0001705873-22-000007 | 10-K | XBRL Viewer

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 15,283	$ 80,557
Accounts receivable, net of allowance for doubtful accounts of $866 at December 31, 2021 and $2,215 at December 31, 2020	86,269	52,027
Derivative instruments	0	2,507
Other current assets	45,946	19,400
Total current assets	147,498	154,491
Noncurrent assets:
Oil and natural gas properties	1,537,894	1,412,566
Accumulated depletion and amortization	(340,328)	(235,259)
Total oil and natural gas properties, net	1,197,566	1,177,307
Other property and equipment	140,710	112,145
Accumulated depreciation	(36,927)	(31,368)
Total other property and equipment, net	103,783	80,777
Derivative instruments	1,070	0
Other noncurrent assets	6,562	7,235
Total assets	1,456,479	1,419,810
Current liabilities:
Accounts payable and accrued expenses	157,524	151,985
Derivative instruments	29,625	23,321
Total current liabilities	187,149	175,306
Noncurrent liabilities:
Long-term debt	394,566	393,480
Derivative instruments	18,577	0
Deferred income taxes	1,831	1,011
Asset retirement obligation	143,926	135,192
Other noncurrent liabilities	17,782	785
Commitments and Contingencies - Note 5
Stockholders' Equity:
Common stock ($0.001 par value; 750,000,000 shares authorized; 85,590,417 and 85,041,581 shares issued; and 80,007,149 and 79,929,335 shares outstanding, at December 31, 2021 and December 31, 2020, respectively)	86	85
Additional paid-in capital	912,471	915,877
Treasury stock, at cost (5,583,268 shares at December 31, 2021 and 5,112,246 shares at December 31, 2020)	(52,436)	(49,995)
Retained deficit	(167,473)	(151,931)
Total stockholders' equity	692,648	714,036
Total liabilities and stockholders' equity	$ 1,456,479	$ 1,419,810

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 866	$ 2,215
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)	85,590,417	85,041,581
Common stock, shares outstanding (in shares)	80,007,149	79,929,335
Treasury stock, shares at cost (in shares)	5,583,268	5,112,246

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues and other:
Revenue from Contract with Customer, Excluding Assessed Tax	$ 701,349,000	$ 406,052,000	$ 597,403,000
(Losses) gains on oil and gas sales derivatives	(156,399,000)	117,781,000	(37,998,000)
Total revenues and other	544,950,000	523,833,000	559,405,000
Expenses and other:
Transportation expenses	6,897,000	6,938,000	8,059,000
Marketing expenses	3,811,000	1,380,000	2,073,000
General and administrative expenses	73,106,000	77,696,000	62,643,000
Depreciation, depletion and amortization	144,495,000	139,180,000	106,006,000
Impairment of oil and gas properties	0	289,085,000	51,081,000
Taxes, other than income taxes	46,500,000	35,572,000	40,645,000
(Gains) losses on natural gas purchase derivatives	(38,577,000)	1,035,000	6,957,000
Other operating expense	3,101,000	5,781,000	4,588,000
Total expenses and other	526,868,000	759,623,000	517,836,000
Other (expenses) income:
Interest expense	(31,964,000)	(34,295,000)	(34,234,000)
Other, net	(247,000)	(28,000)	80,000
Total other (expenses) income	(32,211,000)	(34,323,000)	(34,154,000)
Reorganization items, net	0	0	(426,000)
(Loss) income before income taxes	(14,129,000)	(270,113,000)	6,989,000
Income tax expense (benefit)	1,413,000	(7,218,000)	(36,550,000)
Net (loss) income	$ (15,542,000)	$ (262,895,000)	$ 43,539,000
Earnings Per Share [Abstract]
Basic (in dollars per share)	$ (0.19)	$ (3.29)	$ 0.54
Diluted (in dollars per share)	$ (0.19)	$ (3.29)	$ 0.53
Oil, natural gas and natural gas liquid sales
Revenues and other:
Revenue from Contract with Customer, Excluding Assessed Tax	$ 625,475,000	$ 378,663,000	$ 565,596,000
Expenses and other:
Cost of goods sold	236,048,000	186,348,000	216,294,000
Service revenue
Revenues and other:
Revenue from Contract with Customer, Excluding Assessed Tax	35,840,000	0	0
Expenses and other:
Cost of goods sold	28,339,000	0	0
Electricity sales
Revenues and other:
Revenue from Contract with Customer, Excluding Assessed Tax	35,636,000	25,813,000	29,397,000
Expenses and other:
Cost of goods sold	23,148,000	16,608,000	19,490,000
Marketing revenues
Revenues and other:
Revenue from Contract with Customer, Excluding Assessed Tax	3,921,000	1,426,000	2,094,000
Other revenues
Revenues and other:
Revenue from Contract with Customer, Excluding Assessed Tax	$ 477,000	$ 150,000	$ 316,000

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained (Deficit) Earnings
Beginning balance at Dec. 31, 2018	$ 1,006,446	$ 82	$ 914,540	$ (24,218)	$ 116,042
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares withheld for payment of taxes on equity awards	(1,268)		(1,268)
Stock based compensation	8,826		8,826
Purchase of rights to common stock	0		(20,265)	20,265
Purchase of treasury stock	(46,042)			(46,042)
Common stock issued to settle unsecured claims	0	3	(3)
Dividends declared on common stock	(39,053)				(39,053)
Net (loss) income	43,539				43,539
Ending balance at Dec. 31, 2019	972,448	85	901,830	(49,995)	120,528
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares withheld for payment of taxes on equity awards	(1,039)		(1,039)
Stock based compensation	15,086		15,086
Dividends declared on common stock	(9,564)				(9,564)
Net (loss) income	(262,895)				(262,895)
Ending balance at Dec. 31, 2020	714,036	85	915,877	(49,995)	(151,931)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares withheld for payment of taxes on equity awards	(1,543)		(1,543)
Stock based compensation	14,434		14,434
Issuance of common stock	1	1
Purchase of treasury stock	(2,441)			(2,441)
Dividends declared on common stock	(16,297)		(16,297)
Net (loss) income	(15,542)				(15,542)
Ending balance at Dec. 31, 2021	$ 692,648	$ 86	$ 912,471	$ (52,436)	$ (167,473)

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	3 Months Ended									12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Common stock, dividends declared (in dollars per share)	$ 0.06	$ 0.06	$ 0.04	$ 0.04	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.20	$ 0.12	$ 0.48

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flow from operating activities:
Net (loss) income	$ (15,542,000)	$ (262,895,000)	$ 43,539,000
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	144,495,000	139,180,000	106,006,000
Amortization of debt issuance costs	4,430,000	5,351,000	5,059,000
Impairment of oil and gas properties	0	289,085,000	51,081,000
Stock-based compensation expense	13,783,000	14,630,000	8,647,000
Deferred income taxes	819,000	(8,045,000)	(36,778,000)
(Decrease) increase in allowance for doubtful accounts	(1,349,000)	1,112,000	153,000
Other operating expenses	(487,000)	5,083,000	5,518,000
Derivatives activities:
Total losses (gains)	117,822,000	(116,746,000)	44,955,000
Cash settlements on derivatives	(91,634,000)	142,292,000	42,197,000
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(15,614,000)	18,767,000	(14,597,000)
Increase in other assets	(24,824,000)	(2,000)	(5,136,000)
Decrease in accounts payable and accrued expenses	4,045,000	(14,172,000)	(917,000)
Decrease in other liabilities	(13,456,000)	(17,111,000)	(7,898,000)
Net cash provided by operating activities	122,488,000	196,529,000	241,829,000
Capital expenditures:
Capital expenditures	(132,719,000)	(76,480,000)	(211,995,000)
Changes in capital expenditures accruals	482,000	(11,336,000)	(11,159,000)
Acquisitions, net of cash received	(50,568,000)	0	0
Acquisition of properties and equipment and other	(876,000)	(5,981,000)	(2,840,000)
Proceeds received from divestitures	14,025,000	0	0
Proceeds from sale of property and equipment and other	869,000	177,000	969,000
Net cash used in investing activities	(168,787,000)	(93,620,000)	(225,025,000)
Cash flow from financing activities:
Borrowings under RBL credit facility	119,000,000	228,900,000	355,132,000
Repayments on RBL credit facility	(119,000,000)	(230,750,000)	(353,282,000)
Dividends paid on common stock	(11,486,000)	(19,463,000)	(39,157,000)
Purchase of treasury stock	(2,440,000)	0	(46,909,000)
Shares withheld for payment of taxes on equity awards and other	(1,543,000)	(1,039,000)	(1,268,000)
Debt issuance costs	(3,506,000)	0	0
Net cash used in financing activities	(18,975,000)	(22,352,000)	(85,484,000)
Net (decrease) increase in cash and cash equivalents	(65,274,000)	80,557,000	(68,680,000)
Cash and cash equivalents:
Beginning	80,557,000	0	68,680,000
Ending	$ 15,283,000	$ 80,557,000	$ 0

Basis of Presentation and Significant Accounting Policies

12 Months Ended

Dec. 31, 2021

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 (“CJWS”). As the context may require, the “Company”, “we”, “our” or similar words refer to Berry Corp. and its consolidated subsidiary, Berry LLC, and as of October 1, 2021 this also includes CJWS and C&J Management.

As of October 1, 2021, we now operate in two business segments: (i) development and production (ii) well servicing and abandonment. The development and production segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California, which became a reportable segment (wells servicing and abandonment) under U.S. GAAP.

Nature of Business

We are an independent upstream energy company focused on the development and production of onshore, low geologic risk, long-lived conventional oil reserves, primarily located in California, with newly acquired well servicing and abandonment capabilities in California.

Berry Corp. was incorporated under Delaware law in February 2017 and its common stock began trading on NASDAQ under the symbol “bry” in July 2018. Berry Corp. operates through its three wholly owned subsidiaries. Berry LLC owns and operates our oil and gas assets, all of which are located onshore in the United States (the “U.S.”), in California (in the San Joaquin basin) and Utah (in the Uinta basin). In January 2022, we divested our natural gas properties in the Piceance basin of Colorado. Effective as of October 1, 2021, we completed the acquisition of one of the largest upstream well servicing and abandonment businesses in California (the “C&J Well Services Acquisition”), this business is owned and operated through CJWS.

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 exploration and production joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements.

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 Development and Production segment consists of the development and production of onshore, low geologic risk, long-lived conventional oil 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 $2 million in 2021, $1 million in 2020, and $2 million in 2019. 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 $7 million, $6 million and $2 million in 2021, 2020 and 2019, 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, 2021 and 2020, the net capitalized costs attributable to unproved properties was approximately $292 million and $311 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, 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 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.

At year end 2019, we evaluated our proved and unproved natural gas properties in regards to the decline in our expectations of future gas prices. As a result, we recorded a non-cash pre-tax asset impairment charge of $51 million for our Piceance gas properties in Colorado, of which $23 million was for proved properties and other property and equipment and $28 million for unproved properties.

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 cogens, natural gas plants and pipelines, 1 to 10 years 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. Following the October 1, 2021 acquisition of CJWS, we accounted for the various assets acquired and liabilities assumed based on our estimates of their fair values. 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 $144 million and $135 million were included in long term liabilities as of December 31, 2021 and December 31, 2020, respectively, with the remaining current portion included in accrued liabilities:


	Year Ended December 31,
	2021		2020
	(in thousands)
Beginning balance	$	160,192	$	149,227
Liabilities incurred including from acquisitions	1,350		5,919
Settlements and payments	(17,900)		(14,931)

Accretion expense	10,936		9,996
Reduction due to property sales	(22,199)		—
Revisions	31,546		9,981

Ending balance	$	163,925	$	160,192

Revenue Recognition

The majority of the Company's revenue is from the development and production 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”) over the performance period. 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 and CROIC 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

We computed basic and diluted earnings per share (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.

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. For basic EPS, the weighted-average number of common shares 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.

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, 2021, our four largest customers represented approximately 30%, 16%, 14%, and 12% of our sales, which are all customers of the development and production segment. For the year ended

December 31, 2020, our three largest customers represented 44%, 20%, and 12% of our sales. For the year ended December 31, 2019, our three largest customers represented approximately 36%, 24%, and 13% of our sales.

At December 31, 2021, trade accounts receivable from three customers represented approximately 28%, 13%, and 11% of our receivables, which are all customers of the development and production segment. At December 31, 2020, trade accounts receivable from three customers represented approximately 38%, 15%, and 11% of our receivables.

Recently Adopted Accounting Standards

In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which simplified the accounting for income taxes. We adopted these rules in the first quarter of 2021 which did not have a material impact on our financial statements.

New Accounting Standards Issued, But Not Yet Adopted

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is an update to the lease standard providing an optional transition approach for land easements allowing entities to evaluate only new or modified land easements. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842), which provided optional transition relief allowing a prospective approach in applying the new rules by not adjusting comparative period financial information for the effects of the new rules and not requiring disclosures for periods before the effective date. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers. During the second quarter of 2020, this adoption date was further delayed by FASB until fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We will adopt these rules in 2022, which we expect to apply prospectively. We are currently evaluating the impact of the adoption of the new lease standard on our consolidated financial statements, including identifying all leases as defined under the new lease standards.

In March 2020, the FASB issued issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provided optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by the reference rate reform, if certain criteria are met. The optional expedient for contract modifications applies to contract modifications that replace a reference rate affected by the reference rate reform, such as the London Interbank Offered Rate (“LIBOR”). Entities may elect to apply the amendments for contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 through December 31, 2022. To date, these rules have not had any impact on our consolidated financial statements and we continue to assess the future impact of these rules on our consolidated financial statements.

Oil and Natural Gas Properties and Other Property and Equipment

12 Months Ended

Dec. 31, 2021

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,
	2021		2020
	(in thousands)
Proved properties	$	1,246,380	$	1,101,371
Unproved properties	291,514		311,195
Total proved and unproved properties	1,537,894		1,412,566
Less accumulated depletion and amortization	(340,328)		(235,259)
Total proved and unproved properties, net	$	1,197,566	$	1,177,307

Other Property and Equipment

Other property and equipment consisted of the following:


	Year Ended December 31,
	2021		2020
	(in thousands)
Cogens, natural gas plants and pipelines	$	54,237	$	72,999
Vehicles and service equipment(1)	55,521		8,878
Furniture and equipment	22,665		21,515
Land	6,101		6,512
Buildings and leasehold improvements	2,186		2,241
Total other property and equipment	140,710		112,145
Less: accumulated depreciation	(36,927)		(31,368)
Total other property and equipment, net	$	103,783	$	80,777

__________

(1) Includes CJWS vehicles and service equipment in 2021.

Debt

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Debt

The following table summarizes our outstanding debt:


	December 31, 2021		December 31, 2020		Interest Rate	Maturity	Security
	(in thousands)

2021 RBL Facility	$	—	n/a		variable rates 5.3% (2021)	August 26, 2025	Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets
2017 RBL Facility	n/a		$	—	variable rates 4.0% (2020)	July 29, 2022 (Cancelled August 26, 2021)	Mortgage on 85% of Present Value of proven oil and gas reserves and lien on certain other assets
2026 Notes	400,000		400,000		7%	February 15, 2026	Unsecured

Long-Term Debt - Principal Amount	400,000		400,000
Less: Debt Issuance Costs	(5,434)		(6,520)
Long-Term Debt, net	$	394,566	$	393,480

Deferred Financing Costs

We incurred legal and bank fees related to the issuance of debt. At December 31, 2021 and 2020, debt issuance costs for the 2021 RBL Facility and 2017 RBL Facility (each as defined below) reported in “other noncurrent assets” on the balance sheet were approximately $5 million and $7 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. Also in 2021, we incurred approximately $4 million of legal and bank fees related to the issuance of the 2021 RBL Facility. At December 31, 2021 and 2020, 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 $5 million and $7 million, respectively.

For the years ended December 31, 2021, 2020, and 2019, the amortization expense for the 2021 RBL Facility, the 2017 RBL Facility and the 2026 Notes combined, was approximately $4 million, $5 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 amount of each RBL Facility approximated fair value because the interest rates are variable and reflect market rates. The fair value of the 2026 Notes was approximately $400 million and $337 million at December 31, 2021 and 2020, 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 (“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.

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, 2021, our leverage ratio and current ratio were 2.0 to 1.0 and 2.2 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, 2021.

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 if availability is equal to or greater than 20% of the borrowing base, whichever is in effect, 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, 2021, 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.

Corporate Organization

Berry Corp., as Berry LLC’s parent company, has no independent assets or operations and is subject to a passive holding company covenant under the 2021 RBL Facility. Any guarantees of potential future registered debt securities by Berry Corp. or Berry LLC would be full and unconditional. In addition, there are no significant restrictions upon the ability of Berry LLC to distribute funds to Berry Corp. by distribution or loan other than restrictions under the 2021 RBL Facility. None of the assets of Berry Corp. or Berry LLC represent restricted net assets.

The 2021 RBL Facility permits Berry Corp. to make dividends so long as both before and after giving pro forma effect to such distribution, no default or event of defaults exists, availability exceeds 20% of the borrowing base, whichever is in effect, and Berry Corp. demonstrates a pro forma leverage ratio less than or equal to 2.0 to 1.0. The conditions are currently met with significant margin.

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”). In April 2021, we completed our scheduled semi-annual borrowing base redetermination under our 2017 RBL Facility, which resulted in a reaffirmed borrowing base at $200 million. On August 26, 2021, we cancelled the 2017 RBL Facility agreement. There were no borrowings outstanding at the time of cancellation.

Senior Unsecured Notes Offering

In February 2018, we 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.

We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after February 15, 2021. 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 2026 Notes are our 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 notes are fully and unconditionally guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries; whereas Berry LLC, C&J Management and CJWS 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 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 future subsidiaries that do not guarantee the 2026 Notes.

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, 2021.

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
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-URI http://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (g)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
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-Paragraph 1C
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495348-112611

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

+ Details

Derivatives

12 Months Ended

Dec. 31, 2021

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 the hedging requirements of the 2021 RBL Facility, we target covering our operating expenses and a majority of our fixed charges, which includes capital needed to sustain production levels, as well as interest and fixed dividends as applicable, with the oil and gas sales hedges for a period of up to three years out. Additionally, we target fixing the price for a large portion of our natural gas purchases used in our steam operations for up to two 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 purchased oil puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel of Brent. For most 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, 2021 we have net payable deferred premiums of approximately $21 million, which is reflected in the mark-to-market valuation and will be payable beginning in 2022 through 2024, in approximately the same amount each year.

For our 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 barrel 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.

For our sold oil and gas puts, we would make settlement payments for prices below the indicated weighted-average price. No payment would be due for prices above the indicated weighted-average price.

For our sold oil and gas calls, we would make settlement payments for prices above the indicated weighted-average price. No payment would be due for prices below the indicated weighted-average price.

For our purchased gas puts, we would receive settlement payments for prices below the indicated weighted-average price. No payment would be received for prices above the indicated weighted-average price.

For our purchased gas calls, we would receive settlement payments for prices above the indicated weighted-average price. No payment would be received for prices below the indicated weighted-average price.

We use oil and gas swaps and puts to protect our sales against decreases in oil and gas prices. We also use swaps to protect our natural gas purchases against increases in prices. We do not enter into derivative contracts for speculative trading purposes and have not accounted for our derivatives as cash-flow or fair-value hedges. The changes in fair value of these instruments are recorded in current earnings. Gains (losses) on oil and gas sales hedges are classified in the revenues and other section of the statement of operations, while natural gas purchase hedges are included in expenses and other section of the statement of operations.

As of December 31, 2021, we had the following crude oil production and gas purchases hedges.


	Q1 2022		Q2 2022		Q3 2022		Q4 2022		FY 2023		FY 2024
Brent
Swaps
Hedged volume (bbls)	796,500		753,500		736,000		736,000		1,595,750		732,000
Weighted-average price ($/bbl)	$	67.02	$	66.59	$	66.36	$	66.36	$	65.26	$	61.78

Put Spreads
Long $50/$40 Put Spread hedged volume (bbls)	405,000		409,500		414,000		414,000		2,555,000		1,647,000
Short $50/$40 Put Spread hedged volume (bbls)	45,000		45,500		46,000		46,000		365,000		366,000
Collars
Purchased Puts hedged volume (bbls)	270,000		—		—		—		—		—
Weighted-average price ($/bbl)	$	40.00	$	—	$	—	$	—	$	—	$	—
Sold Calls hedged volume (bbls)	270,000		—		—		—		—		—
Weighted-average price ($/bbl)	$	80.00	$	—	$	—	$	—	$	—	$	—
Henry Hub
Purchased Puts
Hedged volume (mmbtu)	1,800,000		—		—		—		—		—
Weighted-average price ($/mmbtu)	$	2.75	$	—	$	—	$	—	$	—	$	—
Purchased Calls
Hedged volume (mmbtu)	2,700,000		2,730,000		2,760,000		2,760,000		10,950,000		9,150,000
Weighted-average price ($/mmbtu)	$	4.00	$	4.00	$	4.00	$	4.00	$	4.00	$	4.00
Sold Puts
Hedged volume (mmbtu)	2,700,000		2,730,000		2,760,000		2,760,000		10,950,000		9,150,000
Weighted-average price ($/mmbtu)	$	2.75	$	2.75	$	2.75	$	2.75	$	2.75	$	2.75

Our long put spread position ($50/$40) is presented in the table above on a gross basis as originally established. Subsequently, we have entered into additional transactions that exactly offset a portion of the original long put spread position and these are shown as short put spread ($50/$40).

In 2022 we added sold fixed price oil swaps (Brent) of 2,000 bbl/d at $80.40 beginning February 2022 through December 2022, 2,000 bbl/d at $85.20 beginning March 2022 through December 2022, and 4,000 bbl/d at $78.42 beginning January 2023 through December 2023. We also added Brent collars of 3,000 bbl/d for calendar year 2023 buying $40.00 put options and selling $106.33 call options.

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, 2021 and 2020.The following tables present the fair values (gross and net) of our outstanding derivatives as of December 31, 2021 and 2020.


	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)


	December 31, 2020
	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	$	15,217	$	(12,710)	$	2,507

Liabilities:
Commodity Contracts	Current liabilities	(36,031)		12,710		(23,321)

Total derivatives		$	(20,814)	$	—	$	(20,814)

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,
	2021		2020		2019
	(in thousands)
(Losses) gains on oil and gas sales derivatives	$	(156,399)	$	117,781	$	(37,998)
Gains (losses) on natural gas purchase derivatives	38,577		(1,035)		(6,957)

Total (losses) gains on derivatives	$	(117,822)	$	116,746	$	(44,955)

For the year ended December 31, 2021, we paid net cash settlements of approximately $92 million. For the years ended December 31, 2020 and 2019 we received net cash scheduled settlements of approximately $142 million and $42 million respectively.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

In the normal course of business, we, or our subsidiary, 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, 2021 and December 31, 2020. 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, 2021, we are not aware of material indemnity claims pending or threatened against us.

We have certain commitments under contracts, including purchase commitments for goods and services. Prior to our 2017 emergence, Berry entered into a Carry and Earning Agreement with Encana, effective June 7, 2006, in connection with our Piceance assets which, among other things, required us to either build a road or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019, we fulfilled the obligation by delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of such access, which we dispute. We settled the lawsuit and the case was dismissed with prejudice on February 1, 2022, which also satisfied the road obligation.

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 January 21, 2021, multiple plaintiffs filed motions in the Torres Lawsuit seeking to be appointed lead plaintiff and lead counsel. After briefing and a stipulation between the remaining movants, the Court appointed Luis Torres and Allia DeAngelis as co-lead plaintiffs on August 18, 2021. On November 1, 2021, the co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these

alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on January 24, 2022; plaintiffs’ opposition is due on March 21, 2022 and Defendants' reply is due on May 16, 2022.

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

Other Commitments

We entered 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. We also entered into a drilling commitment associated with our property acquisition. We also have operating lease agreements mainly for office space. Office rent payments are generally expensed as part of general and administrative expenses and were approximately $2.0 million, $1.5 million and $1.5 million in 2021, 2020 and 2019, respectively.

At December 31, 2021, future net minimum payments for non-cancelable purchase obligations and operating leases (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance and maintenance expense) were as follows:


	2022		2023		2024		2025		2026		Thereafter		Total
	(in thousands)
Processing and transportation contracts(1)	$	9,835	$	10,348	$	9,130	$	8,083	$	8,082	$	51,604	$	97,082
Operating lease obligations	2,279		2,122		1,649		1,551		1,554		936		10,091
Other purchase obligations(2)	20,700		2,400		—		—		—		—		23,100
Total	$	32,814	$	14,870	$	10,779	$	9,634	$	9,636	$	52,540	$	130,273

__________

(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 included a purchase commitment of $6 million to build a road, which was classified as current. In January 2022 the purchase commitment of $6 million was fully resolved without any payment. Additionally, we have 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 April 2023. 49 of those wells are estimated at $14.7 million and are required to be drilled by December 2022.

Stockholders' Equity

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Stockholders' Equity

Cash Dividends

Our Board of Directors approved regular cash dividends on our common stock of $0.04 per share for each of the first and second quarters of 2021 and $0.06 per share for each of the third and fourth quarters of 2021. For the year ended December 31, 2021 we paid approximately $11 million in cash dividends on our common stock. For the year ended December 31, 2020 we paid approximately $19 million in cash dividends on our common stock, which included payment of the dividend declared for the fourth quarter of 2019 and a $0.12 per share cash dividend for the first quarter of 2020. For the year ended December 31, 2019 we declared a cash dividend of $0.12 per share each quarter for a total of $0.48 per share and paid approximately $39 million in cash dividends on our common stock.

Our Board of Directors declared a regular dividend for the first quarter of 2022 at a rate of $0.06 per share on the Company’s outstanding common stock, payable on April 15, 2022 to shareholders of record at the close of business on March 15, 2022.

Common Stock

On February 28, 2017 (the “Effective Date”), 32,920,000 shares of common stock in Berry Corp. were distributed in accordance with our plan of reorganization in the Chapter 11 Proceeding (the “Plan”). In addition 7,080,000 shares of Berry Corp. common stock reserved for future issuance in the event that the holders of such rights chose cash distributions instead. We negotiated with the claimants to settle their claims and in 2019 we issued approximately 2,770,000 shares of Berry Corp. common stock instead of 7,080,000 to resolve these claims for approximately $20 million.

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 the Effective Date, Berry Corp. entered into a registration rights agreement (the “Registration Rights Agreement”) with certain holders of the Unsecured Notes. Subsequently, the registration rights agreement was amended and restated in connection with our IPO.

In accordance with the Registration Rights Agreement, Berry Corp. filed a shelf registration statement with the SEC subsequent to the Effective Date. 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 issued or to be issued by Berry Corp. under the Plan (defined in Note 13), (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, 2021, there were 80,007,149 shares of common stock outstanding. Up to an additional 6,998,815 shares were issuable for unvested restricted stock units and performance restricted stock units (assuming maximum achievement of performance goals) under the Company's 2017 Omnibus Incentive Plan as of December 31, 2021.

Stock Repurchase Program

In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at the time, they authorized repurchases of up to $50 million under the program. In 2018 and 2019, the Company repurchased a total of 5,057,682 shares under the stock repurchase program for approximately $50 million in aggregate. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million available under the repurchase program. We did not repurchase any common stock in 2020. For the year ended

December 31, 2021, we repurchased 471,022 shares at an average price of $5.18 per share for approximately $2 million in the third quarter. All shares repurchased are reflected as treasury stock. Accordingly, as of December 31, 2021, the Company has repurchased a total of 5,528,704 shares under the stock repurchase program for approximately $52 million in aggregate, leaving approximately $48 million authorized and available for future repurchases under the program. 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 Berry Corp. to purchase shares during any period or at all. 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 2021, 0% to 200% of the TSR PSUs granted in prior years and from 0% to 200% of the CROIC PSUs granted in 2021. No CROIC PSUs were granted prior to 2021.

The fair value of the RSUs and CROIC 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.

On June 27, 2018, our board of directors adopted the second amended and restated 2017 Omnibus Incentive Plan (“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 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. The maximum number of shares remaining that may be issued is 1,368,778 as of December 31, 2021.

For the years ended December 31, 2021, 2020, and 2019 the stock-based compensation expense was approximately $14 million, $15 million, and $9 million, respectively. For the years ended December 31, 2021, 2020 and 2019 the stock-based compensation the 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, 2021. The RSUs vest ratably over three years. Unrecognized compensation cost associated with the RSUs at December 31, 2021 was 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, 2020	1,939	$	7.52
Granted	1,833	$	4.65
Vested	(774)	$	7.97
Forfeited	(418)	$	5.54
Non-vested at December 31, 2021	2,580	$	5.67

The table below summarizes the activity relating to the PSUs issued under the Revised Incentive Plan during the year ended December 31, 2021. Unrecognized compensation cost associated with the PSUs at December 31, 2021 is 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, 2020	1,652	$	14.77
Granted	998	$	5.96
Vested	(75)	$	12.75
Forfeited	(490)	$	13.17
Non-vested at December 31, 2021	2,085	$	11.00

Defined Contribution Plan	12 Months Ended
Defined Contribution Plan	Dec. 31, 2021
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. 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 $1.6 million, $1.0 million, and $1.7 million for the years ended December 31, 2021, 2020, and 2019, respectively, under the provisions of the 401(k) plan.

- Definition

The entire disclosure for retirement benefits.

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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Income Taxes

Income taxesThe 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. The key contributor to the change in our effective rate from (523)% in the year ended December 31, 2019 to 2.8% for the year ended December 31, 2020 is due to the valuation allowance recorded in 2020 and the recognition of U.S. federal general business credits in 2019 related to the 2017 and 2018 tax periods.

Income tax expense (benefit) consisted of the following:


	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Current taxes:
Federal	$	—	$	—	$	—
State	581		828		227
Total current taxes	581		828		227
Deferred taxes:
Federal	832		2,653		(36,756)
State	—		(10,699)		(21)
Total deferred taxes	832		(8,046)		(36,777)
Total current and deferred taxes	$	1,413	$	(7,218)	$	(36,550)

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


	Year Ended December 31,
	2021		2020		2019
Federal statutory rate	21.0	%	21.0	%	21.0	%
State, net of federal tax benefit	3.7	%	6.3	%	8.9	%
Nondeductible compensation	(24.5)	%	—	%	—	%
Effect of permanent differences	(4.7)	%	(0.6)	%	0.2	%
Tax credits - Prior Year	(29.5)	%	4.9	%	(546.4)	%
Tax credits - Current Year	21.5	%	1.1	%	—	%
State return to provision	(0.2)	%	(1.1)	%	(6.6)	%

Change in valuation allowance	2.7	%	(28.8)	%	0.0	%
Effective tax rate	(10.0)	%	2.8	%	(522.9)	%

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


	Year Ended December 31,
	2021		2020
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	40,846	$	21,205
Accruals	11,731		14,208
Asset retirement obligations	44,437		43,518
Derivative instruments	12,776		5,654
Tax credits	61,044		62,058

Other	3,551		4,946
Subtotal	174,385		151,589
Valuation allowance	(77,546)		(77,923)
Total deferred tax assets	96,839		73,666
Deferred tax liabilities:
Book tax differences in property basis	(98,670)		(74,677)

Total deferred tax liabilities	(98,670)		(74,677)
Net deferred tax liability	$	(1,831)	$	(1,011)

As of December 31, 2021, the Company had approximately $181 million of federal net operating loss (“NOL”) carryforwards and $49 million of state NOL carryforwards. The vast majority of the federal net operating loss carryovers have no expiration date. State net operating loss carry forwards will expire in varying amounts beginning after taxable year ended 2027. In addition, as of December 31, 2021, the Company had US federal general business tax credit carryforwards totaling $54 million and state tax credits of $9 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. Due to the history of losses in recent years, management continues to believe that it is more likely than not that a large portion of our deferred tax assets would not be realized. Accordingly, we recorded a valuation allowance on our deferred tax assets for the years ended December 31, 2021 and 2020 in the amount of $78 million.


	Year Ended December 31,
	2021		2020
	(in thousands)
Unrecognized tax benefits - January 1	$	—	$	13,892
Prior year - change	—		(13,892)
Current year - change	—		—
Unrecognized tax benefits - December 31	$	—	$	—

During the third quarter 2020, the Internal Revenue Service issued final regulations implementing interest expense deduction limitation rules under section 163(j) of the Internal Revenue Code. The final regulations changed certain rules on the computation and limitation of interest expense amounts and are applicable for tax years beginning on or after November 13, 2020. Early adoption is permitted for tax years beginning after December 31, 2017. We assessed the impact of these regulations being issued in 2020. As a result, we recognized the entirety of its

$14 million of uncertain tax benefits that were recorded as of December 31, 2019. The recognition of these uncertain tax benefits did not affect the effective tax rate. No penalties or interest expense have been accrued on unrecognized tax benefits in the periods presented.

We had no material uncertain tax positions at December 31, 2021 or 2020. 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 2018 thru 2021 federal and 2017 thru 2021 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

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows

12 Months Ended

Dec. 31, 2021

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,
	2021		2020
	(in thousands)
Prepaid expenses	$	26,840	$	3,580

Materials and supplies	9,533		11,666
Prepaid deposits	6,415		12
Oil inventories	2,933		3,490
Other	225		652
Total other current assets	$	45,946	$	19,400

Other non-current assets at December 31, 2021 and December 31, 2020 included approximately $5 million and $7 million of deferred financing costs, net of amortization, respectively. During the year ended December 31, 2021 the allowance for doubtful accounts decreased by approximately $1.3 million, which represented collection of past due amounts and the reversal of that portion of the allowance to the consolidated statements of operations.

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


	Year Ended December 31,
	2021		2020
	(in thousands)
Accounts payable - trade	$	17,699	$	11,055
Accrued expenses	62,962		43,452
Royalties payable	24,816		15,150

Greenhouse gas liability - current portion	7,513		35,554
Taxes other than income tax liability	8,273		10,118
Accrued interest	10,736		10,783
Dividends payable	4,800		—
Asset retirement obligation - current portion	20,000		25,000
Other	725		873
Total accounts payable and accrued expenses	$	157,524	$	151,985

At December 31, 2021 other non-current liabilities included approximately $18 million non-current greenhouse gas liability, which is due 2024. At December 31, 2020 we had no non-current greenhouse gas liability as the entire amount was due in 2021 and thus classified as a current liability in accounts payable and accrued expenses.

Supplemental Information on the Statement of Operations

For the years ended December 31, 2021, 2020, and 2019 other operating expenses were $3 million, $6 million, and $5 million respectively. 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 of 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. For the year ended December 31, 2019 other operating income was $5 million, which mainly consisted of the costs in excess of the liability, due to earlier than anticipated abandonment and spending, related to our long-term abandonment activities and obligation.

Supplemental Cash Flow Information

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


	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Supplemental Disclosures of Significant Non-Cash Operating Activities:
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	$	3,424	$	1,596	$	10,056
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	$	29,211	$	29,962	$	30,720
Income taxes payments (refunds)	$	699	$	222	$	(2)

Cash and cash equivalents consists primarily of highly liquid investments with original maturities of three months or less and are stated at cost, which approximates fair value. As part of our cash management system, we use a controlled disbursement account to fund cash distribution checks presented for payment by the holder. Checks issued but not yet presented to banks may result in overdraft balances for accounting purposes, and if so, are included in accounts payable and accrued expenses in the consolidated balance sheets. Such amounts are immaterial as of December 31, 2021 and December 31, 2020.

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2021

Business Combination and Asset Acquisition [Abstract]

Acquisitions and Divestitures

2021

C&J Well Services Acquisition

On October 1, 2021, we acquired one of the largest well servicing and abandonment business 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 Company's preliminary allocation of the purchase price, including preliminary working capital adjustments, to the estimated fair value of the CJWS net assets is as follows:




	October 1, 2021
	(in thousands)
Accounts receivable	$	17,254
Property and equipment	45,099
Other assets	1,700
Total assets acquired	$	64,053
Accounts payable and accrued expenses assumed	(10,927)

Net assets acquired	$	53,126

The allocation of the purchase price to C&J Well Services net tangible assets and liabilities as of October 1, 2021, is preliminary and subject to revisions to the fair value calculations for the identifiable assets and liabilities. The final purchase price allocation could differ from the preliminary allocation noted in the summary above. The acquired property and equipment is stated at fair value, and depreciation on the acquired property and equipment is computed using the straight-line method over the estimated useful lives of each asset.

The unaudited pro forma information presented below has been prepared to give effect to the C&J Well Services 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 C&J Well Services 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 development and production segment completed the sale of our Placerita Field property in the Ventura Basin in Los Angeles County, California for approximately $14 million. We have recorded a gain on the sale of approximately $2 million.

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.

2019

During 2019 we had various property acquisitions of approximately $2.9 million that individually were not significant.

Earnings Per Share

12 Months Ended

Dec. 31, 2021

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. No incremental RSU or PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the “if-converted” method for the years ended December 31, 2021 and 2020. The incremental RSU and PSU shares of 572,000 for the year ended December 31, 2019 were included in the diluted EPS calculation as their effect was dilutive under the “if-converted” method.


	Year Ended December 31,
	2021		2020		2019
	(in thousands except per share amounts)
Basic EPS calculation
Net (loss) income	$	(15,542)	$	(262,895)	$	43,539




Weighted-average shares of common stock outstanding	80,209		79,802		81,379
Basic (loss) earnings per share	$	(0.19)	$	(3.29)	$	0.54
Diluted EPS calculation
Net (loss) income	$	(15,542)	$	(262,895)	$	43,539




Weighted-average shares of common stock outstanding	80,209		79,802		81,379
Dilutive effect of potentially dilutive securities(1)	—		—		572
Weighted-average common shares outstanding - diluted	80,209		79,802		81,951
Diluted (loss) earnings per share	$	(0.19)	$	(3.29)	$	0.53

__________

(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.

Revenue Recognition

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Revenue Recognition

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

We adopted the practical expedient related to disclosing the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied at the end of the reporting period. 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). Our contracts with customers typically require payment within 30 days following invoicing.

Service Revenue

We recognize service revenue from the upstream 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 majority of the portion sold from certain of 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.

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,
	2021		2020		2019
	(in thousands)
Oil sales	$	587,613	$	362,976	$	543,634
Natural gas sales	32,679		14,041		19,391
Natural gas liquids sales	5,183		1,646		2,571
Service revenue	35,840		—		—

Electricity sales	35,636		25,813		29,397
Marketing revenues	3,921		1,426		2,094
Other revenues	477		150		316
Revenues from contracts with customers	701,349		406,052		597,403
(Losses) gains on oil and gas sales derivatives	(156,399)		117,781		(37,998)
Total revenues and other	$	544,950	$	523,833	$	559,405

- 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
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+ Details

Segment Information

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Segment Information

As of October 1, 2021, we have operated in two business segments: (i) development and production (ii) well servicing and abandonment. The development and production segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of an upstream well servicing and abandonment 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 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, 2021
	Development & Production		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)









Revenues - excluding hedges	$	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

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, 2021
	Development & Production		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	—		1,335		1,400		2,735

Adjusted EBITDA	$	251,146	$	4,310	$	(43,310)	$	212,146

- 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.

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+ Details

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2021
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events 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 no material impact to the financial statements. 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 700 boe/d.

Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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 exploration and production joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements.
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 Development and Production segment consists of the development and production of onshore, low geologic risk, long-lived conventional oil 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 $2 million in 2021, $1 million in 2020, and $2 million in 2019. 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 $7 million, $6 million and $2 million in 2021, 2020 and 2019, 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, 2021 and 2020, the net capitalized costs attributable to unproved properties was approximately $292 million and $311 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, 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 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. At year end 2019, we evaluated our proved and unproved natural gas properties in regards to the decline in our expectations of future gas prices. As a result, we recorded a non-cash pre-tax asset impairment charge of $51 million for our Piceance gas properties in Colorado, of which $23 million was for proved properties and other property and equipment and $28 million for unproved properties.
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 cogens, natural gas plants and pipelines, 1 to 10 years 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. Following the October 1, 2021 acquisition of CJWS, we accounted for the various assets acquired and liabilities assumed based on our estimates of their fair values. 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 development and production 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 606, Revenue from Contracts with Customers, using the modified retrospective method. We adopted the practical expedient related to disclosing the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied at the end of the reporting period. 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). Our contracts with customers typically require payment within 30 days following invoicing. Service Revenue We recognize service revenue from the upstream 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 majority of the portion sold from certain of 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.
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”) over the performance period. 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 and CROIC 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 We computed basic and diluted earnings per share (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. 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. For basic EPS, the weighted-average number of common shares 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.
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 Standards In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which simplified the accounting for income taxes. We adopted these rules in the first quarter of 2021 which did not have a material impact on our financial statements. New Accounting Standards Issued, But Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), which is an update to the lease standard providing an optional transition approach for land easements allowing entities to evaluate only new or modified land easements. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842), which provided optional transition relief allowing a prospective approach in applying the new rules by not adjusting comparative period financial information for the effects of the new rules and not requiring disclosures for periods before the effective date. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers. During the second quarter of 2020, this adoption date was further delayed by FASB until fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We will adopt these rules in 2022, which we expect to apply prospectively. We are currently evaluating the impact of the adoption of the new lease standard on our consolidated financial statements, including identifying all leases as defined under the new lease standards. In March 2020, the FASB issued issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provided optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by the reference rate reform, if certain criteria are met. The optional expedient for contract modifications applies to contract modifications that replace a reference rate affected by the reference rate reform, such as the London Interbank Offered Rate (“LIBOR”). Entities may elect to apply the amendments for contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 through December 31, 2022. To date, these rules have not had any impact on our consolidated financial statements and we continue to assess the future impact of these rules on our consolidated financial statements.

Basis of Presentation and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Activity in ARO Account


	Year Ended December 31,
	2021		2020
	(in thousands)
Beginning balance	$	160,192	$	149,227
Liabilities incurred including from acquisitions	1,350		5,919
Settlements and payments	(17,900)		(14,931)

Accretion expense	10,936		9,996
Reduction due to property sales	(22,199)		—
Revisions	31,546		9,981

Ending balance	$	163,925	$	160,192

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

12 Months Ended

Dec. 31, 2021

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,
	2021		2020
	(in thousands)
Proved properties	$	1,246,380	$	1,101,371
Unproved properties	291,514		311,195
Total proved and unproved properties	1,537,894		1,412,566
Less accumulated depletion and amortization	(340,328)		(235,259)
Total proved and unproved properties, net	$	1,197,566	$	1,177,307

Schedule of Other Property and Equipment

Other property and equipment consisted of the following:


	Year Ended December 31,
	2021		2020
	(in thousands)
Cogens, natural gas plants and pipelines	$	54,237	$	72,999
Vehicles and service equipment(1)	55,521		8,878
Furniture and equipment	22,665		21,515
Land	6,101		6,512
Buildings and leasehold improvements	2,186		2,241
Total other property and equipment	140,710		112,145
Less: accumulated depreciation	(36,927)		(31,368)
Total other property and equipment, net	$	103,783	$	80,777

__________

(1) Includes CJWS vehicles and service equipment in 2021.

Debt (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Schedule of Outstanding Debt

The following table summarizes our outstanding debt:


	December 31, 2021		December 31, 2020		Interest Rate	Maturity	Security
	(in thousands)

2021 RBL Facility	$	—	n/a		variable rates 5.3% (2021)	August 26, 2025	Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets
2017 RBL Facility	n/a		$	—	variable rates 4.0% (2020)	July 29, 2022 (Cancelled August 26, 2021)	Mortgage on 85% of Present Value of proven oil and gas reserves and lien on certain other assets
2026 Notes	400,000		400,000		7%	February 15, 2026	Unsecured

Long-Term Debt - Principal Amount	400,000		400,000
Less: Debt Issuance Costs	(5,434)		(6,520)
Long-Term Debt, net	$	394,566	$	393,480

Derivatives (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Transactions Resulting in Crude Oil Production and Gas Purchases Hedges

As of December 31, 2021, we had the following crude oil production and gas purchases hedges.


	Q1 2022		Q2 2022		Q3 2022		Q4 2022		FY 2023		FY 2024
Brent
Swaps
Hedged volume (bbls)	796,500		753,500		736,000		736,000		1,595,750		732,000
Weighted-average price ($/bbl)	$	67.02	$	66.59	$	66.36	$	66.36	$	65.26	$	61.78

Put Spreads
Long $50/$40 Put Spread hedged volume (bbls)	405,000		409,500		414,000		414,000		2,555,000		1,647,000
Short $50/$40 Put Spread hedged volume (bbls)	45,000		45,500		46,000		46,000		365,000		366,000
Collars
Purchased Puts hedged volume (bbls)	270,000		—		—		—		—		—
Weighted-average price ($/bbl)	$	40.00	$	—	$	—	$	—	$	—	$	—
Sold Calls hedged volume (bbls)	270,000		—		—		—		—		—
Weighted-average price ($/bbl)	$	80.00	$	—	$	—	$	—	$	—	$	—
Henry Hub
Purchased Puts
Hedged volume (mmbtu)	1,800,000		—		—		—		—		—
Weighted-average price ($/mmbtu)	$	2.75	$	—	$	—	$	—	$	—	$	—
Purchased Calls
Hedged volume (mmbtu)	2,700,000		2,730,000		2,760,000		2,760,000		10,950,000		9,150,000
Weighted-average price ($/mmbtu)	$	4.00	$	4.00	$	4.00	$	4.00	$	4.00	$	4.00
Sold Puts
Hedged volume (mmbtu)	2,700,000		2,730,000		2,760,000		2,760,000		10,950,000		9,150,000
Weighted-average price ($/mmbtu)	$	2.75	$	2.75	$	2.75	$	2.75	$	2.75	$	2.75

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, 2021 and 2020.


	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)


	December 31, 2020
	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	$	15,217	$	(12,710)	$	2,507

Liabilities:
Commodity Contracts	Current liabilities	(36,031)		12,710		(23,321)

Total derivatives		$	(20,814)	$	—	$	(20,814)

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,
	2021		2020		2019
	(in thousands)
(Losses) gains on oil and gas sales derivatives	$	(156,399)	$	117,781	$	(37,998)
Gains (losses) on natural gas purchase derivatives	38,577		(1,035)		(6,957)

Total (losses) gains on derivatives	$	(117,822)	$	116,746	$	(44,955)

- 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.

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+ Details

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Future Net Minimum Payments for Purchase Obligations and Operating Leases


	2022		2023		2024		2025		2026		Thereafter		Total
	(in thousands)
Processing and transportation contracts(1)	$	9,835	$	10,348	$	9,130	$	8,083	$	8,082	$	51,604	$	97,082
Operating lease obligations	2,279		2,122		1,649		1,551		1,554		936		10,091
Other purchase obligations(2)	20,700		2,400		—		—		—		—		23,100
Total	$	32,814	$	14,870	$	10,779	$	9,634	$	9,636	$	52,540	$	130,273

__________

Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2021

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, 2020	1,939	$	7.52
Granted	1,833	$	4.65
Vested	(774)	$	7.97
Forfeited	(418)	$	5.54
Non-vested at December 31, 2021	2,580	$	5.67

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, 2020	1,652	$	14.77
Granted	998	$	5.96
Vested	(75)	$	12.75
Forfeited	(490)	$	13.17
Non-vested at December 31, 2021	2,085	$	11.00

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income tax expense (benefit) consisted of the following:


	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Current taxes:
Federal	$	—	$	—	$	—
State	581		828		227
Total current taxes	581		828		227
Deferred taxes:
Federal	832		2,653		(36,756)
State	—		(10,699)		(21)
Total deferred taxes	832		(8,046)		(36,777)
Total current and deferred taxes	$	1,413	$	(7,218)	$	(36,550)

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,
	2021		2020		2019
Federal statutory rate	21.0	%	21.0	%	21.0	%
State, net of federal tax benefit	3.7	%	6.3	%	8.9	%
Nondeductible compensation	(24.5)	%	—	%	—	%
Effect of permanent differences	(4.7)	%	(0.6)	%	0.2	%
Tax credits - Prior Year	(29.5)	%	4.9	%	(546.4)	%
Tax credits - Current Year	21.5	%	1.1	%	—	%
State return to provision	(0.2)	%	(1.1)	%	(6.6)	%

Change in valuation allowance	2.7	%	(28.8)	%	0.0	%
Effective tax rate	(10.0)	%	2.8	%	(522.9)	%

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,
	2021		2020
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	40,846	$	21,205
Accruals	11,731		14,208
Asset retirement obligations	44,437		43,518
Derivative instruments	12,776		5,654
Tax credits	61,044		62,058

Other	3,551		4,946
Subtotal	174,385		151,589
Valuation allowance	(77,546)		(77,923)
Total deferred tax assets	96,839		73,666
Deferred tax liabilities:
Book tax differences in property basis	(98,670)		(74,677)

Total deferred tax liabilities	(98,670)		(74,677)
Net deferred tax liability	$	(1,831)	$	(1,011)

Summary of Unrecognized Tax Benefits


	Year Ended December 31,
	2021		2020
	(in thousands)
Unrecognized tax benefits - January 1	$	—	$	13,892
Prior year - change	—		(13,892)
Current year - change	—		—
Unrecognized tax benefits - December 31	$	—	$	—

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

12 Months Ended

Dec. 31, 2021

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,
	2021		2020
	(in thousands)
Prepaid expenses	$	26,840	$	3,580

Materials and supplies	9,533		11,666
Prepaid deposits	6,415		12
Oil inventories	2,933		3,490
Other	225		652
Total other current assets	$	45,946	$	19,400

Schedule of Accounts Payable and Accrued Expenses

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


	Year Ended December 31,
	2021		2020
	(in thousands)
Accounts payable - trade	$	17,699	$	11,055
Accrued expenses	62,962		43,452
Royalties payable	24,816		15,150

Greenhouse gas liability - current portion	7,513		35,554
Taxes other than income tax liability	8,273		10,118
Accrued interest	10,736		10,783
Dividends payable	4,800		—
Asset retirement obligation - current portion	20,000		25,000
Other	725		873
Total accounts payable and accrued expenses	$	157,524	$	151,985

Supplemental Cash Flow Information

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


	Year Ended December 31,
	2021		2020		2019
	(in thousands)
Supplemental Disclosures of Significant Non-Cash Operating Activities:
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	$	3,424	$	1,596	$	10,056
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	$	29,211	$	29,962	$	30,720
Income taxes payments (refunds)	$	699	$	222	$	(2)

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2021

Business Combination and Asset Acquisition [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The Company's preliminary allocation of the purchase price, including preliminary working capital adjustments, to the estimated fair value of the CJWS net assets is as follows:




	October 1, 2021
	(in thousands)
Accounts receivable	$	17,254
Property and equipment	45,099
Other assets	1,700
Total assets acquired	$	64,053
Accounts payable and accrued expenses assumed	(10,927)

Net assets acquired	$	53,126

Summary of Pro Forma Information


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

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Schedule of Earnings Per Share


	Year Ended December 31,
	2021		2020		2019
	(in thousands except per share amounts)
Basic EPS calculation
Net (loss) income	$	(15,542)	$	(262,895)	$	43,539




Weighted-average shares of common stock outstanding	80,209		79,802		81,379
Basic (loss) earnings per share	$	(0.19)	$	(3.29)	$	0.54
Diluted EPS calculation
Net (loss) income	$	(15,542)	$	(262,895)	$	43,539




Weighted-average shares of common stock outstanding	80,209		79,802		81,379
Dilutive effect of potentially dilutive securities(1)	—		—		572
Weighted-average common shares outstanding - diluted	80,209		79,802		81,951
Diluted (loss) earnings per share	$	(0.19)	$	(3.29)	$	0.53

__________(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

Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2021

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,
	2021		2020		2019
	(in thousands)
Oil sales	$	587,613	$	362,976	$	543,634
Natural gas sales	32,679		14,041		19,391
Natural gas liquids sales	5,183		1,646		2,571
Service revenue	35,840		—		—

Electricity sales	35,636		25,813		29,397
Marketing revenues	3,921		1,426		2,094
Other revenues	477		150		316
Revenues from contracts with customers	701,349		406,052		597,403
(Losses) gains on oil and gas sales derivatives	(156,399)		117,781		(37,998)
Total revenues and other	$	544,950	$	523,833	$	559,405

Segment Information (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Schedule of Segment Information


	Year Ended December 31, 2021
	Development & Production		Well Servicing and Abandonment		Corporate/Eliminations		Consolidated Company
	(in thousands)









Revenues - excluding hedges	$	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

Adjusted EBITDA Reconciliation


	Year Ended December 31, 2021
	Development & Production		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	—		1,335		1,400		2,735

Adjusted EBITDA	$	251,146	$	4,310	$	(43,310)	$	212,146

Basis of Presentation and Significant Accounting Policies - Narrative (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2021 USD ($) subsidiary segment	Mar. 31, 2020 USD ($)	Dec. 31, 2021 USD ($) subsidiary segment	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Public Utilities, General Disclosures [Line Items]
Number of subsidiaries \| subsidiary	3		3
Number of reportable segments \| segment	2		2
Capitalized interest			$ 2,000,000	$ 1,000,000	$ 2,000,000
Capitalized exploratory well costs	$ 0		0	0	0
Capitalized overhead	7,000,000		7,000,000	6,000,000	2,000,000
Net capitalized costs attributable to unproved properties	292,000,000		292,000,000	311,000,000
Impairment of oil and gas properties			0	289,085,000	$ 51,081,000
Asset retirement obligation, noncurrent	$ 143,926,000		$ 143,926,000	$ 135,192,000
Largest customers \| Sales \| Customer one
Public Utilities, General Disclosures [Line Items]
Concentration risk				44.00%	36.00%
Largest customers \| Sales \| Customer one \| Development & Production
Public Utilities, General Disclosures [Line Items]
Concentration risk			30.00%
Largest customers \| Sales \| Customer two
Public Utilities, General Disclosures [Line Items]
Concentration risk				20.00%	24.00%
Largest customers \| Sales \| Customer two \| Development & Production
Public Utilities, General Disclosures [Line Items]
Concentration risk			16.00%
Largest customers \| Sales \| Customer three
Public Utilities, General Disclosures [Line Items]
Concentration risk				12.00%	13.00%
Largest customers \| Sales \| Customer three \| Development & Production
Public Utilities, General Disclosures [Line Items]
Concentration risk			14.00%
Largest customers \| Sales \| Customer four \| Development & Production
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				38.00%
Largest customers \| Trade accounts receivable \| Customer one \| Development & Production
Public Utilities, General Disclosures [Line Items]
Concentration risk			28.00%
Largest customers \| Trade accounts receivable \| Customer two
Public Utilities, General Disclosures [Line Items]
Concentration risk				15.00%
Largest customers \| Trade accounts receivable \| Customer two \| Development & Production
Public Utilities, General Disclosures [Line Items]
Concentration risk			13.00%
Largest customers \| Trade accounts receivable \| Customer three
Public Utilities, General Disclosures [Line Items]
Concentration risk				11.00%
Largest customers \| Trade accounts receivable \| Customer three \| Development & Production
Public Utilities, General Disclosures [Line Items]
Concentration risk			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
Proved Oil and Gas Properties
Public Utilities, General Disclosures [Line Items]
Impairment of oil and gas properties		$ 289,000,000			$ 23,000,000
Unproved Oil and Gas Properties
Public Utilities, General Disclosures [Line Items]
Impairment of oil and gas properties				$ 0	$ 28,000,000

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, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 160,192	$ 149,227
Liabilities incurred including from acquisitions	$ 6,000	1,350	5,919
Settlements and payments		(17,900)	(14,931)
Accretion expense		10,936	9,996
Reduction due to property sales		(22,199)	0
Revisions		31,546	9,981
Ending balance		$ 163,925	$ 160,192

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, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Proved properties	$ 1,246,380	$ 1,101,371
Unproved properties	291,514	311,195
Oil and natural gas properties	1,537,894	1,412,566
Less accumulated depletion and amortization	(340,328)	(235,259)
Total oil and natural gas properties, net	$ 1,197,566	$ 1,177,307

Oil and Natural Gas Properties and Other Property and Equipment - Other Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 140,710	$ 112,145
Less accumulated depreciation	(36,927)	(31,368)
Total other property and equipment, net	103,783	80,777
Cogens, natural gas plants and pipelines
Property, Plant and Equipment [Line Items]
Other property and equipment	54,237	72,999
Vehicles and service equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	55,521	8,878
Furniture and equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	22,665	21,515
Land
Property, Plant and Equipment [Line Items]
Other property and equipment	6,101	6,512
Buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 2,186	$ 2,241

Debt - Outstanding Debt (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-Term Debt - Principal Amount	$ 400,000,000	$ 400,000,000
Less: Debt Issuance Costs	(5,434,000)	(6,520,000)
Long-Term Debt, net	394,566,000	393,480,000
Medium-term notes \| 2026 Notes
Debt Instrument [Line Items]
Long-Term Debt - Principal Amount	400,000,000	400,000,000
Revolving credit facility \| Line of credit \| 2021 RBL Facility
Debt Instrument [Line Items]
Long-Term Debt - Principal Amount	$ 0
Variable rate	5.30%
Security	90.00%
Revolving credit facility \| Line of credit \| 2017 RBL Facility
Debt Instrument [Line Items]
Long-Term Debt - Principal Amount		$ 0
Variable rate		4.00%
Security	85.00%
Revolving credit facility \| Line of credit \| 2026 Notes
Debt Instrument [Line Items]
Variable rate	7.00%

Debt - Narrative (Details)		1 Months Ended	3 Months Ended	12 Months Ended
Debt - Narrative (Details)	Aug. 26, 2021 USD ($)	Feb. 28, 2018 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Apr. 30, 2021 USD ($)	Feb. 27, 2020 USD ($)	Jul. 31, 2017 USD ($)
Debt Instrument [Line Items]
Debt issuance costs for the 2026 Senior Unsecured Notes			$ 5,434,000	$ 5,434,000	$ 6,520,000
Amortization of debt issuance costs				$ 4,430,000	5,351,000	$ 5,059,000
Leverage ratio at period end			2	2
Current ratio at period end			2.2	2.2
Bond repurchase program, authorized amount								$ 75,000,000
Unsecured debt \| 2026 Notes
Debt Instrument [Line Items]
Fair value of debt			$ 400,000,000	$ 400,000,000	337,000,000
Principal amount of debt issued		$ 400,000,000
Interest rate		7.00%
Net proceeds from issuance of debt		$ 391,000,000
Redemption price in event of change in control		101.00%
Letters of credit \| Line of credit \| 2021 RBL Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 20,000,000
Revolving credit facility \| Line of credit \| RBL Facility
Debt Instrument [Line Items]
Debt issuance costs for the RBL Facility			5,000,000	5,000,000	7,000,000
Revolving credit facility \| Line of credit \| 2021 RBL Facility
Debt Instrument [Line Items]
Professional Fees			4,000,000
Maximum borrowing capacity	500,000,000
Borrowing base elected	$ 200,000,000		$ 200,000,000	$ 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
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
Free cash flow percentage	100.00%
Value of proven oil and gas reserves serving as collateral (at least)			90.00%	90.00%
Available borrowing capacity			$ 193,000,000	$ 193,000,000
Letters of credit outstanding			$ 7,000,000	$ 7,000,000
Revolving credit facility \| Line of credit \| 2017 RBL Facility
Debt Instrument [Line Items]
Maximum borrowing capacity									$ 1,500,000,000
Borrowing base elected							$ 200,000,000
Value of proven oil and gas reserves serving as collateral (at least)			85.00%	85.00%
Borrowings outstanding	$ 0
Revolving credit facility \| Line of credit \| RBL Facility 2017
Debt Instrument [Line Items]
Unamortized debt issuance costs				$ 3,000,000
Base Rate \| Minimum \| Revolving credit facility \| Line of credit \| 2021 RBL Facility
Debt Instrument [Line Items]
Applicable margin	2.00%
Base Rate \| Maximum \| Revolving credit facility \| Line of credit \| 2021 RBL Facility
Debt Instrument [Line Items]
Applicable margin	3.00%
Benchmark Rate \| Minimum \| Revolving credit facility \| Line of credit \| 2021 RBL Facility
Debt Instrument [Line Items]
Applicable margin	3.00%
Benchmark Rate \| Maximum \| Revolving credit facility \| Line of credit \| 2021 RBL Facility
Debt Instrument [Line Items]
Applicable margin	4.00%
Interest expense
Debt Instrument [Line Items]
Amortization of debt issuance costs				$ 4,000,000	$ 5,000,000	$ 5,000,000

Derivatives - Narrative (Details) $ in Thousands	3 Months Ended				10 Months Ended	11 Months Ended	12 Months Ended
Derivatives - Narrative (Details) $ in Thousands	Dec. 31, 2022 $ / bbl bbl	Sep. 30, 2022 $ / bbl bbl	Jun. 30, 2022 $ / bbl bbl	Mar. 31, 2022 $ / bbl bbl	Dec. 31, 2022 $ / bbl bbl	Dec. 31, 2022 $ / bbl bbl	Dec. 31, 2024 $ / bbl bbl	Dec. 31, 2023 $ / bbl bbl	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Jan. 01, 2023 $ / bbl	Mar. 01, 2022 $ / bbl	Feb. 01, 2022 $ / bbl
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)									2 years
Deferred premiums, remaining \| $									$ 21,000
Paid net cash settlements \| $									92,000
Net cash paid for scheduled derivative settlements \| $									$ 87,625	$ (142,000)	$ (42,000)
Swaps \| Subsequent Event
Derivative [Line Items]
Hedged volume (bbls) \| bbl					2,000	2,000		4,000
Weighted-average price ($/bbl)												78.42	85.20	80.40
Producer Collar, Sold Calls \| Subsequent Event
Derivative [Line Items]
Weighted-average price ($/bbl)												106.33
Producer Collar, Purchased Puts \| Subsequent Event
Derivative [Line Items]
Hedged volume (bbls) \| bbl								3,000
Weighted-average price ($/bbl)												40.00
Forecast \| Swaps
Derivative [Line Items]
Hedged volume (bbls) \| bbl	736,000	736,000	753,500	796,500			732,000	1,595,750
Weighted-average price ($/bbl)	66.36	66.36	66.59	67.02	66.36	66.36	61.78	65.26
Forecast \| Producer Collar, Sold Calls
Derivative [Line Items]
Hedged volume (bbls) \| bbl	0	0	0	270,000			0	0
Weighted-average price ($/bbl)	0	0	0	80.00	0	0	0	0
Forecast \| Producer Collar, Purchased Puts
Derivative [Line Items]
Hedged volume (bbls) \| bbl	0	0	0	270,000			0	0
Weighted-average price ($/bbl)	0	0	0	40.00	0	0	0	0

Derivatives - Derivative Transactions Resulting in Crude Oil Production and Gas Purchases Hedges (Details) - Forecast MMBTU in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2022 MMBTU $ / bbl $ / MMBtu bbl	Sep. 30, 2022 MMBTU $ / bbl $ / MMBtu bbl	Jun. 30, 2022 MMBTU $ / bbl $ / MMBtu bbl	Mar. 31, 2022 MMBTU $ / bbl $ / MMBtu bbl	Dec. 31, 2024 MMBTU $ / bbl $ / MMBtu bbl	Dec. 31, 2023 MMBTU $ / bbl $ / MMBtu bbl
Swaps
Derivative [Line Items]
Hedged volume (bbls)	736,000	736,000	753,500	796,500	732,000	1,595,750
Weighted-average price ($/bbl) \| $ / bbl	66.36	66.36	66.59	67.02	61.78	65.26
Put Spread, Long
Derivative [Line Items]
Hedged volume (bbls)	414,000	414,000	409,500	405,000	1,647,000	2,555,000
Put Spread, Short
Derivative [Line Items]
Hedged volume (bbls)	46,000	46,000	45,500	45,000	366,000	365,000
Producer Collar, Purchased Puts
Derivative [Line Items]
Hedged volume (bbls)	0	0	0	270,000	0	0
Weighted-average price ($/bbl) \| $ / bbl	0	0	0	40.00	0	0
Producer Collar, Sold Calls
Derivative [Line Items]
Hedged volume (bbls)	0	0	0	270,000	0	0
Weighted-average price ($/bbl) \| $ / bbl	0	0	0	80.00	0	0
Purchased Puts
Derivative [Line Items]
Hedged volume (mmbtu) \| MMBTU	0	0	0	1,800	0	0
Weighted-average price ($/mmbtu) \| $ / MMBtu	0	0	0	2.75	0	0
Purchased Calls
Derivative [Line Items]
Hedged volume (mmbtu) \| MMBTU	2,760	2,760	2,730	2,700	9,150	10,950
Weighted-average price ($/mmbtu) \| $ / MMBtu	4.00	4.00	4.00	4.00	4.00	4.00
Sold Puts
Derivative [Line Items]
Hedged volume (mmbtu) \| MMBTU	2,760	2,760	2,730	2,700	9,150	10,950
Weighted-average price ($/mmbtu) \| $ / MMBtu	2.75	2.75	2.75	2.75	2.75	2.75

Derivatives - Fair Values (Gross and Net) of Outstanding Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivative Liability [Abstract]
Derivative Assets (Liabilities), at Fair Value, Net, Total	$ (47,132)	$ (20,814)
Commodity Contracts \| Current assets
Derivative Asset [Abstract]
Gross Amounts Recognized at Fair Value	5,360	15,217
Gross Amounts Offset in the Balance Sheet	(5,360)	(12,710)
Derivative Asset, Total	0	2,507
Commodity Contracts \| Non-current assets
Derivative Asset [Abstract]
Gross Amounts Recognized at Fair Value	29,828
Gross Amounts Offset in the Balance Sheet	(28,758)
Derivative Asset, Total	1,070
Commodity Contracts \| Current liabilities
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	(34,985)	(36,031)
Derivative Liability, Fair Value, Gross Asset	5,360	12,710
Derivative Liability	(29,625)	$ (23,321)
Commodity Contracts \| Non-current liabilities
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	(47,335)
Derivative Liability, Fair Value, Gross Asset	28,758
Derivative Liability	$ (18,577)

Derivatives - Gains and Losses of Derivatives Instruments in Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
(Losses) gains on derivatives	$ (117,822)	$ 116,746	$ (44,955)
Oil, natural gas and natural gas liquid sales
Derivative [Line Items]
(Losses) gains on derivatives	(156,399)	117,781	(37,998)
Natural gas sales
Derivative [Line Items]
(Losses) gains on derivatives	$ 38,577	$ (1,035)	$ (6,957)

Derivatives (Parenthetical) (Details) - Forecast	Mar. 31, 2022 $ / bbl
Put Spread, Long \| Maximum
Derivative [Line Items]
Weighted-average price ($/bbl)	50
Put Spread, Long \| Minimum
Derivative [Line Items]
Weighted-average price ($/bbl)	40
Put Spread, Short \| Maximum
Derivative [Line Items]
Weighted-average price ($/bbl)	50
Put Spread, Short \| Minimum
Derivative [Line Items]
Weighted-average price ($/bbl)	40

Commitments and Contingencies - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments under contracts	$ 6.0
Office rent expense	$ 2.0	$ 1.5	$ 1.5

Commitments and Contingencies - Future Net Minimum Payments for Purchase Obligations and Operating Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($) well
Operating lease obligations
2022	$ 2,279
2023	2,122
2024	1,649
2025	1,551
2026	1,554
Thereafter	936
Total	10,091
Total
2022	32,814
2023	14,870
2024	10,779
2025	9,634
2026	9,636
Thereafter	52,540
Total	130,273
Commitments under contracts	$ 6,000
Drilling commitment, number of wells \| well	57
Drilling commitment, estimated total cost	$ 17,100
Drilling commitment, number of wells required to be drilled by next fiscal year \| well	49
Drilling commitment, required to be paid next year	$ 14,700
Processing, transportation and storage contracts
Minimum purchase obligations
2022	9,835
2023	10,348
2024	9,130
2025	8,083
2026	8,082
Thereafter	51,604
Total	97,082
Other purchase obligations
Minimum purchase obligations
2022	20,700
2023	2,400
2024	0
2025	0
2026	0
Thereafter	0
Total	$ 23,100

Stockholders' Equity - Cash Dividend (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended										12 Months Ended
	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Class of Stock [Line Items]
Common stock, dividends declared (in dollars per share)		$ 0.06	$ 0.06	$ 0.04	$ 0.04	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.12	$ 0.20	$ 0.12	$ 0.48
Dividends paid on common stock											$ 11,486	$ 19,463	$ 39,157
Subsequent Event
Class of Stock [Line Items]
Common stock, dividends declared (in dollars per share)	$ 0.06

Stockholders' Equity - Common Stock (Narrative) (Details) $ in Millions		12 Months Ended
	Feb. 28, 2017 vote shares	Dec. 31, 2019 USD ($)	Mar. 31, 2019 shares
Class of Stock [Line Items]
Number of voting rights per share \| vote	1
Common Stock
Class of Stock [Line Items]
Issuance of shares (in shares)	32,920,000
Common stock reserved to settle claims of unsecured creditors (in shares)	7,080,000
Shares issued to settle claims (in shares)			2,770,000
Payments for repurchase of common stock, subject to claims \| $		$ 20

Stockholders' Equity - Shares Outstanding (Narrative) (Details) - shares	Dec. 31, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Common stock, shares outstanding (in shares)	80,007,149	79,929,335
2017 Omnibus Incentive Plan
Class of Stock [Line Items]
Common stock, shares outstanding (in shares)	80,007,149
Unvested restricted stock units and performance restricted stock units outstanding (in shares)	6,998,815

Stockholders' Equity - Stock Repurchase Program (Narrative) (Details) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended		13 Months Ended	37 Months Ended
	Feb. 29, 2020	Sep. 30, 2021	Dec. 31, 2021	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2018
Equity, Class of Treasury Stock [Line Items]
Number of shares repurchased (in shares)			471,022		5,057,682	5,528,704
Repurchase of stock		$ 2,000,000	$ 2,441,000	$ 46,042,000	$ 50,000,000	$ 52,000,000
Average price of shares repurchased (in dollars per share)			$ 5.18
Stock Repurchase Program
Equity, Class of Treasury Stock [Line Items]
Authorized amount of repurchases							$ 100,000,000
Authorized current repurchases	$ 50,000,000
Remaining authorized repurchase amount			$ 48,000,000			$ 48,000,000
Stock Repurchase Program, Current Repurchases Authorized
Equity, Class of Treasury Stock [Line Items]
Authorized amount of repurchases							$ 50,000,000

Stockholders' Equity - Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jun. 27, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated share-based compensation expense		$ 14	$ 15	$ 9
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Unrecognized compensation costs	$ 8	$ 8
Unrecognized compensation cost, weighted average period of recognition		2 years
Performance-based Restricted Stock Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 10	$ 10
Unrecognized compensation cost, weighted average period of recognition		2 years
Restated Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares reserved for future issuance (in shares)					10,000,000
Number of shares available for grant (in shares)	1,368,778	1,368,778
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 Prior Years
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%
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 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 Prior Years
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%

Stockholders' Equity - RSUs and PRUs Activity (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2021 $ / shares shares
Restricted Stock Units (RSUs)
Number of shares
Outstanding, beginning of period (in shares) \| shares	1,939
Granted (in shares) \| shares	1,833
Vested (in shares) \| shares	(774)
Forfeited (in shares) \| shares	(418)
Outstanding, end of period (in shares) \| shares	2,580
Weighted-average Grant Date Fair Value
Outstanding, beginning of period (in dollars per share) \| $ / shares	$ 7.52
Granted (in dollars per share) \| $ / shares	4.65
Vested (in dollars per share) \| $ / shares	7.97
Forfeited (in dollars per share) \| $ / shares	5.54
Outstanding, end of period (in dollars per share) \| $ / shares	$ 5.67
Performance-based Restricted Stock Units (PSUs)
Number of shares
Outstanding, beginning of period (in shares) \| shares	1,652
Granted (in shares) \| shares	998
Vested (in shares) \| shares	(75)
Forfeited (in shares) \| shares	(490)
Outstanding, end of period (in shares) \| shares	2,085
Weighted-average Grant Date Fair Value
Outstanding, beginning of period (in dollars per share) \| $ / shares	$ 14.77
Granted (in dollars per share) \| $ / shares	5.96
Vested (in dollars per share) \| $ / shares	12.75
Forfeited (in dollars per share) \| $ / shares	13.17
Outstanding, end of period (in dollars per share) \| $ / shares	$ 11.00

Defined Contribution Plan (Details) - USD ($) $ in Millions	1 Months Ended	6 Months Ended		12 Months Ended
Defined Contribution Plan (Details) - USD ($) $ in Millions	Jan. 31, 2021	Dec. 31, 2021	Jun. 30, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Retirement Benefits [Abstract]
Defined contribution plan, matching contribution, percentage of employee's gross pay (up to)		6.00%	6.00%	3.00%
Defined contribution plan, matching contribution percentage	100.00%	100.00%
Defined contribution plan, cost				$ 1.6	$ 1.0	$ 1.7

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
Income Taxes - Narrative (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Components Of Income Tax Expense (Benefit) [Line Items]
Effective tax rate	(10.00%)	2.80%	(522.90%)
Income tax expense (benefit)	$ 1,413,000	$ (7,218,000)	$ (36,550,000)
Valuation allowance	77,546,000	77,923,000
Uncertain tax benefits	0	13,892,000
Unrecognized tax benefits, accrued penalties or interest expense	0	0
Penalties and interest expense	0	$ 0	$ 0
Domestic
Components Of Income Tax Expense (Benefit) [Line Items]
Net operating loss carryforwards	181,000,000
Domestic \| General Business Tax Credit Carryforward
Components Of Income Tax Expense (Benefit) [Line Items]
Tax credit carryforwards	54,000,000
Domestic \| State Tax Credit Carryforward
Components Of Income Tax Expense (Benefit) [Line Items]
Income tax expense (benefit)	(7,000,000)
State and Local Jurisdiction
Components Of Income Tax Expense (Benefit) [Line Items]
Net operating loss carryforwards	49,000,000
State and Local Jurisdiction \| State Tax Credit Carryforward
Components Of Income Tax Expense (Benefit) [Line Items]
Tax credit carryforwards	$ 9,000,000

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current taxes:
Federal	$ 0	$ 0	$ 0
State	581	828	227
Total current taxes	581	828	227
Deferred taxes:
Federal	832	2,653	(36,756)
State	0	(10,699)	(21)
Total deferred taxes	832	(8,046)	(36,777)
Total current and deferred taxes	$ 1,413	$ (7,218)	$ (36,550)

- Definition

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

+ References + Details

Income Taxes - Reconciliation of the Federal Statutory Tax Rate to the Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Federal statutory rate	21.00%	21.00%	21.00%
State, net of federal tax benefit	3.70%	6.30%	8.90%
Nondeductible compensation	(24.50%)	0.00%	0.00%
Effect of permanent differences	(4.70%)	(0.60%)	0.20%
Tax credits - Prior Year	(29.50%)	4.90%	(546.40%)
Tax credits - Current Year	21.50%	1.10%	0.00%
State return to provision	(0.20%)	(1.10%)	(6.60%)
Change in valuation allowance	2.70%	(28.80%)	0.00%
Effective tax rate	(10.00%)	2.80%	(522.90%)

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
Net operating loss carryforwards	$ 40,846	$ 21,205
Accruals	11,731	14,208
Asset retirement obligations	44,437	43,518
Derivative instruments	12,776	5,654
Tax credits	61,044	62,058
Other	3,551	4,946
Subtotal	174,385	151,589
Valuation allowance	(77,546)	(77,923)
Total deferred tax assets	96,839	73,666
Deferred tax liabilities:
Book tax differences in property basis	(98,670)	(74,677)
Total deferred tax liabilities	(98,670)	(74,677)
Net deferred tax liability	$ (1,831)	$ (1,011)

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - January 1	$ 0	$ 13,892
Prior year - change	0	(13,892)
Current year - change	0	0
Unrecognized tax benefits - December 31	$ 0	$ 0

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaid expenses	$ 26,840	$ 3,580
Materials and supplies	9,533	11,666
Prepaid deposits	6,415	12
Oil inventories	2,933	3,490
Other	225	652
Total other current assets	$ 45,946	$ 19,400

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Narrative (Details) - USD ($)	1 Months Ended	12 Months Ended
	Oct. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reclassification [Line Items]
Increase (decrease) allowance for doubtful accounts		$ (1,300,000)
Deferred financing costs, non-current, net of amortization		5,000,000	$ 7,000,000
Greenhouse gas liability, noncurrent		18,000,000	0
Other operating expense (income)		3,101,000	5,781,000	$ 4,588,000
Supplemental property tax assessment		3,000,000
Income from employee retention credits		2,000,000
Other expenses		2,000,000
Excess abandonment costs			3,000,000
Oil tank storage fees			2,000,000
Drilling rig standby charges			$ 1,000,000
Placerita Field
Reclassification [Line Items]
Gain on sale	$ 2,000,000
Revolving credit facility \| RBL Facility 2017 \| Line of credit
Reclassification [Line Items]
Unamortized debt issuance costs		$ 3,000,000

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Schedule of Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accounts payable - trade	$ 17,699	$ 11,055
Accrued expenses	62,962	43,452
Royalties payable	24,816	15,150
Greenhouse gas liability - current portion	7,513	35,554
Taxes other than income tax liability	8,273	10,118
Accrued interest	10,736	10,783
Dividends payable	4,800	0
Asset retirement obligation - current portion	20,000	25,000
Other	725	873
Total accounts payable and accrued expenses	$ 157,524	$ 151,985

Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Disclosures of Significant Non-Cash Operating Activities:
Greenhouse gas liability - reclassification from long-term to current liability	$ 0	$ 33,376	$ 0
Supplemental Disclosures of Significant Non-Cash Investing Activities:
Material inventory transfers to oil and natural gas properties	3,424	1,596	10,056
Supplemental Disclosures of Cash Payments (Receipts):
Interest, net of amounts capitalized	29,211	29,962	30,720
Income taxes payments (refunds)	$ 699	$ 222	$ (2)

Acquisitions and Divestitures - Additional Information (Details) $ in Thousands		1 Months Ended		3 Months Ended			12 Months Ended
	Oct. 01, 2021 USD ($)	Oct. 31, 2021 USD ($)	May 31, 2020 USD ($) a	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisitions, net of cash received							$ 50,568	$ 0	$ 0
Proceeds received from divestitures							14,025	0	0
Asset retirement obligation, liabilities incurred			$ 6,000				1,350	$ 5,919
Payments to acquire property									$ 2,900
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
Transaction costs					$ 3,000		$ 3,000
C&J Well Services Acquisition \| Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisitions, net of cash received				$ 2,000
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

Acquisitions and Divestitures - Recognized Assets Acquired and Liabilities Assumed (Details) - C&J Well Services Acquisition $ in Thousands	Oct. 01, 2021 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	$ 17,254
Property and equipment	45,099
Other assets	1,700
Total assets acquired	64,053
Accounts payable and accrued expenses assumed	(10,927)
Net assets acquired	$ 53,126

Acquisitions and Divestitures - Pro Forma Revenue (Details) - C&J Well Services Acquisition - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Revenue	$ 664,549	$ 657,796
Net income (loss)	$ 740	$ (250,884)

Earnings Per Share - Narrative (Details) - shares	12 Months Ended
Earnings Per Share - Narrative (Details) - shares	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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)	0	0	572,000

Earnings Per Share - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share, Basic [Abstract]
Net (loss) income	$ (15,542)	$ (262,895)	$ 43,539
Weighted-average shares of common stock outstanding (in shares)	80,209	79,802	81,379
Basic (loss) earnings per share (in dollars per share)	$ (0.19)	$ (3.29)	$ 0.54
Earnings Per Share, Diluted [Abstract]
Net (loss) income	$ (15,542)	$ (262,895)	$ 43,539
Weighted-average shares of common stock outstanding (in shares)	80,209	79,802	81,379
Dilutive effect of potentially dilutive securities (in shares)	0	0	572
Weighted-average common shares outstanding - diluted (in shares)	80,209	79,802	81,951
Diluted (loss) earnings per share (in dollars per share)	$ (0.19)	$ (3.29)	$ 0.53
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs)
Earnings Per Share, Diluted [Abstract]
Potentially dilutive securities (in shares)	3,300	100

Revenue Recognition - Narrative (Details)	12 Months Ended
Revenue Recognition - Narrative (Details)	Dec. 31, 2021
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

Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 701,349	$ 406,052	$ 597,403
(Losses) gains on derivatives	(156,399)	117,781	(37,998)
Total revenues and other	544,950	523,833	559,405
Oil sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	587,613	362,976	543,634
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	32,679	14,041	19,391
Natural gas liquids sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,183	1,646	2,571
Service revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	35,840	0	0
Electricity sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	35,636	25,813	29,397
Marketing revenues
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	3,921	1,426	2,094
Other revenues
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 477	$ 150	$ 316

Segment Information - Schedule of Segment Information (Details) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($) business	Sep. 30, 2021 business	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax			$ 701,349	$ 406,052	$ 597,403
Net (loss) income before income taxes			(14,129)	(270,113)	6,989
Adjusted EBITDA			212,146
Capital expenditures			132,719	76,480	$ 211,995
Total assets	$ 1,456,479		1,456,479	$ 1,419,810
Business segments \| business	2	1
Corporate/Eliminations
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax			0
Net (loss) income before income taxes			(96,956)
Adjusted EBITDA			(43,310)
Capital expenditures			2,211
Total assets	$ (74,771)		(74,771)
Development & Production \| Operating Segments
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax			665,509
Net (loss) income before income taxes			82,826
Adjusted EBITDA			251,146
Capital expenditures			129,479
Total assets	1,450,157		1,450,157
Well Servicing and Abandonment \| Operating Segments
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax			35,840
Net (loss) income before income taxes			1
Adjusted EBITDA			4,310
Capital expenditures			1,029
Total assets	$ 81,093		$ 81,093

Segment Information - Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Net (loss) income	$ (15,542)	$ (262,895)	$ 43,539
Interest expense	31,964	34,295	34,234
Income tax expense (benefit)	1,413	(7,218)	(36,550)
Depreciation, depletion and amortization	144,495	139,180	106,006
Total losses (gains)	117,822	(116,746)	44,955
Derivative, Cost of Hedge Net of Cash Received	(87,625)	142,000	42,000
Other operating expense	(3,101)	(5,781)	(4,588)
Stock-based compensation expense	13,783	$ 14,630	$ 8,647
Non-recurring costs	2,735
Adjusted EBITDA	212,146
Operating Segments \| Development & Production
Segment Reporting Information [Line Items]
Net (loss) income	82,825
Interest expense	0
Income tax expense (benefit)	0
Depreciation, depletion and amortization	136,915
Total losses (gains)	117,822
Derivative, Cost of Hedge Net of Cash Received	(87,625)
Other operating expense	(109)
Stock-based compensation expense	1,100
Non-recurring costs	0
Adjusted EBITDA	251,146
Operating Segments \| Well Servicing and Abandonment
Segment Reporting Information [Line Items]
Net (loss) income	1
Interest expense	0
Income tax expense (benefit)	0
Depreciation, depletion and amortization	2,974
Total losses (gains)	0
Derivative, Cost of Hedge Net of Cash Received	0
Other operating expense	0
Stock-based compensation expense	0
Non-recurring costs	1,335
Adjusted EBITDA	4,310
Corporate/Eliminations
Segment Reporting Information [Line Items]
Net (loss) income	(98,368)
Interest expense	31,964
Income tax expense (benefit)	1,413
Depreciation, depletion and amortization	4,606
Total losses (gains)	0
Derivative, Cost of Hedge Net of Cash Received	0
Other operating expense	(2,992)
Stock-based compensation expense	12,683
Non-recurring costs	1,400
Adjusted EBITDA	$ (43,310)

Subsequent Events (Details) - Antelope Creek Acquisition - Subsequent Event $ in Millions	1 Months Ended
	Feb. 23, 2022 USD ($)	Feb. 01, 2022 Boe
Business Acquisition [Line Items]
Acquisition amount \| $	$ 18
Boe produced \| Boe		700