
Derivative [Line Items]
Weighted-average price ($/bbl)								40
Minimum \| Put Spread, Short
Derivative [Line Items]
Weighted-average price ($/bbl)								40
Minimum \| Producer Collar, Purchased Puts
Derivative [Line Items]
Weighted-average price ($/bbl) \| $ / MMBoe	60.00		60.00	60.00
Weighted-average price ($/mmbtu)		40.00			40.00	40.00	40.00	40.00		58.35	40.00
Minimum \| Consumer Collars
Derivative [Line Items]
Weighted-average price ($/mmbtu) \| $ / MMBoe							2.75	2.75
Maximum \| Put Spread, Long
Derivative [Line Items]
Weighted-average price ($/bbl)								50
Maximum \| Put Spread, Short
Derivative [Line Items]
Weighted-average price ($/bbl)								50
Maximum \| Producer Collar, Purchased Puts
Derivative [Line Items]
Weighted-average price ($/bbl) \| $ / MMBoe	88.50		82.21	88.35
Weighted-average price ($/mmbtu)		106.00			106.00	106.00	106.00	106.00		91.45	105.00
Maximum \| Consumer Collars
Derivative [Line Items]
Weighted-average price ($/mmbtu) \| $ / MMBoe							4.00	4.00

Segment Information (Tables)

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Schedule of Segment Information


	Year Ended December 31, 2022
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues(1)	$	874,190	$	184,448	$	(3,188)	$	1,055,450
Net income (loss) before income taxes	$	303,178	$	14,747	$	(110,193)	$	207,732
Adjusted EBITDA	$	411,811	$	26,113	$	(57,976)	$	379,948
Capital expenditures	$	141,930	$	8,455	$	2,536	$	152,921
Total assets	$	1,563,251	$	83,461	$	(15,682)	$	1,631,030


	Year Ended December 31, 2021
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Revenues(1)	$	665,509	$	35,840	$	—	$	701,349
Net income (loss) before income taxes	$	82,826	$	1	$	(96,956)	$	(14,129)
Adjusted EBITDA	$	251,146	$	4,310	$	(43,310)	$	212,146
Capital expenditures	$	129,479	$	1,029	$	2,211	$	132,719
Total assets	$	1,450,157	$	81,093	$	(74,771)	$	1,456,479

__________

(1) These revenues do not include hedge settlements.

Adjusted EBITDA Reconciliation


	Year Ended December 31, 2022
			Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	303,178	$	14,747	$	(67,757)	$	250,168
Add (Subtract):
Interest expense	—		23		30,894		30,917
Income tax benefit	—		—		(42,436)		(42,436)
Depreciation, depletion, and amortization	139,886		12,548		4,413		156,847
Losses on derivatives	48,314		—		—		48,314
Net cash paid for scheduled derivative settlements	(88,023)		—		—		(88,023)
Other operating expenses (income)	3,827		(1,690)		1,585		3,722
Stock compensation expense	1,361		287		15,325		16,973
Non-recurring costs(1)	3,268		198		—		3,466
Adjusted EBITDA	$	411,811	$	26,113	$	(57,976)	$	379,948

__________


	Year Ended December 31, 2021
	E&P		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	82,825	$	1	$	(98,368)	$	(15,542)
Add (Subtract):
Interest expense	—		—		31,964		31,964
Income tax expense	—		—		1,413		1,413
Depreciation, depletion, and amortization	136,915		2,974		4,606		144,495
Losses on derivatives	117,822		—		—		117,822
Net cash paid for scheduled derivative settlements	(87,625)		—		—		(87,625)
Other operating expenses	109		—		2,992		3,101
Stock compensation expense	1,100		—		12,683		13,783
Non-recurring costs(1)	—		1,335		1,400		2,735
Adjusted EBITDA	$	251,146	$	4,310	$	(43,310)	$	212,146

__________

(1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the fourth quarter of

2021.

Stockholders' Equity

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Stockholders' Equity

Cash Dividends

Our Board of Directors approved quarterly fixed cash dividends totaling $0.24 per share in 2022, as well as variable cash dividends of $1.10 per share, which were based on the results in 2022, for a total of $1.34 per share. In February 2023, our Board of Directors approved a fixed cash dividend of $0.06 per share, as well as, the variable cash dividend of $0.44 per share based on the fourth quarter of 2022 results.

For the year ended December 31, 2022, December 31, 2021, December 31, 2020 we paid approximately $109 million, $11 million and $19 million, respectively, in cash dividends on our common stock.

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.

Common Stock

On March 1, 2022, our Board of Directors approved the 2022 Omnibus Incentive Plan (the “2022 Omnibus Plan”), which was subsequently approved by stockholders on May 25, 2022. The plan authorized the issuance of 2,300,000 shares of common stock. The maximum number of shares remaining that may be issued is 1,573,402 as of December 31, 2022, which is the total number of shares of our common stock remaining available for issuance after counting the number of securities to be issued upon vesting of outstanding RSU and PSU awards, and counting PSUs at the maximum payout level. Shares reserved at maximum payout that do not vest at maximum are made available for future grants.

On June 27, 2018, our board of directors adopted the second amended and restated 2017 Omnibus Incentive Plan (“2017 Omnibus Plan”), as amended and restated (our “Restated Incentive Plan”). This plan constitutes an amendment and restatement of the plan (the “Prior Plan”) as in effect immediately prior to the adoption of the Restated Incentive Plan. The Prior Plan constituted an amendment and restatement of the plan originally adopted as of June 15, 2017 (the “2017 Omnibus Plan”). The Restated Incentive Plan provides for the grant, from time to time, at the discretion of the board of directors or a committee thereof, of stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards. The maximum number of shares of common stock that may be issued pursuant to an award under the Restated Incentive Plan is 10,000,000 inclusive of the number of shares of common stock previously issued pursuant to awards granted under the Prior Plan or the 2017 Plan.

Voting Rights. Each share of common stock is entitled to one vote with respect to each matter on which holders of common stock are entitled to vote. Holders of common stock do not have cumulative voting rights.

Dividend Rights. Holders of common stock will be entitled to receive dividends, if any, as may be declared from time to time by our board of directors (the “Board”) out of legally available funds.

Liquidation Rights. Upon liquidation, dissolution or winding up of the Company, holders of our common stock will be entitled to share ratably in the assets of the Company that are legally available for distribution to holders of our common stock after payment of the Company’s debts and other liabilities.

Preemptive and Conversion Rights. Holders of common stock have no preemptive, conversion or other rights to subscribe for additional shares.

Registration Rights Agreement

On June 28, 2018, Berry Corp. entered into an amended and restated registration rights agreement (the “Registration Rights Agreement”) with certain holders of our Common Stock and Preferred Stock in connection with our IPO.

In accordance with the Registration Rights Agreement, Berry Corp. filed a shelf registration statement with the SEC on December 10, 2018, which was declared effective on December 13, 2018. The shelf registration statement registered the resale, on a delayed or continuous basis, of all Registrable Securities that have been timely designated for inclusion by specified Holders (as defined in the Registration Rights Agreement). Generally, “Registrable Securities” includes (i) common stock and preferred stock issued by Berry Corp. in connection with the IPO to stockholders party to the Registration Rights Agreement, and (ii) preferred stock that was purchased by the participants in the rights offering noted above and (iii) common stock into which the preferred stock converts, except that “Registrable Securities” does not include securities that have been sold under an effective registration statement or Rule 144 under the Securities Act. The Registration Rights Agreement will terminate when there are no longer any Registrable Securities outstanding.

Shares Outstanding

As of December 31, 2022, there were 75,767,503 shares of common stock outstanding. Up to an additional 8,110,302 shares were issuable for unvested restricted stock units and performance restricted stock units (assuming maximum achievement of performance goals) under the Company's 2022 Omnibus Incentive Plan as of December 31, 2022.

Repurchase Program

For the year ended December 31, 2022, we repurchased 5 million shares for approximately $51 million. As of December 31, 2022, the Company had repurchased a total of 10,528,704 shares under the stock repurchase program for approximately $104 million in aggregate. As previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company intends to allocate a portion of Adjusted Free Cash Flow to opportunistic share repurchases.

In April 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 December 31, 2022, the Company’s remaining total share repurchase authority is $98 million, after the repurchases made in the second, third, and fourth quarters of 2022. In February 2023, the Board of Directors approved an increase of $102 million to the Company’s stock repurchase authorization bringing the Company’s remaining share authority to $200 million. 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.

We repurchased approximately $2 million of shares in 2021 and none in 2020.

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

The Company has awarded restricted stock units (“RSUs”) that are solely time-based awards and performance-based restricted stock units (“PSUs”) that include (i) awards with a market objective measured against both absolute total stockholder return (“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR PSUs”) over the performance period and (ii) awards based on the Company's average cash returned on invested capital (“CROIC 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 in 2022 and 2021, 0% to 200% of the TSR PSUs granted in 2020, 0% to 200% of the CROIC PSUs granted in 2022 and 2021, and 0% to 200% of the ROIC PSUs granted in 2022. No CROIC PSUs were granted prior to 2021 and no ROIC PSUs were granted prior to 2022.

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

The PSUs awarded in February 2022 were accounted for as liability awards in the first quarter of 2022, but were converted to equity awards during the second quarter of 2022 due to the approval of the 2022 Omnibus Plan by the stockholders in May 2022.

For the years ended December 31, 2022, 2021, and 2020 the stock-based compensation expense was approximately $18 million, $14 million, and $15 million, respectively. For the year ended December 31, 2022, the income tax benefit was $2 million. For the years ended December 31 2021 and 2020 the stock-based compensation income tax benefit was not material.

The table below summarizes the activity relating to RSUs issued under the Restated Incentive Plan during the year ended December 31, 2022. The RSUs vest ratably over three years. Unrecognized compensation cost associated with the RSUs at December 31, 2022 was approximately $10 million which will be recognized over a weighted-average period of approximately two years.


	Number of shares	Weighted-average Grant Date Fair Value
	(shares in thousands)
Non-vested at December 31, 2021	2,580	$	5.67
Granted	1,317	$	8.92
Vested	(1,145)	$	6.36
Forfeited	(233)	$	6.97
Non-vested at December 31, 2022	2,519	$	6.94

The table below summarizes the activity relating to the PSUs issued under the Revised Incentive Plan during the year ended December 31, 2022. Unrecognized compensation cost associated with the PSUs at December 31, 2022 is approximately $8 million which will be recognized over a weighted-average period of approximately two years.


	Number of shares	Weighted-average Grant Date Fair Value
	(shares in thousands)
Non-vested at December 31, 2021	2,085	$	11.00
Granted	611	$	12.03
Vested	(36)	$	12.75
Forfeited	(59)	$	12.51
Non-vested at December 31, 2022	2,601	$	11.18

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Schedule of Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accounts payable - trade	$ 40,286	$ 17,699
Accrued expenses	85,360	62,962
Royalties payable	38,264	24,816
Greenhouse gas liability - current portion	0	7,513
Taxes other than income tax liability	6,640	8,273
Accrued interest	10,885	10,736
Dividends payable	0	4,800
Asset retirement obligation - current portion	20,000	20,000
Total lease obligations	1,666	0
Other	0	725
Total accounts payable and accrued expenses	$ 203,101	$ 157,524

Label	Element	Value
ABL Facility 2022 [Member]
Repayments of Long-Term Lines of Credit	us-gaap_RepaymentsOfLongTermLinesOfCredit	$ 0
Proceeds from Long-Term Lines of Credit	us-gaap_ProceedsFromLongTermLinesOfCredit	$ 0

Leases - Lease Cost (Details) $ in Thousands	12 Months Ended
Leases - Lease Cost (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Lease Cost
Operating lease cost	$ 1,992
Total net lease cost	$ 1,992

Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Schedule of Restricted Stock Units (RSUs) Activity


	Number of shares	Weighted-average Grant Date Fair Value
	(shares in thousands)
Non-vested at December 31, 2021	2,580	$	5.67
Granted	1,317	$	8.92
Vested	(1,145)	$	6.36
Forfeited	(233)	$	6.97
Non-vested at December 31, 2022	2,519	$	6.94

Schedule of Performance-Based Restricted Stock Unit (PSUs) Activity


	Number of shares	Weighted-average Grant Date Fair Value
	(shares in thousands)
Non-vested at December 31, 2021	2,085	$	11.00
Granted	611	$	12.03
Vested	(36)	$	12.75
Forfeited	(59)	$	12.51
Non-vested at December 31, 2022	2,601	$	11.18

Oil and Natural Gas Properties and Other Property and Equipment - Other Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 155,619	$ 140,710
Less accumulated depreciation	(55,781)	(36,927)
Total other property and equipment, net	99,838	103,783
Cogeneration facilities, natural gas plants and pipelines
Property, Plant and Equipment [Line Items]
Other property and equipment	58,357	54,237
Vehicles and service equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	65,195	55,521
Furniture and equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	23,779	22,665
Land
Property, Plant and Equipment [Line Items]
Other property and equipment	6,102	6,101
Buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 2,186	$ 2,186

Stockholders' Equity - RSUs and PRUs Activity (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2022 $ / shares shares
Restricted Stock Units (RSUs)
Number of shares
Outstanding, beginning of period (in shares) \| shares	2,580
Granted (in shares) \| shares	1,317
Vested (in shares) \| shares	(1,145)
Forfeited (in shares) \| shares	(233)
Outstanding, end of period (in shares) \| shares	2,519
Weighted-average Grant Date Fair Value
Outstanding, beginning of period (in dollars per share) \| $ / shares	$ 5.67
Granted (in dollars per share) \| $ / shares	8.92
Vested (in dollars per share) \| $ / shares	6.36
Forfeited (in dollars per share) \| $ / shares	6.97
Outstanding, end of period (in dollars per share) \| $ / shares	$ 6.94
Performance-based Restricted Stock Units (PSUs)
Number of shares
Outstanding, beginning of period (in shares) \| shares	2,085
Granted (in shares) \| shares	611
Vested (in shares) \| shares	(36)
Forfeited (in shares) \| shares	(59)
Outstanding, end of period (in shares) \| shares	2,601
Weighted-average Grant Date Fair Value
Outstanding, beginning of period (in dollars per share) \| $ / shares	$ 11.00
Granted (in dollars per share) \| $ / shares	12.03
Vested (in dollars per share) \| $ / shares	12.75
Forfeited (in dollars per share) \| $ / shares	12.51
Outstanding, end of period (in dollars per share) \| $ / shares	$ 11.18

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flow from operating activities:
Net income (loss)	$ 250,168,000	$ (15,542,000)	$ (262,895,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	156,847,000	144,495,000	139,180,000
Amortization of debt issuance costs	2,590,000	4,430,000	5,351,000
Impairment of oil and gas properties	0	0	289,085,000
Stock-based compensation expense	16,973,000	13,783,000	14,630,000
Deferred income taxes	(45,566,000)	819,000	(8,045,000)
(Decrease) increase in allowance for doubtful accounts	0	(1,349,000)	1,112,000
Other operating expenses	160,000	(487,000)	5,083,000
Derivatives activities:
Total losses (gains)	48,314,000	117,822,000	(116,746,000)
Cash settlements on derivatives	(88,023,000)	(91,634,000)	142,292,000
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(15,409,000)	(15,614,000)	18,767,000
Decrease (increase) in other assets	6,725,000	(24,824,000)	(2,000)
Increase (decrease) in accounts payable and accrued expenses	36,100,000	4,045,000	(14,172,000)
Decrease in other liabilities	(7,938,000)	(13,456,000)	(17,111,000)
Net cash provided by operating activities	360,941,000	122,488,000	196,529,000
Capital expenditures:
Capital expenditures	(152,921,000)	(132,719,000)	(76,480,000)
Changes in capital expenditures accruals	14,286,000	482,000	(11,336,000)
Acquisitions, net of cash received	(25,917,000)	(50,568,000)	0
Acquisition of properties and equipment and other	0	(876,000)	(5,981,000)
Proceeds received from divestitures	0	14,025,000	0
Proceeds from sale of property and equipment and other	0	869,000	177,000
Net cash used in investing activities	(164,552,000)	(168,787,000)	(93,620,000)
Cash flow from financing activities:
Dividends paid on common stock	(109,455,000)	(11,486,000)	(19,463,000)
Repurchase of common stock	(51,303,000)	(2,440,000)	0
Shares withheld for payment of taxes on equity awards and other	(4,136,000)	(1,543,000)	(1,039,000)
Debt issuance costs	(528,000)	(3,506,000)	0
Net cash used in financing activities	(165,422,000)	(18,975,000)	(22,352,000)
Net increase (decrease) in cash and cash equivalents	30,967,000	(65,274,000)	80,557,000
Cash and cash equivalents:
Beginning	15,283,000	80,557,000	0
Ending	46,250,000	15,283,000	80,557,000
RBL Facility
Cash flow from financing activities:
Borrowings under credit facility	247,000,000	119,000,000	228,900,000
Repayments on credit facility	(247,000,000)	(119,000,000)	$ (230,750,000)
2022 ABL Facility
Cash flow from financing activities:
Borrowings under credit facility	2,000,000	0
Repayments on credit facility	$ (2,000,000)	$ 0

Segment Information - Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Net income (loss)	$ 250,168	$ (15,542)	$ (262,895)
Interest expense	30,917	31,964	34,295
Income tax (benefit) expense	(42,436)	1,413	(7,218)
Depreciation, depletion and amortization	156,847	144,495	139,180
Losses on derivatives	48,314	117,822	(116,746)
Net cash paid for scheduled derivative settlements	(88,023)	(87,625)
Other operating expense	3,722	3,101	5,781
Stock-based compensation expense	16,973	13,783	$ 14,630
Non-recurring costs(1)	3,466	2,735
Adjusted EBITDA	379,948	212,146
Operating Segments \| E&P
Segment Reporting Information [Line Items]
Net income (loss)	303,178	82,825
Interest expense	0	0
Income tax (benefit) expense	0	0
Depreciation, depletion and amortization	139,886	136,915
Losses on derivatives	48,314	117,822
Net cash paid for scheduled derivative settlements	(88,023)	(87,625)
Other operating expense	3,827	109
Stock-based compensation expense	1,361	1,100
Non-recurring costs(1)	3,268	0
Adjusted EBITDA	411,811	251,146
Operating Segments \| Well Servicing and Abandonment
Segment Reporting Information [Line Items]
Net income (loss)	14,747	1
Interest expense	23	0
Income tax (benefit) expense	0	0
Depreciation, depletion and amortization	12,548	2,974
Losses on derivatives	0	0
Net cash paid for scheduled derivative settlements	0	0
Other operating expense	(1,690)	0
Stock-based compensation expense	287	0
Non-recurring costs(1)	198	1,335
Adjusted EBITDA	26,113	4,310
Corporate/Eliminations
Segment Reporting Information [Line Items]
Net income (loss)	(67,757)	(98,368)
Interest expense	30,894	31,964
Income tax (benefit) expense	(42,436)	1,413
Depreciation, depletion and amortization	4,413	4,606
Losses on derivatives	0	0
Net cash paid for scheduled derivative settlements	0	0
Other operating expense	1,585	2,992
Stock-based compensation expense	15,325	12,683
Non-recurring costs(1)	0	1,400
Adjusted EBITDA	$ (57,976)	$ (43,310)

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Future Net Minimum Payments for Purchase Obligations and Operating Leases

At December 31, 2022, future net minimum payments for non-cancelable purchase obligations (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance expense) were as follows:


	2023		2024		2025		2026		2027		Thereafter		Total
	(in thousands)
Processing and transportation contracts(1)	$	11,343	$	9,553	$	8,234	$	8,082	$	8,083	$	43,521	$	88,816
Drilling commitment(2)	8,400		8,700		—		—		—		—		17,100
Total	$	19,743	$	18,253	$	8,234	$	8,082	$	8,083	$	43,521	$	105,916

__________

Stockholders' Equity - Common Stock (Narrative) (Details)	Feb. 28, 2017 vote	Dec. 31, 2022 shares	Mar. 01, 2022 shares	Jun. 27, 2018 shares
Class of Stock [Line Items]
Number of voting rights per share \| vote	1
2022 Omnibus Incentive Plan ("2022 Plan")
Class of Stock [Line Items]
Shares authorized, common stock (in shares)			2,300,000
Number of shares available for grant (in shares)		1,573,402
Restated Incentive Plan
Class of Stock [Line Items]
Common stock, shares reserved for future issuance (in shares)				10,000,000

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Summary of Pro Forma Information

The following unaudited pro forma information is not necessarily indicative of the results that would have been achieved if the CJWS acquisition had occurred in the past, and should not be relied upon as an indication of the operating results that the Company would have achieved if the acquisition had occurred at the beginning of the periods presented, and our operating results, or the future results.


	Pro Forma
	Year Ended December 31,
	2021		2020
	(unaudited) (in thousands)
Revenue	$	664,549	$	657,796
Net income (loss)	$	740	$	(250,884)

Revenue Recognition - Narrative (Details)	12 Months Ended
Revenue Recognition - Narrative (Details)	Dec. 31, 2022
Oil, natural gas and natural gas liquid sales
Disaggregation of Revenue [Line Items]
Payment term (within)	30 days
Service revenue \| Minimum
Disaggregation of Revenue [Line Items]
Payment term (within)	30 days
Service revenue \| Maximum
Disaggregation of Revenue [Line Items]
Payment term (within)	60 days

Earnings Per Share

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

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 earnings (loss) per share.

The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the year ended December 31, 2022, 4,069,000 incremental RSU and PSU shares were included in the diluted EPS calculation. For the years ended December 2021 and 2020, no incremental RSU or PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the “if-converted” method.


	Year Ended December 31,
	2022		2021		2020
	(in thousands except per share amounts)
Basic EPS calculation
Net income (loss)	$	250,168	$	(15,542)	$	(262,895)
Weighted-average shares of common stock outstanding	78,517		80,209		79,802
Basic income (loss) per share	$	3.19	$	(0.19)	$	(3.29)
Diluted EPS calculation
Net income (loss)	$	250,168	$	(15,542)	$	(262,895)
Weighted-average shares of common stock outstanding	78,517		80,209		79,802
Dilutive effect of potentially dilutive securities(1)	4,069		—		—
Weighted-average common shares outstanding - diluted	82,586		80,209		79,802
Diluted income (loss) per share	$	3.03	$	(0.19)	$	(3.29)

__________

(1) We excluded 3.3 million and 0.1 million of combined RSUs and PSUs from the diluted weighted-average common shares outstanding because their effect was anti-dilutive for the years ended December 31, 2021 and 2020, respectively.

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	Dallas, TX
Auditor Firm ID	185

Earnings Per Share - Narrative (Details) - shares	12 Months Ended
Earnings Per Share - Narrative (Details) - shares	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Incremental common shares attributable to dilutive effect of share-based payment arrangements (in shares)	4,069,000	0	0

Leases - Cash Flow (Details) $ in Thousands	12 Months Ended
Leases - Cash Flow (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$ 2,128
ROU assets obtained in exchange for operating lease liabilities	$ 7,956

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows (Tables)

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Other Current Assets

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


	Year Ended December 31,
	2022		2021
	(in thousands)
Prepaid expenses	$	12,330	$	26,840

Materials and supplies	8,976		9,533
Prepaid deposits	7,266		6,415
Oil inventories	4,036		2,933
Other	1,117		225
Total other current assets	$	33,725	$	45,946

Schedule of Accounts Payable and Accrued Expenses

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


	Year Ended December 31,
	2022		2021
	(in thousands)
Accounts payable - trade	$	40,286	$	17,699
Accrued expenses	85,360		62,962
Royalties payable	38,264		24,816

Greenhouse gas liability - current portion	—		7,513
Taxes other than income tax liability	6,640		8,273
Accrued interest	10,885		10,736
Dividends payable	—		4,800
Asset retirement obligation - current portion	20,000		20,000
Operating lease liability	1,666		—
Other	—		725
Total accounts payable and accrued expenses	$	203,101	$	157,524

Supplemental Cash Flow Information

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


	Year Ended December 31,
	2022		2021		2020
	(in thousands)
Supplemental Disclosures of Significant Non-Cash Operating Activities:
Greenhouse gas liability - reclassification from current liability to long-term	$	8,000	$	—	$	—
Greenhouse gas liability - reclassification from long-term to current liability	$	—	$	—	$	33,376
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties	$	2,707	$	3,424	$	1,596
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	$	29,792	$	29,211	$	29,962
Income taxes payments	$	3,633	$	699	$	222

Acquisitions and Divestitures - Additional Information (Details) $ in Thousands		1 Months Ended				3 Months Ended		12 Months Ended
	Oct. 01, 2021 USD ($)	Feb. 28, 2022 USD ($) MMBoe	Jan. 31, 2022 USD ($) MMBoe	Oct. 31, 2021 USD ($)	May 31, 2020 USD ($) a	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisitions, net of cash received								$ 25,917	$ 50,568	$ 0
Proceeds received from divestitures								0	14,025	$ 0
Gain on sale									2,000
Antelope Creek Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition amount		$ 18,000
Boe produced \| MMBoe		0.6
Various Oil and Gas Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition amount								8,000
Piceance Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposition of oil and gas property			$ (2,000)						$ (2,000)
Production per day, from acquisition \| MMBoe			1.2
Placerita Field
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds received from divestitures				$ 14,000
Gain on sale				$ 2,000
C&J Well Services Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred in acquisition	$ 53,000
Acquisitions, net of cash received						$ 51,000		2,000
Transaction costs								$ 3,000
Chevron North Midway-Sunset Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration transferred in acquisition					$ 5,000
Area of land acquired (in acres) \| a					740
Payments to acquire business					$ 2,000
Payment for contingent consideration liability							$ 3,000
McKittrick Field
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land acquired (in acres) \| a					267

Stockholders' Equity - Cash Dividend (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	12 Months Ended
	Feb. 28, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Common stock, dividends paid (in dollars per share)		$ 1.34
Common stock, dividends declared (in dollars per share)		$ 1.34	$ 0.20	$ 0.12
Dividends paid on common stock		$ 109,455	$ 11,486	$ 19,463
Cash Dividend
Class of Stock [Line Items]
Common stock, dividends paid (in dollars per share)		$ 0.24
Dividends paid on common stock		$ 109,000	$ 11,000	$ 19,000
Cash Dividend \| Subsequent Event \| Forecast
Class of Stock [Line Items]
Common stock, dividends paid (in dollars per share)	$ 0.06
Variable Rate Dividend
Class of Stock [Line Items]
Common stock, dividends paid (in dollars per share)		$ 1.10
Variable Rate Dividend \| Subsequent Event \| Forecast
Class of Stock [Line Items]
Common stock, dividends paid (in dollars per share)	$ 0.44

Revenue Recognition

12 Months Ended

Dec. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenue Recognition

We account for revenue in accordance with the Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers, using the modified retrospective method.

The performance obligations that are unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these are wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation as well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation.

We derive revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with the remaining 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 primarily generated from well servicing and abandonment business.

The following is a description of our principal activities from which we generate revenue. Revenues are recognized when a customer obtains control of promised goods or services, in an amount that reflects the consideration we expect to receive in exchange for those goods or services.

Oil, Natural Gas and NGLs

We recognize revenue from the sale of our oil, natural gas and NGL production when delivery has occurred and control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our NGL contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the amount that we expect to receive once we are able to adequately estimate the consideration (i.e., when market prices are known or estimated). Our contracts with customers typically require payment within 30 days following invoicing.

Service Revenue

We recognize service revenue from the well servicing and abandonment business upon delivery of the service to the customer. These services are consumed by our customers when they are provided on their sites. Revenue is recognized as performance obligations have been completed on a daily basis, when all of the proper customer approvals are obtained. We do not have any long-term service contracts; nor do we have revenue expected to be recognized in any future year related to remaining performance obligations or contracts with variable consideration related to undelivered performance obligations. Our contracts with customers typically require payment within 30-60 days following invoicing.

Electricity Sales

The electrical output of our cogeneration facilities that is not used in our operations is sold to the California market based on market pricing, which includes capacity payments. The portion sold from our cogeneration facilities is sold under contracts to California utility companies, based on the market pricing. Revenue is recognized over time when obligations under the terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the electricity. Revenue is measured as the amount of consideration we expect to receive based on average index pricing with payment due the month following delivery. Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on seasonality, which is consistent with how we earn the capacity payment. Capacity payments are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the case of capacity payments. We report electricity revenue as electricity sales on our consolidated statements of operations.

Marketing Revenue

Marketing revenue primarily includes our activities associated with transporting and marketing third-party volumes. These sales are made under the same agreements with the same purchaser as our natural gas sales discussed above. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Revenues are presented excluding costs incurred prior to transferring control of these volumes to the customer, or the costs to purchase these volumes when we are acting as the principal. The revenues and expenses related to the sale and purchase of third-party volumes are presented separately as marketing revenue and marketing expenses on the consolidated statements of operations. In January 2022, we sold our Piceance Colorado operations, which included third-party marketing activities. Historically, these activities accounted for nearly all of our marketing revenues.

Disaggregated Revenue

As a result of adoption of this standard, we are now required to disclose the following information regarding revenue from contracts with customers on a disaggregated basis.


	Year Ended December 31,
	2022		2021		2020
	(in thousands)
Oil sales	$	806,631	$	587,613	$	362,976
Natural gas sales	29,515		32,679		14,041
Natural gas liquids sales	6,303		5,183		1,646
Service revenue	181,400		35,840		—

Electricity sales	30,833		35,636		25,813
Marketing revenues	289		3,921		1,426
Other revenues	479		477		150
Revenues from contracts with customers	1,055,450		701,349		406,052
(Losses) gains on oil and gas sales derivatives	(137,109)		(156,399)		117,781
Total revenues and other	$	918,341	$	544,950	$	523,833

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI https://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

+ Details

Derivatives - Narrative (Details) MMBTU / d in Thousands, MMBTU in Thousands, $ in Millions	1 Months Ended	2 Months Ended	3 Months Ended						8 Months Ended	12 Months Ended
	Jan. 31, 2025 bbl / d $ / MMBoe bbl	Dec. 31, 2023 MMBTU / d MMBTU $ / bbl $ / MMBtu	Mar. 31, 2026 bbl / d $ / MMBoe bbl	Mar. 31, 2025 bbl / d $ / MMBoe bbl	Dec. 31, 2023 $ / bbl $ / MMBtu bbl	Sep. 30, 2023 $ / bbl $ / MMBtu bbl	Jun. 30, 2023 $ / bbl $ / MMBtu bbl	Mar. 31, 2023 $ / bbl $ / MMBtu bbl	Oct. 31, 2023 MMBTU / d MMBTU $ / MMBtu	Dec. 31, 2025 $ / bbl $ / MMBtu bbl	Dec. 31, 2024 $ / bbl $ / MMBtu bbl	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Derivative [Line Items]
Target period to cover operating expenses and fixed charges (up to)												3 years
Target period for fixing the price natural gas purchases used in steam operations (up to)												3 years
Deferred premiums, remaining \| $												$ 5
Net cash paid (received) settlements \| $												$ 88	$ 92	$ (142)
Forecast \| Swaps
Derivative [Line Items]
Hedged volume (bbls) \| bbl					1,196,000	1,211,717	1,387,750	1,385,278		0	3,392,048
Weighted-average price ($/bbl)		76.18			76.18	76.26	77.01	77.15		0	76.12
Forecast \| Producer Collar, Purchased Puts
Derivative [Line Items]
Hedged volume (bbls) \| bbl	3,627		472,500	270,000	368,000	368,000	364,000	360,000		2,212,500	1,098,000
Hedged volume (bbls/d) \| bbl / d	117		5,250	3,000
Forecast \| Producer Collar, Purchased Puts \| Maximum
Derivative [Line Items]
Weighted-average price ($/bbl) \| $ / MMBoe	88.50		82.21	88.35
Forecast \| Producer Collar, Purchased Puts \| Minimum
Derivative [Line Items]
Weighted-average price ($/bbl) \| $ / MMBoe	60.00		60.00	60.00
Forecast \| Put Spread, Long
Derivative [Line Items]
Hedged volume (bbls) \| bbl					644,000	644,000	637,000	630,000		0	1,647,000
Forecast \| Put Spread, Long \| Maximum
Derivative [Line Items]
Weighted-average price ($/bbl)								50
Forecast \| Put Spread, Long \| Minimum
Derivative [Line Items]
Weighted-average price ($/bbl)								40
Forecast \| Put Spread, Short
Derivative [Line Items]
Hedged volume (bbls) \| bbl					92,000	92,000	91,000	90,000		0	366,000
Forecast \| Put Spread, Short \| Maximum
Derivative [Line Items]
Weighted-average price ($/bbl)								50
Forecast \| Put Spread, Short \| Minimum
Derivative [Line Items]
Weighted-average price ($/bbl)								40
Forecast \| NWPL/HH - basis swaps
Derivative [Line Items]
Hedged volume, terminated \| MMBTU		610							4,900
Hedged volume, terminated per day \| MMBTU / d		10							20
Weighted-average price ($/mmbtu) \| $ / MMBtu		1.12			1.12	1.12	1.12	1.12	1.12	0	0

Derivatives (Tables)

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Transactions Resulting in Crude Oil Production and Gas Purchases Hedges

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


	Q1 2023		Q2 2023		Q3 2023		Q4 2023		FY 2024		FY 2025
Brent - Crude Oil Production
Swaps
Hedged volume (bbls)	1,385,278		1,387,750		1,211,717		1,196,000		3,392,048		—
Weighted-average price ($/bbl)	$	77.15	$	77.01	$	76.26	$	76.18	$	76.12	$	—

Put Spreads
Long $50/$40 Put Spread hedged volume (bbls)	630,000		637,000		644,000		644,000		1,647,000		—
Short $50/$40 Put Spread hedged volume (bbls)	90,000		91,000		92,000		92,000		366,000		—
Producer Collars
Hedged volume (bbls)	360,000		364,000		368,000		368,000		1,098,000		2,212,500
Weighted-average price ($/bbl)	$40.00/$106.00		$40.00/$106.00		$40.00/$106.00		$40.00/$106.00		$40.00/$105.00		$58.35/$91.45
Henry Hub - Natural Gas Purchases
Consumer Collars
Hedged volume (mmbtu)	2,110,000		1,820,000		—		—		—		—
Weighted-average price ($/mmbtu)	$4.00/$2.75		$4.00/$2.75		$	—	$	—	$	—	$	—
NWPL - Natural Gas Purchases
Hedged volume (mmbtu)	1,800,000		3,640,000		3,680,000		3,680,000		7,320,000		6,080,000
Weighted-average price ($/mmbtu)	$	6.40	$	5.34	$	5.34	$	5.34	$	4.27	$	4.27
Gas Basis Differentials
NWPL/HH - basis swaps
Hedged volume (mmbtu)	1,800,000		1,820,000		1,840,000		1,840,000		—		—
Weighted-average price ($/mmbtu)	$	1.12	$	1.12	$	1.12	$	1.12	$	—	$	—

Fair Values (Gross and Net) of Outstanding Derivatives

The following tables present the fair values (gross and net) of our outstanding derivatives as of December 31, 2022 and 2021.


	December 31, 2022
	Balance Sheet Classification	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheet		Net Fair Value Presented in the Balance Sheet
	(in thousands)
Assets:
Commodity Contracts	Current assets	$	66,974	$	(30,607)	$	36,367
Commodity Contracts	Non-current assets	39,886		(39,810)		76
Liabilities:
Commodity Contracts	Current liabilities	(61,713)		30,607		(31,106)
Commodity Contracts	Non-current liabilities	(53,452)		39,810		(13,642)
Total derivatives		$	(8,305)	$	—	$	(8,305)


	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)

Gains and Losses of Derivatives Instruments in Statement of Operations

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


	Year Ended December 31,
	2022		2021		2020
	(in thousands)
(Losses) gains on oil and gas sales derivatives	$	(137,109)	$	(156,399)	$	117,781
Gains (losses) on natural gas purchase derivatives	88,795		38,577		(1,035)

Total (losses) gains on derivatives	$	(48,314)	$	(117,822)	$	116,746

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5624163-113959

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5580258-113959

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI https://asc.fasb.org/extlink&oid=125515794&loc=d3e41620-113959

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5579245-113959

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI https://asc.fasb.org/extlink&oid=125515794&loc=d3e41638-113959

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI https://asc.fasb.org/extlink&oid=125515794&loc=d3e41678-113959

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI https://asc.fasb.org/extlink&oid=125515794&loc=d3e41641-113959

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5624171-113959

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5579240-113959

+ Details

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 866	$ 866
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	750,000,000	750,000,000
Common stock, shares issued (in shares)	86,350,771	85,590,417
Common stock, shares outstanding (in shares)	75,767,503	80,007,149
Treasury stock, shares at cost (in shares)	10,583,268	5,583,268

Earnings Per Share - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share, Basic [Abstract]
Net income (loss)	$ 250,168	$ (15,542)	$ (262,895)
Weighted-average shares of common stock outstanding (in shares)	78,517	80,209	79,802
Basic (loss) earnings per share (in dollars per share)	$ 3.19	$ (0.19)	$ (3.29)
Earnings Per Share, Diluted [Abstract]
Net income (loss)	$ 250,168	$ (15,542)	$ (262,895)
Weighted-average shares of common stock outstanding (in shares)	78,517	80,209	79,802
Dilutive effect of potentially dilutive securities (in shares)	4,069	0	0
Weighted-average common shares outstanding - diluted (in shares)	82,586	80,209	79,802
Diluted income (loss) per share (in dollars per share)	$ 3.03	$ (0.19)	$ (3.29)
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs)
Earnings Per Share, Diluted [Abstract]
Potentially dilutive securities (in shares)		3,300	100

Stockholders' Equity - Shares Outstanding (Narrative) (Details) - shares	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Common stock, shares outstanding (in shares)	75,767,503	80,007,149
2017 Omnibus Incentive Plan
Class of Stock [Line Items]
Common stock, shares outstanding (in shares)	75,767,503
Unvested restricted stock units and performance restricted stock units outstanding (in shares)	8,110,302

Debt - Outstanding Debt (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Feb. 28, 2018
Debt Instrument [Line Items]
Long-Term Debt - Principal Amount	$ 400,000,000	$ 400,000,000
Less: Debt Issuance Costs	(4,265,000)	(5,434,000)
Long-Term Debt, net	395,735,000	394,566,000
Unsecured debt \| 2026 Notes
Debt Instrument [Line Items]
Long-Term Debt - Principal Amount	$ 400,000,000	400,000,000
Interest Rate	7.00%		7.00%
Revolving credit facility \| Line of credit \| 2021 RBL Facility
Debt Instrument [Line Items]
Long-Term Debt - Principal Amount	$ 0	$ 0
Variable rate	9.50%	5.30%
Security	90.00%
Revolving credit facility \| Line of credit \| 2022 ABL Facility
Debt Instrument [Line Items]
Long-Term Debt - Principal Amount	$ 0
Variable rate	8.30%

Stockholders' Equity - Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated share-based compensation expense	$ 18	$ 14	$ 15
Tax benefit from compensation expense	2
Performance-based Restricted Stock Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 8
Unrecognized compensation cost, weighted average period of recognition	2 years
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation costs	$ 10
Unrecognized compensation cost, weighted average period of recognition	2 years
Minimum \| Total Stockholder Return Performance Based Restricted Stock Units Granted in 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	0.00%
Minimum \| Total Stockholder Return Performance Based Restricted Stock Units Granted in 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	0.00%
Minimum \| Total Stockholder Return Performance Based Restricted Stock Units Granted In 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	0.00%
Minimum \| Total Cash Return on Invested Capital Performance Based Restricted Stock Units Granted in 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	0.00%
Minimum \| Total Cash Return on Invested Capital Performance Based Restricted Stock Units Granted in 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	0.00%
Minimum \| Total Return on Invested Capital Performance-Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	0.00%
Maximum \| Performance-based Restricted Stock Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Maximum \| Total Stockholder Return Performance Based Restricted Stock Units Granted in 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	250.00%
Maximum \| Total Stockholder Return Performance Based Restricted Stock Units Granted in 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	250.00%
Maximum \| Total Stockholder Return Performance Based Restricted Stock Units Granted In 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	200.00%
Maximum \| Total Cash Return on Invested Capital Performance Based Restricted Stock Units Granted in 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	200.00%
Maximum \| Total Cash Return on Invested Capital Performance Based Restricted Stock Units Granted in 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	200.00%
Maximum \| Total Return on Invested Capital Performance-Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Possible range of shares received over amount granted	200.00%