Cover Page
Cover Page - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Jan. 31, 2023 | Jun. 30, 2022 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2022 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Transition Report | false | ||
Entity File Number | 001-38606 | ||
Entity Registrant Name | BERRY CORPORATION (bry) | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 81-5410470 | ||
Entity Address, Address Line One | 16000 Dallas Parkway | ||
Entity Address, Address Line Two | Suite 500 | ||
Entity Address, City or Town | Dallas | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 75248 | ||
City Area Code | 661 | ||
Local Phone Number | 616-3900 | ||
Title of 12(b) Security | Common Stock, par value $0.001 per share | ||
Trading Symbol | BRY | ||
Security Exchange Name | NASDAQ | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | true | ||
Entity Ex Transition Period | false | ||
ICFR Auditor Attestation Flag | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 501.6 | ||
Entity Common Stock, Shares Outstanding | 75,767,503 | ||
Documents Incorporated by Reference | The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 23, 2023) will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2022 and is incorporated by reference in Part III to the extent described herein. | ||
Entity Central Index Key | 0001705873 | ||
Document Fiscal Year Focus | 2022 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
Audit Information [Abstract] | |
Auditor Name | KPMG LLP |
Auditor Location | Dallas, TX |
Auditor Firm ID | 185 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Current assets: | ||
Cash and cash equivalents | $ 46,250 | $ 15,283 |
Accounts receivable, net of allowance for doubtful accounts of $866 at December 31, 2022 and December 31, 2021 | 101,713 | 86,269 |
Derivative instruments | 36,367 | 0 |
Other current assets | 33,725 | 45,946 |
Total current assets | 218,055 | 147,498 |
Noncurrent assets: | ||
Oil and natural gas properties | 1,725,864 | 1,537,894 |
Accumulated depletion and amortization | (465,889) | (340,328) |
Total oil and natural gas properties, net | 1,259,975 | 1,197,566 |
Other property and equipment | 155,619 | 140,710 |
Accumulated depreciation | (55,781) | (36,927) |
Total other property and equipment, net | 99,838 | 103,783 |
Deferred income taxes | 42,844 | 0 |
Derivative instruments | 76 | 1,070 |
Other noncurrent assets | 10,242 | 6,562 |
Total assets | 1,631,030 | 1,456,479 |
Current liabilities: | ||
Accounts payable and accrued expenses | 203,101 | 157,524 |
Derivative instruments | 31,106 | 29,625 |
Total current liabilities | 234,207 | 187,149 |
Noncurrent liabilities: | ||
Long-term debt | 395,735 | 394,566 |
Derivative instruments | 13,642 | 18,577 |
Deferred income taxes | 0 | 1,831 |
Asset retirement obligation | 158,491 | 143,926 |
Other noncurrent liabilities | 28,470 | 17,782 |
Commitments and Contingencies - Note 5 | ||
Stockholders' Equity: | ||
Common stock ($0.001 par value; 750,000,000 shares authorized; 86,350,771 and 85,590,417 shares issued; and 75,767,503 and 80,007,149 shares outstanding, at December 31, 2022 and December 31, 2021, respectively) | 86 | 86 |
Additional paid-in capital | 821,443 | 912,471 |
Treasury stock, at cost (10,583,268 shares at December 31, 2022 and 5,583,268 shares at December 31, 2021) | (103,739) | (52,436) |
Retained earnings (accumulated deficit) | 82,695 | (167,473) |
Total stockholders' equity | 800,485 | 692,648 |
Total liabilities and stockholders' equity | $ 1,631,030 | $ 1,456,479 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Statement of Financial Position [Abstract] | ||
Allowance for doubtful accounts | $ 866 | $ 866 |
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Common stock, shares authorized (in shares) | 750,000,000 | 750,000,000 |
Common stock, shares issued (in shares) | 86,350,771 | 85,590,417 |
Common stock, shares outstanding (in shares) | 75,767,503 | 80,007,149 |
Treasury stock, shares at cost (in shares) | 10,583,268 | 5,583,268 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Revenues and other: | |||
(Losses) gains on oil and gas sales derivatives | $ (137,109,000) | $ (156,399,000) | $ 117,781,000 |
Total revenue, excluding assessed tax | 1,055,450,000 | 701,349,000 | 406,052,000 |
Total revenues and other | 918,341,000 | 544,950,000 | 523,833,000 |
Expenses and other: | |||
Transportation expenses | 4,564,000 | 6,897,000 | 6,938,000 |
Marketing expenses | 299,000 | 3,811,000 | 1,380,000 |
General and administrative expenses | 96,439,000 | 73,106,000 | 77,696,000 |
Depreciation, depletion and amortization | 156,847,000 | 144,495,000 | 139,180,000 |
Impairment of oil and gas properties | 0 | 0 | 289,085,000 |
Taxes, other than income taxes | 39,495,000 | 46,500,000 | 35,572,000 |
(Gains) losses on natural gas purchase derivatives | (88,795,000) | (38,577,000) | 1,035,000 |
Other operating expense | 3,722,000 | 3,101,000 | 5,781,000 |
Total expenses and other | 679,550,000 | 526,868,000 | 759,623,000 |
Other (expenses) income: | |||
Interest expense | (30,917,000) | (31,964,000) | (34,295,000) |
Other, net | (142,000) | (247,000) | (28,000) |
Total other (expenses) income | (31,059,000) | (32,211,000) | (34,323,000) |
Income (loss) before income taxes | 207,732,000 | (14,129,000) | (270,113,000) |
Income tax (benefit) expense | (42,436,000) | 1,413,000 | (7,218,000) |
Net income (loss) | $ 250,168,000 | $ (15,542,000) | $ (262,895,000) |
Earnings Per Share [Abstract] | |||
Basic (in dollars per share) | $ 3.19 | $ (0.19) | $ (3.29) |
Diluted (in dollars per share) | $ 3.03 | $ (0.19) | $ (3.29) |
Oil, natural gas and natural gas liquid sales | |||
Revenues and other: | |||
Total revenue, excluding assessed tax | $ 842,449,000 | $ 625,475,000 | $ 378,663,000 |
Expenses and other: | |||
Cost of goods sold | 302,321,000 | 236,048,000 | 186,348,000 |
Service revenue | |||
Revenues and other: | |||
Total revenue, excluding assessed tax | 181,400,000 | 35,840,000 | 0 |
Expenses and other: | |||
Cost of goods sold | 142,819,000 | 28,339,000 | 0 |
Electricity sales | |||
Revenues and other: | |||
Total revenue, excluding assessed tax | 30,833,000 | 35,636,000 | 25,813,000 |
Expenses and other: | |||
Cost of goods sold | 21,839,000 | 23,148,000 | 16,608,000 |
Marketing revenues | |||
Revenues and other: | |||
Total revenue, excluding assessed tax | 289,000 | 3,921,000 | 1,426,000 |
Other revenues | |||
Revenues and other: | |||
Total revenue, excluding assessed tax | $ 479,000 | $ 477,000 | $ 150,000 |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) | Total | Common Stock | Additional Paid-in Capital | Treasury Stock | Retained Earnings (Accumulated Deficit) |
Beginning balance at Dec. 31, 2019 | $ 972,448,000 | $ 85,000 | $ 901,830,000 | $ (49,995,000) | $ 120,528,000 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Shares withheld for payment of taxes on equity awards | (1,039,000) | (1,039,000) | |||
Stock based compensation | 15,086,000 | 15,086,000 | |||
Purchase of treasury stock | 0 | ||||
Dividends declared on common stock | (9,564,000) | (9,564,000) | |||
Net income (loss) | (262,895,000) | (262,895,000) | |||
Ending balance at Dec. 31, 2020 | 714,036,000 | 85,000 | 915,877,000 | (49,995,000) | (151,931,000) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Shares withheld for payment of taxes on equity awards | (1,543,000) | (1,543,000) | |||
Stock based compensation | 14,434,000 | 14,434,000 | |||
Issuance of common stock | 1,000 | 1,000 | |||
Purchase of treasury stock | (2,441,000) | (2,441,000) | |||
Dividends declared on common stock | (16,297,000) | (16,297,000) | |||
Net income (loss) | (15,542,000) | (15,542,000) | |||
Ending balance at Dec. 31, 2021 | 692,648,000 | 86,000 | 912,471,000 | (52,436,000) | (167,473,000) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Shares withheld for payment of taxes on equity awards | (4,136,000) | (4,136,000) | |||
Stock based compensation | 17,762,000 | 17,762,000 | |||
Purchase of treasury stock | (51,303,000) | (51,303,000) | |||
Dividends declared on common stock | (104,654,000) | (104,654,000) | |||
Net income (loss) | 250,168,000 | 250,168,000 | |||
Ending balance at Dec. 31, 2022 | $ 800,485,000 | $ 86,000 | $ 821,443,000 | $ (103,739,000) | $ 82,695,000 |
CONSOLIDATED STATEMENTS OF ST_2
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Stockholders' Equity [Abstract] | |||
Common stock, dividends declared (in dollars per share) | $ 1.34 | $ 0.20 | $ 0.12 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Cash flow from operating activities: | |||
Net income (loss) | $ 250,168,000 | $ (15,542,000) | $ (262,895,000) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 156,847,000 | 144,495,000 | 139,180,000 |
Amortization of debt issuance costs | 2,590,000 | 4,430,000 | 5,351,000 |
Impairment of oil and gas properties | 0 | 0 | 289,085,000 |
Stock-based compensation expense | 16,973,000 | 13,783,000 | 14,630,000 |
Deferred income taxes | (45,566,000) | 819,000 | (8,045,000) |
(Decrease) increase in allowance for doubtful accounts | 0 | (1,349,000) | 1,112,000 |
Other operating expenses | 160,000 | (487,000) | 5,083,000 |
Derivatives activities: | |||
Total losses (gains) | 48,314,000 | 117,822,000 | (116,746,000) |
Cash settlements on derivatives | (88,023,000) | (91,634,000) | 142,292,000 |
Changes in assets and liabilities: | |||
(Increase) decrease in accounts receivable | (15,409,000) | (15,614,000) | 18,767,000 |
Decrease (increase) in other assets | 6,725,000 | (24,824,000) | (2,000) |
Increase (decrease) in accounts payable and accrued expenses | 36,100,000 | 4,045,000 | (14,172,000) |
Decrease in other liabilities | (7,938,000) | (13,456,000) | (17,111,000) |
Net cash provided by operating activities | 360,941,000 | 122,488,000 | 196,529,000 |
Capital expenditures: | |||
Capital expenditures | (152,921,000) | (132,719,000) | (76,480,000) |
Changes in capital expenditures accruals | 14,286,000 | 482,000 | (11,336,000) |
Acquisitions, net of cash received | (25,917,000) | (50,568,000) | 0 |
Acquisition of properties and equipment and other | 0 | (876,000) | (5,981,000) |
Proceeds received from divestitures | 0 | 14,025,000 | 0 |
Proceeds from sale of property and equipment and other | 0 | 869,000 | 177,000 |
Net cash used in investing activities | (164,552,000) | (168,787,000) | (93,620,000) |
Cash flow from financing activities: | |||
Dividends paid on common stock | (109,455,000) | (11,486,000) | (19,463,000) |
Repurchase of common stock | (51,303,000) | (2,440,000) | 0 |
Shares withheld for payment of taxes on equity awards and other | (4,136,000) | (1,543,000) | (1,039,000) |
Debt issuance costs | (528,000) | (3,506,000) | 0 |
Net cash used in financing activities | (165,422,000) | (18,975,000) | (22,352,000) |
Net increase (decrease) in cash and cash equivalents | 30,967,000 | (65,274,000) | 80,557,000 |
Cash and cash equivalents: | |||
Beginning | 15,283,000 | 80,557,000 | 0 |
Ending | 46,250,000 | 15,283,000 | 80,557,000 |
RBL Facility | |||
Cash flow from financing activities: | |||
Borrowings under credit facility | 247,000,000 | 119,000,000 | 228,900,000 |
Repayments on credit facility | (247,000,000) | (119,000,000) | $ (230,750,000) |
2022 ABL Facility | |||
Cash flow from financing activities: | |||
Borrowings under credit facility | 2,000,000 | 0 | |
Repayments on credit facility | $ (2,000,000) | $ 0 |
Basis of Presentation and Signi
Basis of Presentation and Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation and Significant Accounting Policies | Basis of Presentation and Significant Accounting Policies “Berry Corp.” refers to Berry Corporation (bry), a Delaware corporation, which is the sole member of each of its three Delaware limited liability company subsidiaries: (1) Berry Petroleum Company, LLC (“Berry LLC”), (2) CJ Berry Well Services Management, LLC (“C&J Management”) and (3) C&J Well Services, LLC (“C&J”). As the context may require, the “Company”, “we”, “our” or similar words refer to Berry Corp. and its subsidiary, Berry LLC, and as of October 1, 2021 this also includes C&J Management and C&J. Nature of Business We are a western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived conventional reserves in the San Joaquin basin of California (100% oil) and the Uinta basin of Utah (oil and gas), with well servicing and abandonment capabilities in California. Since October 1, 2021, we have operated in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment. Principles of Consolidation and Reporting The consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”), which requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We eliminated all significant intercompany transactions and balances upon consolidation. For oil and gas E&P joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements. Segment Reporting The Company has two reportable segments. Reportable segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker (“CODM”), our Chief Executive Officer, in deciding how to allocate resources and assess performance. The E&P segment consists of the development and production of onshore, low geologic risk, long-lived conventional oil and gas reserves, primarily located in California, as well as Utah. The well servicing and abandonment segment provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics. Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP required management of the Company to make informed estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. Estimates that are particularly significant to the financial statements include estimates of our reserves of oil and gas; future cash flows from oil and gas properties; depreciation, depletion and amortization; asset retirement obligations; fair values of commodity derivatives; stock-based compensation; fair values of assets acquired and liabilities assumed; and income taxes. Cash Equivalents We consider all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Inventories Inventories were included in other current assets. Oil and natural gas inventories were valued at the lower of cost or net realizable value. Materials and supplies were valued at their weighted-average cost and are reviewed periodically for obsolescence. Oil and Natural Gas Properties Proved Properties We account for oil and natural gas properties in accordance with the successful efforts method. Under this method, all acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves. All development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved developed reserves. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in the current period. Gains or losses from the disposal of other properties are recognized in the current period. For assets acquired, we base the capitalized cost on fair value at the acquisition date. We expense expenditures for maintenance and repairs necessary to maintain properties in operating condition, as well as annual lease rentals, as they are incurred. Estimated dismantlement and abandonment costs are capitalized at their estimated net present value and amortized over the remaining lives of the related assets. Interest is capitalized only during the periods in which these assets are brought to their intended use. The amount of capitalized interest was approximately $1 million, $2 million and $1 million in 2022, 2021 and 2020, respectively. We only capitalize the interest on borrowed funds related to our share of costs associated with qualifying capital expenditures. The amount of capitalized exploratory well costs was zero for all periods and the amount of capitalized overhead was approximately $6 million, $7 million and $6 million in 2022, 2021 and 2020, respectively. We evaluate the impairment of our proved oil and natural gas properties and other property and equipment generally on a field-by-field basis or at the lowest level for which cash flows are identifiable, whenever events or changes in circumstance indicate that the carrying value may not be recoverable. We reduce the carrying values of proved properties to fair value when the expected undiscounted future cash flows are less than net book value. We measure the fair values of proved properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount rate. These inputs require significant judgments and estimates by our management at the time of the valuation which can change significantly over time. The underlying commodity prices are embedded in our estimated cash flows and are the product of a process that begins with the relevant forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors our management believes will impact realizable prices. The fair value was estimated using inputs characteristic of a Level 3 fair value measurement. Unproved Properties A portion of the carrying value of our oil and gas properties was attributable to unproved properties. At December 31, 2022 and 2021, the net capitalized costs attributable to unproved properties was approximately $248 million and $292 million, respectively. The unproved amounts were not subject to depreciation, depletion and amortization until they were classified as proved properties and amortized on a unit-of-production basis. We evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, adverse change in regulatory environment, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. Impairment In 2022 and 2021, we did not record any impairment charges for proved and unproved properties. As of March 31, 2020, we performed impairment tests with respect to our proved and unproved oil and gas properties and other property and equipment as a result of significant declines in oil prices during the latter part of the first quarter 2020. We recorded a non-cash pre-tax asset impairment charge of $289 million during the first quarter of 2020 on proved properties in Utah and certain California locations and other property and equipment. We evaluated our proved properties in accordance with accounting guidance and fair value techniques utilizing the period-end forward price curve, as well as assessing projects we determine we would not pursue in the foreseeable future given the current environment. We determined based on plans and exploration and development efforts no impairment was necessary for our unproved property balance in 2020. Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, cogeneration facilities, buildings, well servicing and abandonment vehicles and equipment, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost, depreciated using the straight-line method based on expected useful lives ranging from 15 to 39 years for buildings and improvements, 20 to 30 years for cogeneration facilities, natural gas plants and pipelines, 1 to 10 years for furniture and equipment, 1 to 10 years for well servicing and abandonment vehicles and equipment and other equipment, and the salvage value is considered as applicable. Other property and equipment assets are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Business Combinations The Company records business combinations using the acquisition method of accounting. Under the acquisition method of accounting, identifiable assets acquired and liabilities assumed are recorded at their acquisition-date fair values. The excess of the purchase price over the estimated fair value, if any, is recorded as goodwill. Changes in the estimated fair values of net assets recorded for acquisitions prior to the finalization of more detailed analysis, but not to exceed one year from the date of acquisition, will adjust the amount of the purchase price allocations accordingly. Measurement period adjustments are reflected in the period in which they occur. We account for acquisitions of businesses using the acquisition method of accounting, which requires the allocation of the purchase price consideration based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. Our estimates and judgments of the fair value of acquired businesses could prove to be inexact, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price consideration to acquired assets and liabilities, which could result in asset impairments, the recording of previously unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets and liabilities is increased during periods of economic uncertainty. Asset Retirement Obligation We recognize the fair value of asset retirement obligations (“AROs”) in the period in which a determination is made that a legal obligation exists to dismantle an asset and remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts were based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalized the cost by increasing the related property, plant and equipment (“PP&E”) balances. If the estimated future cost of the AROs changes, we record an adjustment to both the ARO and PP&E. Over time, the liability is increased and the capitalized cost is depreciated over the useful life of the asset. Accretion expense is also recognized over time as the discounted liabilities are accreted to their expected settlement value and is included in depreciation, depletion and amortization in the statement of operations. The following table summarizes activity in our ARO account in which approximately $158 million and $144 million were included in long term liabilities as of December 31, 2022 and December 31, 2021, respectively, with the remaining current portion included in accrued liabilities: Year Ended December 31, 2022 2021 (in thousands) Beginning balance $ 163,925 $ 160,192 Liabilities incurred including from acquisitions 3,028 1,350 Settlements and payments (19,558) (17,900) Accretion expense 10,848 10,936 Reduction due to property sales (1,210) (22,199) Revisions 21,458 31,546 Ending balance $ 178,491 $ 163,925 Revenue Recognition The majority of the Company's revenue is from the E&P business, which includes the sale of crude oil, natural gas and NGLs, as well as electricity from its cogeneration plants. The remaining revenue is generated from the well servicing and abandonment business. See Note 12 for information regarding the Company’s revenue recognition policy. Fair Value Measurements We have categorized our assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level 3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period. We primarily apply the market approach for recurring fair value measurement, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management’s judgments regarding expectations of projected cash flows and discounts those cash flows using a risk-adjusted discount rate. The only item on our balance sheet that would be affected by recurring fair value measurements is derivatives. We determine the fair value of our oil and gas sales and natural gas purchase derivatives using valuation techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We classify these measurements as Level 2. We use market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When we are required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the income approach is based on management’s best assumptions regarding expectations of future net cash flows. PP&E is written down to fair value if we determine that there has been an impairment in its value. The fair value is determined as of the date of the assessment using discounted cash flow models based on management’s expectations for the future. Inputs include estimates of future production, prices based on commodity forward price curves as of the date of the estimate, estimated future operating and development costs and a risk-adjusted discount rate. However, assumptions used reflect assets highest and best use and a market participant’s view of long-term prices, costs and other factors and are consistent with assumptions used in our business plans and investment decisions. We classify these measurements as Level 3. Stock-based Compensation We have issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units (“PSUs”) that include (i) awards with a market objective measured against both absolute total stockholder return (“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR PSUs”) over the performance period and (ii) awards based on the Company's average cash returned on invested capital (“CROIC PSUs” and “ROIC PSUs”) over the performance period. CROIC PSUs are awarded to certain Berry employees, while ROIC PSUs are awarded to certain CJWS employees. The fair value of the stock-based awards is determined at the date of grant and is not remeasured. The fair value of the RSUs, CROIC PSUs and ROIC PSUs was determined using the grant date stock price. The fair value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the peer group over the performance periods. Estimates used in the Monte Carlo valuation model are considered highly complex and subjective. Compensation expense, net of actual forfeitures, for the RSUs and PSUs is recognized on a straight-line basis over the requisite service periods, which is over the awards’ respective vesting or performance periods which range from one Other Loss Contingencies In the normal course of business, we are involved in lawsuits, claims and other environmental and legal proceedings and audits. We accrue reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, we disclose, if material, in aggregate, our exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. We review our loss contingencies on an ongoing basis. Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors. Electricity Cost Allocation We own several cogeneration facilities. Our investment in cogeneration facilities has been for the express purpose of lowering steam costs in our heavy oil operations in California and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power, extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. We allocate steam and electricity costs to lease operating expenses based on the conversion efficiency of the cogeneration facilities plus certain direct costs of producing steam. We also allocate a portion of the electricity production costs related to the power we sell to third parties, which is reported in “electricity generation expenses” in the statement of operations. Income Taxes Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). Earnings per Share Basic earnings (loss) per share is calculated as net income (loss) divided by the weighted-average shares of common stock outstanding during the period. Diluted earnings (loss) per share is calculated by dividing net income (loss) by the weighted-average shares of common stock outstanding, including the effect of potentially dilutive securities. For basic earnings per share (“EPS”), the weighted-average number of common stock outstanding excludes outstanding shares related to unvested restricted stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding potentially dilutive securities, unless their effect is anti-dilutive. We did not have any participating securities in the periods presented. We compute basic and diluted EPS using the two-class method required for participating securities. Common stock awards are considered participating securities when such shares have non-forfeitable dividend rights at the same rate as common stock. Our dividend rights are forfeitable, and are not considered participating securities. Under the two-class method, undistributed earnings allocated to participating securities are subtracted from net income attributable to common stock in determining net income attributable to common stockholders. In loss periods, no allocation is made to participating securities because the participating securities do not share in losses. Business and Credit Concentrations We maintain our cash in bank deposit accounts which, at times, may exceed federally insured amounts. We have not experienced any losses in such accounts. We believe we are not exposed to any significant credit risk on our cash. We sell oil, natural gas and NGLs to various types of customers, including pipelines, refineries and other oil and natural gas companies and electricity to utility companies. We also perform well servicing and abandonment for oil and natural gas companies. Based on the current demand for oil, natural gas, NGLs, as well as our well servicing and abandonment services and the availability of other purchasers, we believe that the loss of any one of our major purchasers would not have a material adverse effect on our financial condition, results of operations or net cash provided by operating activities. For the year ended December 31, 2022, our three largest customers represented approximately 33%, 16%, and 10% of our sales. For the year ended December 31, 2021, our four largest customers represented 30%, 16%, 14%, and 12% of our sales. For the year ended December 31, 2020, our three largest customers represented approximately 44%, 20%, and 12% of our sales. All such customers were customers of our E&P segment. At December 31, 2022, trade accounts receivable from three customers represented approximately 33%, 16%, and 13% of our receivables. At December 31, 2021, trade accounts receivable from three customers represented approximately 28%, 13%, and 11% of our receivables. Recently Adopted Accounting Standards In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures with respect to the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) , which is an update to the lease standard providing an optional transition approach for land easements allowing entities to evaluate only new or modified land easements. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842) , which provided optional transition relief allowing a prospective approach in applying the new rules by not adjusting comparative period financial information for the effects of the new rules and not requiring disclosures for periods before the effective date. As an emerging growth company, we have elected to delay the adoption of these rules until they are applicable to non-SEC issuers. During the second quarter of 2020, this adoption date was further delayed by FASB until fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. We adopted these rules in the first quarter of 2022 prospectively. The impacts of adoption were immaterial. |
Oil and Natural Gas Properties
Oil and Natural Gas Properties and Other Property and Equipment | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
Oil and Natural Gas Properties and Other Property and Equipment | Oil and Natural Gas Properties and Other Property and Equipment Oil and Natural Gas Capitalized Costs Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: Year Ended December 31, 2022 2021 (in thousands) Proved properties $ 1,477,791 $ 1,246,380 Unproved properties 248,073 291,514 Total proved and unproved properties 1,725,864 1,537,894 Less accumulated depletion and amortization (465,889) (340,328) Total proved and unproved properties, net $ 1,259,975 $ 1,197,566 Other Property and Equipment Other property and equipment consisted of the following: Year Ended December 31, 2022 2021 (in thousands) Cogeneration facilities, natural gas plants and pipelines $ 58,357 $ 54,237 Vehicles and service equipment (1) 65,195 55,521 Furniture and equipment 23,779 22,665 Land 6,102 6,101 Buildings and leasehold improvements 2,186 2,186 Total other property and equipment 155,619 140,710 Less: accumulated depreciation (55,781) (36,927) Total other property and equipment, net $ 99,838 $ 103,783 __________ (1) Includes CJWS vehicles and service equipment. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Debt | Debt The following table summarizes our outstanding debt: December 31, 2022 December 31, 2021 Interest Rate Maturity Security (in thousands) 2021 RBL Facility $ — $ — variable rates 9.5% (2022) and 5.3% (2021) August 26, 2025 Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets 2022 ABL Facility — n/a variable rates 8.3% (2022) June 5, 2025 Personal property assets, other than excluded accounts 2026 Notes 400,000 400,000 7.0% February 15, 2026 Unsecured Long-Term Debt - Principal Amount 400,000 400,000 Less: Debt Issuance Costs (4,265) (5,434) Long-Term Debt, net $ 395,735 $ 394,566 Deferred Financing Costs We incurred legal and bank fees related to the issuance of debt. At December 31, 2022 and 2021, debt issuance costs for the 2021 RBL Facility and the 2022 ABL Facility (each as defined below) reported in “other noncurrent assets” on the balance sheet were approximately $4 million and $5 million, net of amortization, respectively. In 2021, we expensed $3 million of unamortized debt issuance costs related to the modification of the 2017 RBL Facility and also incurred approximately $4 million of legal and bank fees related to the issuance of the 2021 RBL Facility. At December 31, 2022 and 2021, debt issuance costs, net of amortization, for the unsecured notes due February 2026 (the “2026 Notes”) reported in “Long-Term Debt, net” on the balance sheet were approximately $4 million and $5 million, respectively. For the years ended December 31, 2022, 2021, and 2020, the amortization expense for the 2021 RBL Facility, 2022 ABL Facility, the 2017 RBL Facility and the 2026 Notes combined, was approximately $2 million, $4 million, and $5 million, respectively. The amortization of debt issuance costs is presented in “interest expense” on the consolidated statements of operations. Fair Value Our debt is recorded at the carrying amount on the balance sheets. The carrying amounts of the 2021 RBL Facility and the 2022 ABL Facility approximate fair value because the interest rates are variable and reflect market rates. The fair value of the 2026 Notes was approximately $369 million and $400 million at December 31, 2022 and 2021, respectively. 2021 RBL Facility On August 26, 2021, Berry Corp, as a guarantor, together with Berry LLC, as the borrower, entered into a credit agreement that provided for a revolving loan with up to $500 million of commitments, subject to a reserve borrowing base (as amended by the First Amendment, the Second Amendment and the Third Amendment, each as defined below, the “2021 RBL Facility”). Our initial borrowing base is $200 million. The 2021 RBL Facility provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $20 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the 2021 RBL Facility on a dollar for dollar basis. The 2021 RBL Facility matures on August 26, 2025, unless terminated earlier in accordance with the 2021 RBL Facility terms. Borrowing base redeterminations generally become effective each May and November, although the borrower and the lenders may each make one interim redetermination between scheduled redeterminations. In December 2021, we completed the first scheduled semi-annual borrowing base redetermination and entered into that certain First Amendment to Credit Agreement (the “First Amendment”), which resulted in a reaffirmed borrowing base at $200 million and changes to the hedging covenants in respect of the exclusion of short puts or similar derivatives in the calculation of minimum and maximum hedging requirements. In May 2022, Berry Corp., as a guarantor, and Berry LLC, as the borrower, entered into that certain Second Amendment to Credit Agreement and Limited Consent and Waiver (the “Second Amendment”) pursuant to which, among other things, the requisite lenders under the 2021 RBL Facility (i) consented to certain dividends and distributions and to certain investments made by Berry LLC in C&J and/or C&J Management, in each case, as further described therein, (ii) waived certain minimum hedging requirements for the time periods described therein, (iii) waived any breach, default or event of default which may have arisen as a result of any of the foregoing, (iv) amended the restricted payments covenant to give us additional flexibility to make restricted payments, subject to satisfaction of certain leverage and availability conditions and other conditions described below and in the Second Amendment and (v) amended the minimum hedging covenant to not, until October 1, 2022, require hedges for any full calendar month from and after January 1, 2025, as further described in the Second Amendment. In May 2022, we also completed our semi-annual borrowing base redetermination and entered into the Third Amendment to the Credit Agreement (the “Third Amendment”), which among other things (1) increased the borrowing base from $200 million to $250 million; (2) established the Aggregate Elected Commitment Amounts (as defined in the 2021 RBL Facility) at $200 million initially; and (3) converted all outstanding Eurodollar Loans (into Term Benchmark Loans (each as defined in the 2021 RBL Facility) with an initial interest period of one-month’s duration and otherwise give effect to the transition from the London interbank offered rate (“LIBOR”) to the secured overnight financing rate (“SOFR”) by replacing the adjusted LIBOR rate with the term SOFR rate for one, three or six months plus 0.1% (subject to a floor of 0.5%). In December 2022, we completed our scheduled semi-annual borrowing base redetermination, which resulted in a reaffirmed borrowing base at $250 million and $200 million elected commitment amount. If the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the 2021 RBL Facility exceeds the borrowing base at any time as a result of a redetermination of the borrowing base, we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, deliver reserve engineering reports and mortgages covering additional oil and gas properties sufficient in certain lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the next six-month period. Upon certain adjustments to the borrowing base other than a result of a redetermination, we are required to make a lump sum payment in an amount equal to the amount by which the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the 2021 RBL Facility exceeds the borrowing base. In addition, the 2021 RBL Facility provides that if there are any outstanding borrowings and the consolidated cash balance exceeds $20 million at the end of each calendar week, such excess amounts shall be used to prepay borrowings under the credit agreement. Otherwise, any unpaid principal will be due at maturity. The outstanding borrowings under the revolving loan bear interest at a rate equal to either (i) a customary base rate plus an applicable margin ranging from 2.0% to 3.0% per annum, and (ii) a customary benchmark rate plus an applicable margin ranging from 3.0% to 4.0% per annum, and in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.5% on the average daily unused amount of the borrowing availability under the 2021 RBL Facility. We have the right to prepay any borrowings under the 2021 RBL Facility with prior notice at any time without a prepayment penalty. The 2021 RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a leverage ratio of not more than 3.0 to 1.0 and (ii) a current ratio of not less than 1.0 to 1.0. As of December 31, 2022, our leverage ratio and current ratio were 1.2 to 1.0 and 1.7 to 1.0, respectively. In addition, the 2021 RBL Facility currently provides that, to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. We were in compliance with all financial covenants under the 2021 RBL Facility as of December 31, 2022. The 2021 RBL Facility contains usual and customary events of default and remedies for credit facilities of a similar nature. The 2021 RBL Facility also places restrictions on the borrower and its restricted subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of the borrower’s senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters. From and after August 26, 2022, the 2021 RBL Facility permits us to repurchase certain indebtedness so long as both before and after giving pro forma effect to such repurchase, no default or event of default exists, availability is equal to or greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to 1.0. The 2021 RBL Facility also permits us to make restricted payments so long as both before and after giving pro forma effect to such distribution, no default or event of default exists, availability exceeds 75% of the borrowing base, and our pro forma leverage ratio is less than or equal to 1.5 to 1.0. In addition, we can make other restricted payments in an aggregate amount not to exceed 100% of Free Cash Flow (as defined under the 2021 RBL Facility) for the fiscal quarter most recently ended prior to such distribution so long as, in addition to other conditions and limitations as described in the 2021 RBL Facility, both before and after giving pro forma effect to such distribution, no default or event of default exists, availability is greater than 20% of the borrowing base and our pro forma leverage ratio is less than or equal to 2.0 to 1.0. We can repurchase equity or make other distributions to our equity holders in an amount equal to (i) 100% of Free Cash Flow (as defined under the 2021 RBL Facility) for the fiscal quarter most recently ended prior to such repurchase or distribution minus (ii) the amount of certain investments made, so long as, in addition to other conditions and limitations as described in the 2021 RBL Facility, availability is equal to or greater than 20% of the elected commitments or borrowing base, whichever is in effect, and our pro forma leverage ratio is less than or equal to 2.0 to 1.0. Berry LLC is the borrower on the 2021 RBL Facility and Berry Corp. is the guarantor. Each future subsidiary of Berry Corp., with certain exceptions, is required to guarantee our obligations and obligations of the other guarantors under the 2021 RBL Facility and under certain hedging transactions and banking services arrangements (the “Guaranteed Obligations”). The lenders under the 2021 RBL Facility hold a mortgage on at least 90% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions. As of December 31, 2022, we had no borrowings outstanding, $7 million in letters of credit outstanding, and approximately $193 million of available borrowings capacity under the 2021 RBL Facility. 2022 ABL Facility On August 9, 2022, C&J and C&J Management, which are the two entities that constitute the well servicing and abandonment segment referred to as CJWS, as borrowers, entered into a credit agreement with Tri Counties Bank, as lender, that provides for a revolving loan facility, subject to satisfaction of customary conditions precedent to borrowing, of up to the lesser of (x) $15 million and (y) the borrowing base (“the “2022 ABL Facility”). The “borrowing base” is an amount equal to 80% percent of the balance due on eligible accounts receivable, subject to reserves that Tri Counties Bank may implement in its reasonable discretion. Interest on the outstanding principal amount of the revolving loans under the 2022 ABL Facility accrues at a per annum rate equal to 1.25% in excess of The Wall Street Journal Prime Rate. The “Wall Street Journal Prime Rate” is the variable rate of interest, on a per annum basis, which is announced and/or published in the “Money Rates” section of The Wall Street Journal from time to time as its “Prime Rate”. The rate will be redetermined whenever The Wall Street Journal Prime Rate changes. Interest is due quarterly, in arrears, starting on September 30, 2022 and will continue to be due and payable in arrears on the last day of each calendar quarter thereafter. On June 5, 2025 the entire unpaid principal balance of the revolving loans under the 2022 ABL Facility, and all unpaid interest thereon, will be due and payable. The 2022 ABL Facility provides a letter of credit sub-facility for the issuance of letters of credit in an aggregate amount not to exceed $7.5 million. The 2022 ABL Facility requires CJWS to comply with the following financial covenants (i) maintain on a consolidated basis a ratio of total liabilities to tangible net worth of no greater than 1.5 to 1.0 at any time; (ii) reduce the amount of revolving advances outstanding under the 2022 ABL Facility to not more than 90% of the lesser of (a) the maximum revolving advance amount, or (b) the borrowing base, as of Tri Counties Bank’s close of business on the last day of each fiscal quarter; and (iii) maintain net income before taxes of not less than $1.00 as of each fiscal year end. As of December 31, 2022, CJWS had a ratio of total liabilities to tangible net worth of 0.2 to 1.0, no advances outstanding, and net income for fiscal year end 2022 was $15 million. The 2022 ABL Facility contains usual and customary events of default and remedies for credit facilities of a similar nature. The 2022 ABL Facility also places restrictions on CJWS with respect to additional indebtedness, liens, dividends and other distributions, investments, acquisitions, mergers, asset dispositions and other matters. CJWS’s obligations under the 2022 ABL Facility are not guaranteed by Berry Corp. or Berry LLC and Berry Corp. and Berry LLC do not and are not required to provide any credit support for such obligations. CJWS was in compliance with all financial covenants under the 2022 ABL Facility as of December 31, 2022. As of December 31, 2022, CJWS had no borrowings and $2 million letters of credit outstanding with $13 million of available borrowing capacity under the 2022 ABL Facility. 2017 RBL Facility On July 31, 2017, we entered into a credit agreement that provided for a revolving loan with up to $1.5 billion of commitment, subject to a reserve borrowing base (“2017 RBL Facility”). On August 26, 2021, we cancelled the 2017 RBL Facility agreement, which had a borrowing base of $200 million and there were no borrowings outstanding at the time of cancellation. Senior Unsecured Notes In February 2018, Berry LLC completed a private issuance of $400 million in aggregate principal amount of 7.0% senior unsecured notes due February 2026 (the “2026 Notes”), which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. The 2026 Notes are Berry LLC’s senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The 2026 Notes are fully and unconditionally guaranteed on a senior unsecured basis by Berry Corp. and will also be guaranteed by certain of our future subsidiaries; C&J Management and C&J are not guarantors. The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our 2021 RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any subsidiaries that do not guarantee the 2026 Notes, including the obligations of C&J Management and C&J under the 2022 ABL Facility. Berry LLC may, at its option, redeem all or a portion of the 2026 Notes at any time. If we experience certain kinds of changes of control, holders of the 2026 Notes may have the right to require us to repurchase their notes at 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any The indenture governing the 2026 Notes contains restrictive covenants that may limit our ability to, among other things: • incur or guarantee additional indebtedness or issue certain types of preferred stock; • pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; • transfer, sell or dispose of assets; • make investments; • create certain liens securing indebtedness; • enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; • consolidate, merge or transfer all or substantially all of our assets; and • engage in transactions with affiliates. The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain of our subsidiaries. We were in compliance with all covenants as of December 31, 2022. Debt Repurchase Program In February 2020, our Board of Directors adopted a program to spend up to $75 million for the opportunistic repurchase of our 2026 Notes. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any notes under this program. |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives We utilize derivatives, such as swaps, puts, calls and collars to hedge a portion of our forecasted oil and gas production and gas purchases to reduce exposure to fluctuations in oil and natural gas prices, which addresses our market risk. In addition to satisfying the oil hedging requirements in our 2021 RBL Facility, we target covering our operating expenses and a majority of our fixed charges, which includes capital needed to sustain production levels, as well as interest and fixed dividends as applicable, with the oil and gas sales hedges for a period of up to three years out. Additionally, we target fixing the price for a large portion of our natural gas purchases used in our steam operations for up to three years. We have also entered into Utah gas transportation contracts to help reduce the price fluctuation exposure, however these do not qualify as hedges. We also, from time to time, have entered into agreements to purchase a portion of the natural gas we require for our operations, which we do not record at fair value as derivatives because they qualify for normal purchases and normal sales exclusions. We had no such transactions in the periods presented. For fixed-price oil and gas sales swaps, we are the seller, so we make settlement payments for prices above the indicated weighted-average price per barrel and per mmbtu, respectively, and receive settlement payments for prices below the indicated weighted-average price per barrel and per mmbtu, respectively. For our long put spreads, in addition to any deferred premium payments, we would receive settlement payments for prices below the indicated highest price of the long put with the maximum payment received per bbl equal to the difference between the indicated prices of the long and short put. No payment would be made or received for prices above the highest indicated price of the long put. The short put spreads offset the long put spreads. A producer collar is used for the sale of our produced oil and is the combination of buying a put option and selling a call option. We would receive settlement payments for prices below the indicated weighted-average price per bbl of the put option and we would make settlement payments for prices above the indicated weighted-average price of the call option. No payment would be made or received for prices in between the indicated weighted-average price of the put and call. A consumer collar is used for the purchase of fuel gas and is the combination of buying a call option and selling a put option. We would receive settlement payments for prices above the indicated weighted-average price of the call option and we would make settlement payments for prices below the indicated weighted-average price of the put option. No payment would be made or received for prices in between the indicated weighted-average price of the put and call. For natural gas basis swaps, we make settlement payments if the difference between NWPL and Henry Hub is below the indicated weighted-average price of our contracts and receive settlement payments if the difference between NWPL and Henry Hub is above the indicated weighted-average price. For some of our options we paid or received a premium at the time the positions were created and for others, the premium payment or receipt is deferred until the time of settlement. As of December 31, 2022 we have net payable deferred premiums of approximately $5 million, which is reflected in the mark-to-market valuation and will be payable through December 31, 2024. As of December 31, 2022, we had the following crude oil production and gas purchases hedges. Q1 2023 Q2 2023 Q3 2023 Q4 2023 FY 2024 FY 2025 Brent - Crude Oil Production Swaps Hedged volume (bbls) 1,385,278 1,387,750 1,211,717 1,196,000 3,392,048 — Weighted-average price ($/bbl) $ 77.15 $ 77.01 $ 76.26 $ 76.18 $ 76.12 $ — Put Spreads Long $50/$40 Put Spread hedged volume (bbls) 630,000 637,000 644,000 644,000 1,647,000 — Short $50/$40 Put Spread hedged volume (bbls) 90,000 91,000 92,000 92,000 366,000 — Producer Collars Hedged volume (bbls) 360,000 364,000 368,000 368,000 1,098,000 2,212,500 Weighted-average price ($/bbl) $40.00/$106.00 $40.00/$106.00 $40.00/$106.00 $40.00/$106.00 $40.00/$105.00 $58.35/$91.45 Henry Hub - Natural Gas Purchases Consumer Collars Hedged volume (mmbtu) 2,110,000 1,820,000 — — — — Weighted-average price ($/mmbtu) $4.00/$2.75 $4.00/$2.75 $ — $ — $ — $ — NWPL - Natural Gas Purchases Hedged volume (mmbtu) 1,800,000 3,640,000 3,680,000 3,680,000 7,320,000 6,080,000 Weighted-average price ($/mmbtu) $ 6.40 $ 5.34 $ 5.34 $ 5.34 $ 4.27 $ 4.27 Gas Basis Differentials NWPL/HH - basis swaps Hedged volume (mmbtu) 1,800,000 1,820,000 1,840,000 1,840,000 — — Weighted-average price ($/mmbtu) $ 1.12 $ 1.12 $ 1.12 $ 1.12 $ — $ — In addition to the table above, in January 2023, we terminated the following basis swaps (NWPL/HH): 4,900,000 mmbtu (20,000 mmbtu/d) at $1.12 beginning March 2023 through October 2023, and 610,000 mmbtu (10,000 mmbtu/d) at $1.12 beginning November 2023 through December 2023. In January 2023 we also added the following Producer Collars (Brent): 3,627 bbl (117 bbl/d) at $60.00/$88.50 for January 2025, 270,000 bbl (3,000 bbl/d) at $60.00/$88.35 for January 2025 through March of 2025, and 472,500 bbl (5,250 bbl/d) at $60.00/$82.21 for January 2026 through March of 2026, which are in addition to the table above. These Producer Collars (Brent) were cashless. Our commodity derivatives are measured at fair value using industry-standard models with various inputs including publicly available underlying commodity prices and forward curves, and all are classified as Level 2 in the required fair value hierarchy for the periods presented. These commodity derivatives are subject to counterparty netting. The following tables present the fair values (gross and net) of our outstanding derivatives as of December 31, 2022 and 2021. The following tables present the fair values (gross and net) of our outstanding derivatives as of December 31, 2022 and 2021. December 31, 2022 Balance Sheet Classification Gross Amounts Recognized at Gross Amounts Offset Net Fair Value (in thousands) Assets: Commodity Contracts Current assets $ 66,974 $ (30,607) $ 36,367 Commodity Contracts Non-current assets 39,886 (39,810) 76 Liabilities: Commodity Contracts Current liabilities (61,713) 30,607 (31,106) Commodity Contracts Non-current liabilities (53,452) 39,810 (13,642) Total derivatives $ (8,305) $ — $ (8,305) December 31, 2021 Balance Sheet Classification Gross Amounts Recognized at Gross Amounts Offset Net Fair Value (in thousands) Assets: Commodity Contracts Current assets $ 5,360 $ (5,360) $ — Commodity Contracts Non-current assets 29,828 (28,758) 1,070 Liabilities: Commodity Contracts Current liabilities (34,985) 5,360 (29,625) Commodity Contracts Non-current liabilities (47,335) 28,758 (18,577) Total derivatives $ (47,132) $ — $ (47,132) By using derivative instruments to economically hedge exposure to changes in commodity prices, we expose ourselves to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We do not receive collateral from our counterparties. We minimize the credit risk in derivative instruments by limiting our exposure to any single counterparty. In addition, our 2021 RBL Facility prevents us from entering into hedging arrangements that are secured, except with our lenders and their affiliates that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A or A2 credit rating or better from Standards & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives which partially mitigates the counterparty nonperformance risk. (Losses) Gains on Derivatives A summary of gains and losses on the derivatives included on the statements of operations is presented below: Year Ended December 31, 2022 2021 2020 (in thousands) (Losses) gains on oil and gas sales derivatives $ (137,109) $ (156,399) $ 117,781 Gains (losses) on natural gas purchase derivatives 88,795 38,577 (1,035) Total (losses) gains on derivatives $ (48,314) $ (117,822) $ 116,746 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies In the normal course of business, we, or our subsidiaries, are the subject of, or party to, pending or threatened legal proceedings, contingencies and commitments involving a variety of matters that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, fines and penalties, remediation costs, or injunctive or declaratory relief. We accrue for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at December 31, 2022 and December 31, 2021. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of accruals on our balance sheet would not be material to our consolidated financial position or results of operations. We, or our subsidiaries, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of December 31, 2022, we are not aware of material indemnity claims pending or threatened against us. Securities Litigation Matter On November, 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class action lawsuit (the “Torres Lawsuit”) in the United States District Court for the Northern District of Texas against Berry Corp. and certain of its current and former directors and officers (collectively, the “Defendants”). The complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933, and Sections 10(b) and 20(a) of the Exchange Act, on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.'s securities between July 26, 2018 and November 3, 2020 (the “Class Period”). In particular, the complaint alleges that the Defendants made false and misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined following release of its financial results for the third quarter of 2020 on November 3, 2020. On November 1, 2021, the court-appointed co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a Motion to Dismiss on January 24, 2022 and on September 13, 2022, the Court issued an order denying that motion. The case is now in discovery. We dispute these claims and intend to defend the matter vigorously. Given the uncertainty of litigation, the early stage of the case, and the legal standards that must be met for, among other things, class certification and success on the merits, we cannot reasonably estimate the possible loss or range of loss that may result from this action. On October 20, 2022, a shareholder derivative lawsuit was filed in the United States District Court for the Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that piggy-backs on the securities class action referenced above and which is currently pending before the same Court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27, 2023, the court granted the parties’ joint stipulated request to stay the derivative action pending resolution of the related securities class action. The Company and the individual defendants believe the claims in the shareholder derivative action are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to this matter. On January 20, 2023, a second shareholder derivative lawsuit was filed, this time in the United States District Court for the District of Delaware, by putative stockholder Molly Karp allegedly on behalf of the Company, again piggy-backing on the securities class action referenced above. This complaint, similar to the first derivative complaint, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the securities violations alleged in the securities class action. In addition, the complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry’s 2022 Proxy Statement was false and misleading in that it suggested the Company’s internal controls were sufficient and the board of directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case. The defendants believe the claims in the shareholder derivative action are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to this matter. Other Commitments In the ordinary course of our business, we enter into certain firm commitments to secure transportation of our production and third-party natural gas to market as well as processing which require a minimum monthly charge regardless of whether the contracted capacity is used or not. At December 31, 2022, future net minimum payments for non-cancelable purchase obligations (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance expense) were as follows: 2023 2024 2025 2026 2027 Thereafter Total (in thousands) Processing and transportation contracts (1) $ 11,343 $ 9,553 $ 8,234 $ 8,082 $ 8,083 $ 43,521 $ 88,816 Drilling commitment (2) 8,400 8,700 — — — — 17,100 Total $ 19,743 $ 18,253 $ 8,234 $ 8,082 $ 8,083 $ 43,521 $ 105,916 __________ (1) Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure pipeline transportation of natural gas to market and between markets, as well as gathering and processing of natural gas. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Stockholders' Equity | Stockholders' Equity Cash Dividends Our Board of Directors approved quarterly fixed cash dividends totaling $0.24 per share in 2022, as well as variable cash dividends of $1.10 per share, which were based on the results in 2022, for a total of $1.34 per share. In February 2023, our Board of Directors approved a fixed cash dividend of $0.06 per share, as well as, the variable cash dividend of $0.44 per share based on the fourth quarter of 2022 results. For the year ended December 31, 2022, December 31, 2021, December 31, 2020 we paid approximately $109 million, $11 million and $19 million, respectively, in cash dividends on our common stock. The Company anticipates that it will continue to pay quarterly cash dividend in the future. However, the payment and amount of future dividends remain within the discretion of the Board and will depend upon the Company’s future earnings, financial condition, capital requirements, and other factors. Common Stock On March 1, 2022, our Board of Directors approved the 2022 Omnibus Incentive Plan (the “2022 Omnibus Plan”), which was subsequently approved by stockholders on May 25, 2022. The plan authorized the issuance of 2,300,000 shares of common stock. The maximum number of shares remaining that may be issued is 1,573,402 as of December 31, 2022, which is the total number of shares of our common stock remaining available for issuance after counting the number of securities to be issued upon vesting of outstanding RSU and PSU awards, and counting PSUs at the maximum payout level. Shares reserved at maximum payout that do not vest at maximum are made available for future grants. On June 27, 2018, our board of directors adopted the second amended and restated 2017 Omnibus Incentive Plan (“2017 Omnibus Plan”), as amended and restated (our “Restated Incentive Plan”). This plan constitutes an amendment and restatement of the plan (the “Prior Plan”) as in effect immediately prior to the adoption of the Restated Incentive Plan. The Prior Plan constituted an amendment and restatement of the plan originally adopted as of June 15, 2017 (the “2017 Omnibus Plan”). The Restated Incentive Plan provides for the grant, from time to time, at the discretion of the board of directors or a committee thereof, of stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards. The maximum number of shares of common stock that may be issued pursuant to an award under the Restated Incentive Plan is 10,000,000 inclusive of the number of shares of common stock previously issued pursuant to awards granted under the Prior Plan or the 2017 Plan. Voting Rights . Each share of common stock is entitled to one vote with respect to each matter on which holders of common stock are entitled to vote. Holders of common stock do not have cumulative voting rights. Dividend Rights . Holders of common stock will be entitled to receive dividends, if any, as may be declared from time to time by our board of directors (the “Board”) out of legally available funds. Liquidation Rights . Upon liquidation, dissolution or winding up of the Company, holders of our common stock will be entitled to share ratably in the assets of the Company that are legally available for distribution to holders of our common stock after payment of the Company’s debts and other liabilities. Preemptive and Conversion Rights. Holders of common stock have no preemptive, conversion or other rights to subscribe for additional shares. Registration Rights Agreement On June 28, 2018, Berry Corp. entered into an amended and restated registration rights agreement (the “Registration Rights Agreement”) with certain holders of our Common Stock and Preferred Stock in connection with our IPO. In accordance with the Registration Rights Agreement, Berry Corp. filed a shelf registration statement with the SEC on December 10, 2018, which was declared effective on December 13, 2018. The shelf registration statement registered the resale, on a delayed or continuous basis, of all Registrable Securities that have been timely designated for inclusion by specified Holders (as defined in the Registration Rights Agreement). Generally, “Registrable Securities” includes (i) common stock and preferred stock issued by Berry Corp. in connection with the IPO to stockholders party to the Registration Rights Agreement, and (ii) preferred stock that was purchased by the participants in the rights offering noted above and (iii) common stock into which the preferred stock converts, except that “Registrable Securities” does not include securities that have been sold under an effective registration statement or Rule 144 under the Securities Act. The Registration Rights Agreement will terminate when there are no longer any Registrable Securities outstanding. Shares Outstanding As of December 31, 2022, there were 75,767,503 shares of common stock outstanding. Up to an additional 8,110,302 shares were issuable for unvested restricted stock units and performance restricted stock units (assuming maximum achievement of performance goals) under the Company's 2022 Omnibus Incentive Plan as of December 31, 2022. Repurchase Program For the year ended December 31, 2022, we repurchased 5 million shares for approximately $51 million. As of December 31, 2022, the Company had repurchased a total of 10,528,704 shares under the stock repurchase program for approximately $104 million in aggregate. As previously disclosed, the Company implemented a shareholder return model in early 2022, for which the Company intends to allocate a portion of Adjusted Free Cash Flow to opportunistic share repurchases. In April 2022, our Board of Directors approved an increase of $102 million to the Company’s stock repurchase authorization bringing the Company’s remaining share repurchase authority to $150 million. As of December 31, 2022, the Company’s remaining total share repurchase authority is $98 million, after the repurchases made in the second, third, and fourth quarters of 2022. In February 2023, the Board of Directors approved an increase of $102 million to the Company’s stock repurchase authorization bringing the Company’s remaining share authority to $200 million. The Board’s authorization permits the Company to make purchases of its common stock from time to time in the open market and in privately negotiated transactions, subject to market conditions and other factors, up to the aggregate amount authorized by the Board. The Board’s authorization has no expiration date. We repurchased approximately $2 million of shares in 2021 and none in 2020. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate the company to purchase shares during any period or at all. Any shares repurchased are reflected as treasury stock and any shares acquired will be available for general corporate purposes. Stock-Based Compensation The Company has awarded restricted stock units (“RSUs”) that are solely time-based awards and performance-based restricted stock units (“PSUs”) that include (i) awards with a market objective measured against both absolute total stockholder return (“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR PSUs”) over the performance period and (ii) awards based on the Company's average cash returned on invested capital (“CROIC PSUs”) over the performance period. Depending on the results achieved during the three-year performance period, the actual number of shares that a grant recipient receives at the end of the period may range from 0% to 250% of the TSR PSUs granted in 2022 and 2021, 0% to 200% of the TSR PSUs granted in 2020, 0% to 200% of the CROIC PSUs granted in 2022 and 2021, and 0% to 200% of the ROIC PSUs granted in 2022. No CROIC PSUs were granted prior to 2021 and no ROIC PSUs were granted prior to 2022. The fair value of the RSUs, CROIC PSUs and ROIC PSUs was determined using the grant date stock price. The fair value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the peer group over the performance periods. The expected volatility of the Company’s common stock at the date of grant was estimated based on average volatility rates for the Company and selected guideline public companies. The dividend yield assumption was based on the then current annualized declared dividend. The risk-free interest rate assumption was based on observed interest rates consistent with the three-year performance measurement period. The PSUs awarded in February 2022 were accounted for as liability awards in the first quarter of 2022, but were converted to equity awards during the second quarter of 2022 due to the approval of the 2022 Omnibus Plan by the stockholders in May 2022. For the years ended December 31, 2022, 2021, and 2020 the stock-based compensation expense was approximately $18 million, $14 million, and $15 million, respectively. For the year ended December 31, 2022, the income tax benefit was $2 million. For the years ended December 31 2021 and 2020 the stock-based compensation income tax benefit was not material. The table below summarizes the activity relating to RSUs issued under the Restated Incentive Plan during the year ended December 31, 2022. The RSUs vest ratably over three years. Unrecognized compensation cost associated with the RSUs at December 31, 2022 was approximately $10 million which will be recognized over a weighted-average period of approximately two years. Number of shares Weighted-average Grant Date Fair Value (shares in thousands) Non-vested at December 31, 2021 2,580 $ 5.67 Granted 1,317 $ 8.92 Vested (1,145) $ 6.36 Forfeited (233) $ 6.97 Non-vested at December 31, 2022 2,519 $ 6.94 The table below summarizes the activity relating to the PSUs issued under the Revised Incentive Plan during the year ended December 31, 2022. Unrecognized compensation cost associated with the PSUs at December 31, 2022 is approximately $8 million which will be recognized over a weighted-average period of approximately two years. Number of shares Weighted-average Grant Date Fair Value (shares in thousands) Non-vested at December 31, 2021 2,085 $ 11.00 Granted 611 $ 12.03 Vested (36) $ 12.75 Forfeited (59) $ 12.51 Non-vested at December 31, 2022 2,601 $ 11.18 |
Defined Contribution Plan
Defined Contribution Plan | 12 Months Ended |
Dec. 31, 2022 | |
Retirement Benefits [Abstract] | |
Defined Contribution Plan | Defined Contribution Plan We sponsor a defined contribution retirement plan under section 401(k) of the Internal Revenue Code to assist all full-time employees in providing for retirement or other future financial needs. Employees are eligible to participate in the 401(k) plan on their date of hire. The 401(k) plan provided for a matching contribution of up to 6% of an employee’s eligible compensation until June 2020 when the Company temporarily suspended matching due to COVID-19. As of January 2021, the Company reinstated the Plan's matching contributions to 100% of the first 3% of compensation deferred by the participant. As of July 2021, the Company increased the Plan's matching contributions to 100% of the first 6% of compensation deferred by the participant. We expensed approximately $6.2 million, $1.6 million, and $1.0 million for the years ended December 31, 2022, 2021, and 2020, respectively, under the provisions of the 401(k) plan. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income TaxesThe change in our effective rate from (10.0)% in the year ended December 31, 2021 to (20.4)% for the year ended December 31, 2022 is primarily due to recognition of U.S. federal general business credits in 2022 related to the 2021 tax period and release of the valuation allowance. The credits are available to offset future federal income tax liabilities. The change in our effective rate from 2.8% in the year ended December 31, 2020 to (10.0)% for the year ended December 31, 2021 is primarily due to nondeductible stock compensation, adjustments to our tax credit carryforward balances and changes in the valuation allowance. Income tax expense (benefit) consisted of the following: Year Ended December 31, 2022 2021 2020 (in thousands) Current taxes: Federal $ 642 $ — $ — State 1,597 581 828 Total current taxes 2,239 581 828 Deferred taxes: Federal (44,053) 832 2,653 State (622) — (10,699) Total deferred taxes (44,675) 832 (8,046) Total current and deferred taxes $ (42,436) $ 1,413 $ (7,218) A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, 2022 2021 2020 Federal statutory rate 21.0 % 21.0 % 21.0 % State, net of federal tax benefit 6.2 % 3.7 % 6.3 % Nondeductible compensation 1.8 % (24.5) % — % Effect of permanent differences (0.3) % (4.7) % (0.6) % Tax credits - Prior Year (11.5) % (29.5) % 4.9 % Tax credits - Current Year — % 21.5 % 1.1 % State return to provision (0.3) % (0.2) % (1.1) % Change in valuation allowance (37.3) % 2.7 % (28.8) % Effective tax rate (20.4) % (10.0) % 2.8 % Significant components of the deferred tax assets and liabilities are as follows: Year Ended December 31, 2022 2021 (in thousands) Deferred tax assets: Net operating loss carryforwards $ 22,402 $ 40,846 Accruals 10,728 11,731 Asset retirement obligations 48,994 44,437 Derivative instruments 2,280 12,776 Tax credits 88,908 61,044 Other 2,882 3,551 Subtotal 176,194 174,385 Valuation allowance — (77,546) Total deferred tax assets 176,194 96,839 Deferred tax liabilities: Book tax differences in property basis (133,350) (98,670) Total deferred tax liabilities (133,350) (98,670) Net deferred tax asset (liability) $ 42,844 $ (1,831) As of December 31, 2022, the Company had approximately $107 million of federal net operating loss (“NOL”) carryforwards and no state net operating loss carryforwards. The federal net operating loss carryovers have no expiration date. In addition, as of December 31, 2022, the Company had US federal general business tax credit carryforwards totaling $82 million and state tax credits of $8 million ($7 million net of federal benefit), which, if unused, will expire after taxable years ended 2037 and 2033, respectively. In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those deferred income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and projected future income for this determination. As of December 31, 2022, due to the positive evidence of current year income, fair value of proved reserves and related future income projections, commodity price forecasts based on published market quotes, and the reversal of existing federal and state temporary differences, and based on the preponderance of that evidence, we determined there is sufficient positive evidence to conclude that is is more likely than not that our deferred tax assets are realizable. Therefore, we have fully released the valuation allowance in 2022, resulting in an income tax benefit of $78 million. We previously recorded a valuation allowance on our deferred tax assets for the year ended December 31, 2021 in the amount of $78 million. We had no material uncertain tax positions at December 31, 2022 or 2021. We do not believe that the total unrecognized benefits will significantly increase within the next 12 months. We are subject to taxation in the United States and various state jurisdictions. We are not currently under audit by any federal or state income tax authority. The 2019 through 2022 federal and 2018 through 2022 state tax years generally remain open to examination under the respective statute of limitations. |
Supplemental Disclosures to the
Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows | Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows Other current assets reported on the consolidated balance sheets included the following: Year Ended December 31, 2022 2021 (in thousands) Prepaid expenses $ 12,330 $ 26,840 Materials and supplies 8,976 9,533 Prepaid deposits 7,266 6,415 Oil inventories 4,036 2,933 Other 1,117 225 Total other current assets $ 33,725 $ 45,946 Other non-current assets at December 31, 2022 included approximately $6 million of operating lease right-of-use assets, net of amortization and $4 million of deferred financing costs, net of amortization. At December 31, 2021 other non-current assets included approximately $5 million of deferred financing costs, net of amortization. Accounts payable and accrued expenses on the consolidated balance sheets included the following: Year Ended December 31, 2022 2021 (in thousands) Accounts payable - trade $ 40,286 $ 17,699 Accrued expenses 85,360 62,962 Royalties payable 38,264 24,816 Greenhouse gas liability - current portion — 7,513 Taxes other than income tax liability 6,640 8,273 Accrued interest 10,885 10,736 Dividends payable — 4,800 Asset retirement obligation - current portion 20,000 20,000 Operating lease liability 1,666 — Other — 725 Total accounts payable and accrued expenses $ 203,101 $ 157,524 At December 31, 2022 other non-current liabilities included approximately $23 million non-current greenhouse gas liability, which is due 2024, and $5 million of non-current operating lease liability. At December 31, 2021 we had $18 million non-current greenhouse gas liability, which is due in 2024. Supplemental Information on the Statement of Operations For the years ended December 31, 2022, 2021, and 2020 other operating expenses were $4 million, $3 million, and $6 million respectively. For the year ended December 31, 2022, other operating expenses mainly consisted of approximately $2 million in royalty audit charges incurred prior to our emergence and restructuring in 2017, and approximately $2 million loss on the divestiture of the Piceance properties. For the year ended December 31, 2021, other operating expenses mainly consisted of expensing $3 million of unamortized debt issuance costs related to the 2017 RBL facility, approximately $3 million of supplemental property tax assessments, royalty audit charges and tank rental costs, and $2 million of various other costs such as excess abandonment costs and legal fees, partially offset by approximately $2 million on gain on the sale of properties and over $2 million of income from employee retention credits. For the year ended December 31, 2020, other operating expenses included of $3 million of excess abandonment costs, $2 million of oil tank storage fees, and $1 million of drilling rig standby charges. Supplemental Cash Flow Information Supplemental disclosures to the consolidated statements of cash flows are presented below: Year Ended December 31, 2022 2021 2020 (in thousands) Supplemental Disclosures of Significant Non-Cash Operating Activities: Greenhouse gas liability - reclassification from current liability to long-term $ 8,000 $ — $ — Greenhouse gas liability - reclassification from long-term to current liability $ — $ — $ 33,376 Supplemental Disclosures of Significant Non-Cash Investing Activities: Material inventory transfers to oil and natural gas properties $ 2,707 $ 3,424 $ 1,596 Supplemental Disclosures of Cash Payments (Receipts): Interest, net of amounts capitalized $ 29,792 $ 29,211 $ 29,962 Income taxes payments $ 3,633 $ 699 $ 222 |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2022 | |
Business Combination and Asset Acquisition [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures 2022 Piceance Divestiture In January 2022, we completed the divestiture of all of our natural gas properties in Colorado, which were in the Piceance basin. The divestiture closed with a loss of approximately $2 million. Our 2021 production from these properties was 1.2 mboe/d. Antelope Creek Acquisition In February 2022, we completed the acquisition of oil and gas producing assets in the Antelope Creek area of Utah for approximately $18 million. These assets are adjacent to our existing Uinta assets and prior to our acquisition produced approximately 0.6 mboe/d. Purchases of Various Oil and Gas Properties During 2022, we also acquired various oil and gas properties, most of which consisted of unproved properties for approximately $8 million in aggregate. 2021 C&J Well Services Acquisition On October 1, 2021, we acquired one of the largest well servicing and abandonment businesses in California, which operates as CJWS. The purchase price was $53 million, including closing adjustments mainly related to working capital, which we funded with cash on hand of $51 million in 2021 and $2 million in 2022. The CJWS transaction costs were approximately $3 million. The acquired business activities are owned and operated by C&J Well Services, a wholly-owned subsidiary of Berry Corp. formed for the purposes of acquiring these businesses and establishing an independent well services and abandonment company. The CJWS transaction was accounted for as a business combination under the acquisition method of accounting. When determining the fair values of assets acquired and liabilities assumed, management made significant estimates, judgments and assumptions. The assets acquired and liabilities assumed are included in the well servicing and abandonment segment. The unaudited pro forma information presented below has been prepared to give effect to the CJWS acquisition as if it had occurred at the beginning of the periods presented. The unaudited pro forma information includes the effects from the allocation of the acquisition purchase price on depreciation and amortization as well as the CJWS acquisition costs charged to earnings during the 2021 period. The unaudited pro forma information is presented for illustration purposes only and is based on estimates and assumptions the Company deemed appropriate. The following unaudited pro forma information is not necessarily indicative of the results that would have been achieved if the CJWS acquisition had occurred in the past, and should not be relied upon as an indication of the operating results that the Company would have achieved if the acquisition had occurred at the beginning of the periods presented, and our operating results, or the future results. Pro Forma Year Ended December 31, 2021 2020 (unaudited) (in thousands) Revenue $ 664,549 $ 657,796 Net income (loss) $ 740 $ (250,884) Placerita Divestiture In October 2021, our E&P segment completed the sale of our Placerita Field property in the Ventura Basin in Los Angeles County, California for approximately $14 million. We recorded a gain on the sale of approximately $2 million in 2021. 2020 In May 2020, we acquired approximately 740 net acres in the North Midway Sunset Field for approximately $5 million. We paid $2 million at closing and the remaining $3 million was paid following our first production from this property, in the fourth quarter 2020. This property is adjacent to, and extends, our existing producing area and we have identified numerous future drilling locations. We believe additional opportunities exist in other productive reservoirs of this property. We also acquired all existing idle wells on this property, some of which we plan to return to production in the near future as price and strategy dictate. We will plug and abandon the remaining idle wells pursuant to our California idle well management plan. We recorded a $6 million liability for asset retirement obligations of the existing wells on this property. We also acquired approximately 267 acres in McKittrick Field which will allow us to continue development of the 21Z mineral fee and leases without requiring written approval from a third party surface fee owner for infrastructure on or across the surface fee property. The purchase price was not material. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share We calculate basic earnings (loss) per share by dividing net income (loss) by the weighted-average number of common shares outstanding for each period presented. Common shares issuable upon the satisfaction of certain conditions pursuant to a contractual agreement, are considered common shares outstanding and are included in the computation of net earnings (loss) per share. The RSUs and PSUs are not a participating security as the dividends are forfeitable. For the year ended December 31, 2022, 4,069,000 incremental RSU and PSU shares were included in the diluted EPS calculation. For the years ended December 2021 and 2020, no incremental RSU or PSU shares were included in the diluted EPS calculation as their effect was anti-dilutive under the “if-converted” method. Year Ended December 31, 2022 2021 2020 (in thousands except per share amounts) Basic EPS calculation Net income (loss) $ 250,168 $ (15,542) $ (262,895) Weighted-average shares of common stock outstanding 78,517 80,209 79,802 Basic income (loss) per share $ 3.19 $ (0.19) $ (3.29) Diluted EPS calculation Net income (loss) $ 250,168 $ (15,542) $ (262,895) Weighted-average shares of common stock outstanding 78,517 80,209 79,802 Dilutive effect of potentially dilutive securities (1) 4,069 — — Weighted-average common shares outstanding - diluted 82,586 80,209 79,802 Diluted income (loss) per share $ 3.03 $ (0.19) $ (3.29) __________ (1) We excluded 3.3 million and 0.1 million of combined RSUs and PSUs from the diluted weighted-average common shares outstanding because their effect was anti-dilutive for the years ended December 31, 2021 and 2020, respectively. |
Revenue Recognition
Revenue Recognition | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition | Revenue Recognition We account for revenue in accordance with the Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers, using the modified retrospective method. The performance obligations that are unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these are wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation as well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation. We derive revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with the remaining revenue generated from sales of electricity and marketing activities. Effective October 1, 2021, we completed the acquisition of CJWS, a well servicing and abandonment business. Revenue from CJWS is primarily generated from well servicing and abandonment business. The following is a description of our principal activities from which we generate revenue. Revenues are recognized when a customer obtains control of promised goods or services, in an amount that reflects the consideration we expect to receive in exchange for those goods or services. Oil, Natural Gas and NGLs We recognize revenue from the sale of our oil, natural gas and NGL production when delivery has occurred and control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our NGL contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the amount that we expect to receive once we are able to adequately estimate the consideration (i.e., when market prices are known or estimated). Our contracts with customers typically require payment within 30 days following invoicing. Service Revenue We recognize service revenue from the well servicing and abandonment business upon delivery of the service to the customer. These services are consumed by our customers when they are provided on their sites. Revenue is recognized as performance obligations have been completed on a daily basis, when all of the proper customer approvals are obtained. We do not have any long-term service contracts; nor do we have revenue expected to be recognized in any future year related to remaining performance obligations or contracts with variable consideration related to undelivered performance obligations. Our contracts with customers typically require payment within 30-60 days following invoicing. Electricity Sales The electrical output of our cogeneration facilities that is not used in our operations is sold to the California market based on market pricing, which includes capacity payments. The portion sold from our cogeneration facilities is sold under contracts to California utility companies, based on the market pricing. Revenue is recognized over time when obligations under the terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the electricity. Revenue is measured as the amount of consideration we expect to receive based on average index pricing with payment due the month following delivery. Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on seasonality, which is consistent with how we earn the capacity payment. Capacity payments are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the case of capacity payments. We report electricity revenue as electricity sales on our consolidated statements of operations. Marketing Revenue Marketing revenue primarily includes our activities associated with transporting and marketing third-party volumes. These sales are made under the same agreements with the same purchaser as our natural gas sales discussed above. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Revenues are presented excluding costs incurred prior to transferring control of these volumes to the customer, or the costs to purchase these volumes when we are acting as the principal. The revenues and expenses related to the sale and purchase of third-party volumes are presented separately as marketing revenue and marketing expenses on the consolidated statements of operations. In January 2022, we sold our Piceance Colorado operations, which included third-party marketing activities. Historically, these activities accounted for nearly all of our marketing revenues. Disaggregated Revenue As a result of adoption of this standard, we are now required to disclose the following information regarding revenue from contracts with customers on a disaggregated basis. Year Ended December 31, 2022 2021 2020 (in thousands) Oil sales $ 806,631 $ 587,613 $ 362,976 Natural gas sales 29,515 32,679 14,041 Natural gas liquids sales 6,303 5,183 1,646 Service revenue 181,400 35,840 — Electricity sales 30,833 35,636 25,813 Marketing revenues 289 3,921 1,426 Other revenues 479 477 150 Revenues from contracts with customers 1,055,450 701,349 406,052 (Losses) gains on oil and gas sales derivatives (137,109) (156,399) 117,781 Total revenues and other $ 918,341 $ 544,950 $ 523,833 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information As of October 1, 2021, we have operated in two business segments: (i) E&P and (ii) well servicing and abandonment. The E&P segment is engaged in the development and production of onshore, low geologic risk, long-lived conventional oil reserves primarily located in California, as well as Utah. On October 1, 2021, we completed the acquisition of an upstream well servicing and abandonment businesses in California, which became a reportable segment (wells servicing and abandonment) under U.S. GAAP. Prior to October 1, 2021, we did not have more than one reportable segment, thus no prior period segment information has been presented. The well servicing and abandonment segment occasionally provides services to our E&P segment, as such, we recorded an intercompany elimination of $3 million in revenue and expense during consolidation. The intercompany elimination in 2021 was immaterial. The following table represents selected financial information for the periods presented regarding the Company's business segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis. Year Ended December 31, 2022 E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company (in thousands) Revenues (1) $ 874,190 $ 184,448 $ (3,188) $ 1,055,450 Net income (loss) before income taxes $ 303,178 $ 14,747 $ (110,193) $ 207,732 Adjusted EBITDA $ 411,811 $ 26,113 $ (57,976) $ 379,948 Capital expenditures $ 141,930 $ 8,455 $ 2,536 $ 152,921 Total assets $ 1,563,251 $ 83,461 $ (15,682) $ 1,631,030 Year Ended December 31, 2021 E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company (in thousands) Revenues (1) $ 665,509 $ 35,840 $ — $ 701,349 Net income (loss) before income taxes $ 82,826 $ 1 $ (96,956) $ (14,129) Adjusted EBITDA $ 251,146 $ 4,310 $ (43,310) $ 212,146 Capital expenditures $ 129,479 $ 1,029 $ 2,211 $ 132,719 Total assets $ 1,450,157 $ 81,093 $ (74,771) $ 1,456,479 __________ (1) These revenues do not include hedge settlements. Adjusted EBITDA is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources to and assessing performance of each segment. Adjusted EBITDA is calculated as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items. Year Ended December 31, 2022 Well Servicing and Abandonment Corporate/Eliminations Consolidated Company (in thousands) Adjusted EBITDA reconciliation to net income (loss): Net income (loss) $ 303,178 $ 14,747 $ (67,757) $ 250,168 Add (Subtract): Interest expense — 23 30,894 30,917 Income tax benefit — — (42,436) (42,436) Depreciation, depletion, and amortization 139,886 12,548 4,413 156,847 Losses on derivatives 48,314 — — 48,314 Net cash paid for scheduled derivative settlements (88,023) — — (88,023) Other operating expenses (income) 3,827 (1,690) 1,585 3,722 Stock compensation expense 1,361 287 15,325 16,973 Non-recurring costs (1) 3,268 198 — 3,466 Adjusted EBITDA $ 411,811 $ 26,113 $ (57,976) $ 379,948 __________ (1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022 and the executive transition costs in the fourth quarter of 2022. Year Ended December 31, 2021 E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company (in thousands) Adjusted EBITDA reconciliation to net income (loss): Net income (loss) $ 82,825 $ 1 $ (98,368) $ (15,542) Add (Subtract): Interest expense — — 31,964 31,964 Income tax expense — — 1,413 1,413 Depreciation, depletion, and amortization 136,915 2,974 4,606 144,495 Losses on derivatives 117,822 — — 117,822 Net cash paid for scheduled derivative settlements (87,625) — — (87,625) Other operating expenses 109 — 2,992 3,101 Stock compensation expense 1,100 — 12,683 13,783 Non-recurring costs (1) — 1,335 1,400 2,735 Adjusted EBITDA $ 251,146 $ 4,310 $ (43,310) $ 212,146 __________ (1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the fourth quarter of 2021. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
Leases | Leases In the first quarter of 2022, we adopted ASC 842, Leases using the modified retrospective approach that requires us to determine our lease balances as of the date of adoption. Prior periods continue to be reported under accounting standards in effect for those periods. The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability and an equal amount is capitalized as a right of use asset on the Company’s balance sheet. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. We have long-term operating leases generally for offices. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. Leases with an initial term of 12 months or less are not recorded on the balance sheet and the Company recognizes lease expense for these leases on a straight-line basis over the lease term. The components of lease expense are as follows: Year Ended December 31, 2022 (in thousands) Lease Cost Operating lease cost $ 1,992 Total net lease cost $ 1,992 The following table presents the consolidated balance sheet information related to leases as of December 31, 2022. As of December 31, 2022 Balance Sheet Classification (in thousands) Leases Assets Operating lease assets $ 6,325 Other noncurrent assets Total assets $ 6,325 Liabilities Operating lease liability $ 1,666 Accounts payable and accrued expenses Operating lease noncurrent liability 5,213 Other noncurrent liabilities Total liabilities $ 6,879 As of December 31, 2022 Long-Term and Discount Rate Weighted-average remaining lease term: Operating Lease 4.3 years Weighted-average discount rate: Operating Lease 5 % The following table presents a schedule of future minimum lease payments required under all operating lease agreements as of December 31, 2022. As of December 31, 2022 Operating Leases (in thousands) 2023 $ 1,963 2024 1,650 2025 1,542 2026 1,549 2027 935 Total lease payments 7,639 Less imputed interest (760) Total lease obligations 6,879 Less current obligations (1,666) Long-term lease obligations $ 5,213 Supplemental consolidated statement of cash flow information related to leases is as follows: Year Ended December 31, 2022 (in thousands) Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 2,128 ROU assets obtained in exchange for operating lease liabilities $ 7,956 |
Basis of Presentation and Sig_2
Basis of Presentation and Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Principles of Consolidation and Reporting | Principles of Consolidation and ReportingThe consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”), which requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. We eliminated all significant intercompany transactions and balances upon consolidation. For oil and gas E&P joint ventures in which we have a direct working interest, we account for our proportionate share of assets, liabilities, revenue, expense and cash flows within the relevant lines of the financial statements. |
Segment Reporting | Segment Reporting The Company has two reportable segments. Reportable segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker (“CODM”), our Chief Executive Officer, in deciding how to allocate resources and assess performance. The E&P segment consists of the development and production of onshore, low geologic risk, long-lived conventional oil and gas reserves, primarily located in California, as well as Utah. The well servicing and abandonment segment provides wellsite services in California to oil and natural gas production companies, with a focus on well servicing, well abandonment services and water logistics. |
Use of Estimates | Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP required management of the Company to make informed estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. |
Cash Equivalents | Cash Equivalents We consider all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. |
Inventories | Inventories Inventories were included in other current assets. Oil and natural gas inventories were valued at the lower of cost or net realizable value. Materials and supplies were valued at their weighted-average cost and are reviewed periodically for obsolescence. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties Proved Properties We account for oil and natural gas properties in accordance with the successful efforts method. Under this method, all acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves. All development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved developed reserves. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in the current period. Gains or losses from the disposal of other properties are recognized in the current period. For assets acquired, we base the capitalized cost on fair value at the acquisition date. We expense expenditures for maintenance and repairs necessary to maintain properties in operating condition, as well as annual lease rentals, as they are incurred. Estimated dismantlement and abandonment costs are capitalized at their estimated net present value and amortized over the remaining lives of the related assets. Interest is capitalized only during the periods in which these assets are brought to their intended use. The amount of capitalized interest was approximately $1 million, $2 million and $1 million in 2022, 2021 and 2020, respectively. We only capitalize the interest on borrowed funds related to our share of costs associated with qualifying capital expenditures. The amount of capitalized exploratory well costs was zero for all periods and the amount of capitalized overhead was approximately $6 million, $7 million and $6 million in 2022, 2021 and 2020, respectively. We evaluate the impairment of our proved oil and natural gas properties and other property and equipment generally on a field-by-field basis or at the lowest level for which cash flows are identifiable, whenever events or changes in circumstance indicate that the carrying value may not be recoverable. We reduce the carrying values of proved properties to fair value when the expected undiscounted future cash flows are less than net book value. We measure the fair values of proved properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a risk-adjusted discount rate. These inputs require significant judgments and estimates by our management at the time of the valuation which can change significantly over time. The underlying commodity prices are embedded in our estimated cash flows and are the product of a process that begins with the relevant forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors our management believes will impact realizable prices. The fair value was estimated using inputs characteristic of a Level 3 fair value measurement. Unproved Properties A portion of the carrying value of our oil and gas properties was attributable to unproved properties. At December 31, 2022 and 2021, the net capitalized costs attributable to unproved properties was approximately $248 million and $292 million, respectively. The unproved amounts were not subject to depreciation, depletion and amortization until they were classified as proved properties and amortized on a unit-of-production basis. We evaluate the impairment of our unproved oil and gas properties whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, adverse change in regulatory environment, contractual conditions or other factors, the capitalized costs of such properties would be expensed. The timing of any write-downs of unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results. Impairment In 2022 and 2021, we did not record any impairment charges for proved and unproved properties. As of March 31, 2020, we performed impairment tests with respect to our proved and unproved oil and gas properties and other property and equipment as a result of significant declines in oil prices during the latter part of the first quarter 2020. We recorded a non-cash pre-tax asset impairment charge of $289 million during the first quarter of 2020 on proved properties in Utah and certain California locations and other property and equipment. We evaluated our proved properties in accordance with accounting guidance and fair value techniques utilizing the period-end forward price curve, as well as assessing projects we determine we would not pursue in the foreseeable future given the current environment. We determined based on plans and exploration and development efforts no impairment was necessary for our unproved property balance in 2020. |
Other Property and Equipment | Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, cogeneration facilities, buildings, well servicing and abandonment vehicles and equipment, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost, depreciated using the straight-line method based on expected useful lives ranging from 15 to 39 years for buildings and improvements, 20 to 30 years for cogeneration facilities, natural gas plants and pipelines, 1 to 10 years for furniture and equipment, 1 to 10 years for well servicing and abandonment vehicles and equipment and other equipment, and the salvage value is considered as applicable. Other property and equipment assets are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. |
Business Combinations | Business Combinations The Company records business combinations using the acquisition method of accounting. Under the acquisition method of accounting, identifiable assets acquired and liabilities assumed are recorded at their acquisition-date fair values. The excess of the purchase price over the estimated fair value, if any, is recorded as goodwill. Changes in the estimated fair values of net assets recorded for acquisitions prior to the finalization of more detailed analysis, but not to exceed one year from the date of acquisition, will adjust the amount of the purchase price allocations accordingly. Measurement period adjustments are reflected in the period in which they occur. We account for acquisitions of businesses using the acquisition method of accounting, which requires the allocation of the purchase price consideration based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. Our estimates and judgments of the fair value of acquired businesses could prove to be inexact, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price consideration to acquired assets and liabilities, which could result in asset impairments, the recording of previously unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets and liabilities is increased during periods of economic uncertainty. |
Asset Retirement Obligation | Asset Retirement Obligation We recognize the fair value of asset retirement obligations (“AROs”) in the period in which a determination is made that a legal obligation exists to dismantle an asset and remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts were based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalized the cost by increasing the related property, plant and equipment (“PP&E”) balances. If the estimated future cost of the AROs changes, we record an adjustment to both the ARO and PP&E. Over time, the liability is increased and the capitalized cost is depreciated over the useful life of the asset. Accretion expense is also recognized over time as the discounted liabilities are accreted to their expected settlement value and is included in depreciation, depletion and amortization in the statement of operations. |
Revenue Recognition | Revenue RecognitionThe majority of the Company's revenue is from the E&P business, which includes the sale of crude oil, natural gas and NGLs, as well as electricity from its cogeneration plants. The remaining revenue is generated from the well servicing and abandonment business. We account for revenue in accordance with the Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers, using the modified retrospective method. The performance obligations that are unsatisfied at the end of a reporting period relate solely to future volumes that we have yet to sell. As such, these are wholly unsatisfied performance obligations as each unit of product represents a separate performance obligation as well as a wholly unsatisfied promise to transfer a distinct good that forms part of a single performance obligation. We derive revenue from sales of oil, natural gas and natural gas liquids (“NGL”), with the remaining revenue generated from sales of electricity and marketing activities. Effective October 1, 2021, we completed the acquisition of CJWS, a well servicing and abandonment business. Revenue from CJWS is primarily generated from well servicing and abandonment business. The following is a description of our principal activities from which we generate revenue. Revenues are recognized when a customer obtains control of promised goods or services, in an amount that reflects the consideration we expect to receive in exchange for those goods or services. Oil, Natural Gas and NGLs We recognize revenue from the sale of our oil, natural gas and NGL production when delivery has occurred and control passes to the customer. Our oil and natural gas contracts are short term, typically less than a year and our NGL contracts are both short and long term. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Our commodity sales contracts are indexed to a market price or an average index price. We recognize revenue in the amount that we expect to receive once we are able to adequately estimate the consideration (i.e., when market prices are known or estimated). Our contracts with customers typically require payment within 30 days following invoicing. Service Revenue We recognize service revenue from the well servicing and abandonment business upon delivery of the service to the customer. These services are consumed by our customers when they are provided on their sites. Revenue is recognized as performance obligations have been completed on a daily basis, when all of the proper customer approvals are obtained. We do not have any long-term service contracts; nor do we have revenue expected to be recognized in any future year related to remaining performance obligations or contracts with variable consideration related to undelivered performance obligations. Our contracts with customers typically require payment within 30-60 days following invoicing. Electricity Sales The electrical output of our cogeneration facilities that is not used in our operations is sold to the California market based on market pricing, which includes capacity payments. The portion sold from our cogeneration facilities is sold under contracts to California utility companies, based on the market pricing. Revenue is recognized over time when obligations under the terms of a contract with our customer are satisfied; generally, this occurs upon delivery of the electricity. Revenue is measured as the amount of consideration we expect to receive based on average index pricing with payment due the month following delivery. Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary based on seasonality, which is consistent with how we earn the capacity payment. Capacity payments are settled monthly. We consider our performance obligations to be satisfied upon delivery of electricity or as the contracted amount of energy is made available to the customer in the case of capacity payments. We report electricity revenue as electricity sales on our consolidated statements of operations. Marketing Revenue Marketing revenue primarily includes our activities associated with transporting and marketing third-party volumes. These sales are made under the same agreements with the same purchaser as our natural gas sales discussed above. We consider our performance obligations to be satisfied upon transfer of control of the commodity. Revenues are presented excluding costs incurred prior to transferring control of these volumes to the customer, or the costs to purchase these volumes when we are acting as the principal. The revenues and expenses related to the sale and purchase of third-party volumes are presented separately as marketing revenue and marketing expenses on the consolidated statements of operations. In January 2022, we sold our Piceance Colorado operations, which included third-party marketing activities. Historically, these activities accounted for nearly all of our marketing revenues. |
Fair Value Measurements | Fair Value Measurements We have categorized our assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level 3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period. We primarily apply the market approach for recurring fair value measurement, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management’s judgments regarding expectations of projected cash flows and discounts those cash flows using a risk-adjusted discount rate. The only item on our balance sheet that would be affected by recurring fair value measurements is derivatives. We determine the fair value of our oil and gas sales and natural gas purchase derivatives using valuation techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We classify these measurements as Level 2. |
Stock-based Compensation | Stock-based Compensation We have issued restricted stock units (“RSUs”) that vest over time and performance-based restricted stock units (“PSUs”) that include (i) awards with a market objective measured against both absolute total stockholder return (“Absolute TSR”) and a relative total stockholder return (“Relative TSR”) (the “TSR PSUs”) over the performance period and (ii) awards based on the Company's average cash returned on invested capital (“CROIC PSUs” and “ROIC PSUs”) over the performance period. CROIC PSUs are awarded to certain Berry employees, while ROIC PSUs are awarded to certain CJWS employees. The fair value of the stock-based awards is determined at the date of grant and is not remeasured. The fair value of the RSUs, CROIC PSUs and ROIC PSUs was determined using the grant date stock price. The fair value of the TSR PSUs was determined using a Monte Carlo simulation analysis to estimate the total shareholder return ranking of the Company, including a comparison against the peer group over the performance periods. Estimates used in the Monte Carlo valuation model are considered highly complex and subjective. Compensation expense, net of actual forfeitures, for the RSUs and PSUs is recognized on a straight-line basis over the requisite service periods, which is over the awards’ respective vesting or performance periods which range from one |
Other Loss Contingencies | Other Loss Contingencies In the normal course of business, we are involved in lawsuits, claims and other environmental and legal proceedings and audits. We accrue reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, we disclose, if material, in aggregate, our exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. We review our loss contingencies on an ongoing basis. Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management’s judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors. |
Electricity Cost Allocation | Electricity Cost Allocation We own several cogeneration facilities. Our investment in cogeneration facilities has been for the express purpose of lowering steam costs in our heavy oil operations in California and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power, extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. We allocate steam and electricity costs to lease operating expenses based on the conversion efficiency of the cogeneration facilities plus certain direct costs of producing steam. We also allocate a portion of the electricity production costs related to the power we sell to third parties, which is reported in “electricity generation expenses” in the statement of operations. |
Income Taxes | Income Taxes Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. Interest and penalties related to unrecognized tax benefits are recognized in income tax expense (benefit). |
Earnings per Share | Earnings per Share Basic earnings (loss) per share is calculated as net income (loss) divided by the weighted-average shares of common stock outstanding during the period. Diluted earnings (loss) per share is calculated by dividing net income (loss) by the weighted-average shares of common stock outstanding, including the effect of potentially dilutive securities. For basic earnings per share (“EPS”), the weighted-average number of common stock outstanding excludes outstanding shares related to unvested restricted stock awards. For diluted EPS, the basic shares outstanding are adjusted by adding potentially dilutive securities, unless their effect is anti-dilutive. We did not have any participating securities in the periods presented. |
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 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) |
Basis of Presentation and Sig_3
Basis of Presentation and Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Summary of Activity in ARO Account | The following table summarizes activity in our ARO account in which approximately $158 million and $144 million were included in long term liabilities as of December 31, 2022 and December 31, 2021, respectively, with the remaining current portion included in accrued liabilities: Year Ended December 31, 2022 2021 (in thousands) Beginning balance $ 163,925 $ 160,192 Liabilities incurred including from acquisitions 3,028 1,350 Settlements and payments (19,558) (17,900) Accretion expense 10,848 10,936 Reduction due to property sales (1,210) (22,199) Revisions 21,458 31,546 Ending balance $ 178,491 $ 163,925 |
Oil and Natural Gas Propertie_2
Oil and Natural Gas Properties and Other Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
Schedule of Aggregate Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities | Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: Year Ended December 31, 2022 2021 (in thousands) Proved properties $ 1,477,791 $ 1,246,380 Unproved properties 248,073 291,514 Total proved and unproved properties 1,725,864 1,537,894 Less accumulated depletion and amortization (465,889) (340,328) Total proved and unproved properties, net $ 1,259,975 $ 1,197,566 |
Schedule of Other Property and Equipment | Other property and equipment consisted of the following: Year Ended December 31, 2022 2021 (in thousands) Cogeneration facilities, natural gas plants and pipelines $ 58,357 $ 54,237 Vehicles and service equipment (1) 65,195 55,521 Furniture and equipment 23,779 22,665 Land 6,102 6,101 Buildings and leasehold improvements 2,186 2,186 Total other property and equipment 155,619 140,710 Less: accumulated depreciation (55,781) (36,927) Total other property and equipment, net $ 99,838 $ 103,783 __________ (1) Includes CJWS vehicles and service equipment. |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule of Outstanding Debt | The following table summarizes our outstanding debt: December 31, 2022 December 31, 2021 Interest Rate Maturity Security (in thousands) 2021 RBL Facility $ — $ — variable rates 9.5% (2022) and 5.3% (2021) August 26, 2025 Mortgage on 90% of Present Value of proven oil and gas reserves and lien on certain other assets 2022 ABL Facility — n/a variable rates 8.3% (2022) June 5, 2025 Personal property assets, other than excluded accounts 2026 Notes 400,000 400,000 7.0% February 15, 2026 Unsecured Long-Term Debt - Principal Amount 400,000 400,000 Less: Debt Issuance Costs (4,265) (5,434) Long-Term Debt, net $ 395,735 $ 394,566 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Transactions Resulting in Crude Oil Production and Gas Purchases Hedges | As of December 31, 2022, we had the following crude oil production and gas purchases hedges. Q1 2023 Q2 2023 Q3 2023 Q4 2023 FY 2024 FY 2025 Brent - Crude Oil Production Swaps Hedged volume (bbls) 1,385,278 1,387,750 1,211,717 1,196,000 3,392,048 — Weighted-average price ($/bbl) $ 77.15 $ 77.01 $ 76.26 $ 76.18 $ 76.12 $ — Put Spreads Long $50/$40 Put Spread hedged volume (bbls) 630,000 637,000 644,000 644,000 1,647,000 — Short $50/$40 Put Spread hedged volume (bbls) 90,000 91,000 92,000 92,000 366,000 — Producer Collars Hedged volume (bbls) 360,000 364,000 368,000 368,000 1,098,000 2,212,500 Weighted-average price ($/bbl) $40.00/$106.00 $40.00/$106.00 $40.00/$106.00 $40.00/$106.00 $40.00/$105.00 $58.35/$91.45 Henry Hub - Natural Gas Purchases Consumer Collars Hedged volume (mmbtu) 2,110,000 1,820,000 — — — — Weighted-average price ($/mmbtu) $4.00/$2.75 $4.00/$2.75 $ — $ — $ — $ — NWPL - Natural Gas Purchases Hedged volume (mmbtu) 1,800,000 3,640,000 3,680,000 3,680,000 7,320,000 6,080,000 Weighted-average price ($/mmbtu) $ 6.40 $ 5.34 $ 5.34 $ 5.34 $ 4.27 $ 4.27 Gas Basis Differentials NWPL/HH - basis swaps Hedged volume (mmbtu) 1,800,000 1,820,000 1,840,000 1,840,000 — — Weighted-average price ($/mmbtu) $ 1.12 $ 1.12 $ 1.12 $ 1.12 $ — $ — |
Fair Values (Gross and Net) of Outstanding Derivatives | The following tables present the fair values (gross and net) of our outstanding derivatives as of December 31, 2022 and 2021. December 31, 2022 Balance Sheet Classification Gross Amounts Recognized at Gross Amounts Offset Net Fair Value (in thousands) Assets: Commodity Contracts Current assets $ 66,974 $ (30,607) $ 36,367 Commodity Contracts Non-current assets 39,886 (39,810) 76 Liabilities: Commodity Contracts Current liabilities (61,713) 30,607 (31,106) Commodity Contracts Non-current liabilities (53,452) 39,810 (13,642) Total derivatives $ (8,305) $ — $ (8,305) December 31, 2021 Balance Sheet Classification Gross Amounts Recognized at Gross Amounts Offset Net Fair Value (in thousands) Assets: Commodity Contracts Current assets $ 5,360 $ (5,360) $ — Commodity Contracts Non-current assets 29,828 (28,758) 1,070 Liabilities: Commodity Contracts Current liabilities (34,985) 5,360 (29,625) Commodity Contracts Non-current liabilities (47,335) 28,758 (18,577) Total derivatives $ (47,132) $ — $ (47,132) |
Gains and Losses of Derivatives Instruments in Statement of Operations | A summary of gains and losses on the derivatives included on the statements of operations is presented below: Year Ended December 31, 2022 2021 2020 (in thousands) (Losses) gains on oil and gas sales derivatives $ (137,109) $ (156,399) $ 117,781 Gains (losses) on natural gas purchase derivatives 88,795 38,577 (1,035) Total (losses) gains on derivatives $ (48,314) $ (117,822) $ 116,746 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Future Net Minimum Payments for Purchase Obligations and Operating Leases | At December 31, 2022, future net minimum payments for non-cancelable purchase obligations (excluding oil and natural gas and other mineral leases, utilities, taxes and insurance expense) were as follows: 2023 2024 2025 2026 2027 Thereafter Total (in thousands) Processing and transportation contracts (1) $ 11,343 $ 9,553 $ 8,234 $ 8,082 $ 8,083 $ 43,521 $ 88,816 Drilling commitment (2) 8,400 8,700 — — — — 17,100 Total $ 19,743 $ 18,253 $ 8,234 $ 8,082 $ 8,083 $ 43,521 $ 105,916 __________ (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. |
Stockholders' Equity (Tables)
Stockholders' Equity (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of Restricted Stock Units (RSUs) Activity | The table below summarizes the activity relating to RSUs issued under the Restated Incentive Plan during the year ended December 31, 2022. The RSUs vest ratably over three years. Unrecognized compensation cost associated with the RSUs at December 31, 2022 was approximately $10 million which will be recognized over a weighted-average period of approximately two years. Number of shares Weighted-average Grant Date Fair Value (shares in thousands) Non-vested at December 31, 2021 2,580 $ 5.67 Granted 1,317 $ 8.92 Vested (1,145) $ 6.36 Forfeited (233) $ 6.97 Non-vested at December 31, 2022 2,519 $ 6.94 |
Schedule of Performance-Based Restricted Stock Unit (PSUs) Activity | The table below summarizes the activity relating to the PSUs issued under the Revised Incentive Plan during the year ended December 31, 2022. Unrecognized compensation cost associated with the PSUs at December 31, 2022 is approximately $8 million which will be recognized over a weighted-average period of approximately two years. Number of shares Weighted-average Grant Date Fair Value (shares in thousands) Non-vested at December 31, 2021 2,085 $ 11.00 Granted 611 $ 12.03 Vested (36) $ 12.75 Forfeited (59) $ 12.51 Non-vested at December 31, 2022 2,601 $ 11.18 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | Income tax expense (benefit) consisted of the following: Year Ended December 31, 2022 2021 2020 (in thousands) Current taxes: Federal $ 642 $ — $ — State 1,597 581 828 Total current taxes 2,239 581 828 Deferred taxes: Federal (44,053) 832 2,653 State (622) — (10,699) Total deferred taxes (44,675) 832 (8,046) Total current and deferred taxes $ (42,436) $ 1,413 $ (7,218) |
Reconciliation of the Federal Statutory Tax Rate to the Effective Tax Rate | A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, 2022 2021 2020 Federal statutory rate 21.0 % 21.0 % 21.0 % State, net of federal tax benefit 6.2 % 3.7 % 6.3 % Nondeductible compensation 1.8 % (24.5) % — % Effect of permanent differences (0.3) % (4.7) % (0.6) % Tax credits - Prior Year (11.5) % (29.5) % 4.9 % Tax credits - Current Year — % 21.5 % 1.1 % State return to provision (0.3) % (0.2) % (1.1) % Change in valuation allowance (37.3) % 2.7 % (28.8) % Effective tax rate (20.4) % (10.0) % 2.8 % |
Schedule of Significant Components of Deferred Tax Assets and Liabilities | Significant components of the deferred tax assets and liabilities are as follows: Year Ended December 31, 2022 2021 (in thousands) Deferred tax assets: Net operating loss carryforwards $ 22,402 $ 40,846 Accruals 10,728 11,731 Asset retirement obligations 48,994 44,437 Derivative instruments 2,280 12,776 Tax credits 88,908 61,044 Other 2,882 3,551 Subtotal 176,194 174,385 Valuation allowance — (77,546) Total deferred tax assets 176,194 96,839 Deferred tax liabilities: Book tax differences in property basis (133,350) (98,670) Total deferred tax liabilities (133,350) (98,670) Net deferred tax asset (liability) $ 42,844 $ (1,831) |
Supplemental Disclosures to t_2
Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Other Current Assets | Other current assets reported on the consolidated balance sheets included the following: Year Ended December 31, 2022 2021 (in thousands) Prepaid expenses $ 12,330 $ 26,840 Materials and supplies 8,976 9,533 Prepaid deposits 7,266 6,415 Oil inventories 4,036 2,933 Other 1,117 225 Total other current assets $ 33,725 $ 45,946 |
Schedule of Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses on the consolidated balance sheets included the following: Year Ended December 31, 2022 2021 (in thousands) Accounts payable - trade $ 40,286 $ 17,699 Accrued expenses 85,360 62,962 Royalties payable 38,264 24,816 Greenhouse gas liability - current portion — 7,513 Taxes other than income tax liability 6,640 8,273 Accrued interest 10,885 10,736 Dividends payable — 4,800 Asset retirement obligation - current portion 20,000 20,000 Operating lease liability 1,666 — Other — 725 Total accounts payable and accrued expenses $ 203,101 $ 157,524 |
Supplemental Cash Flow Information | Supplemental disclosures to the consolidated statements of cash flows are presented below: Year Ended December 31, 2022 2021 2020 (in thousands) Supplemental Disclosures of Significant Non-Cash Operating Activities: Greenhouse gas liability - reclassification from current liability to long-term $ 8,000 $ — $ — Greenhouse gas liability - reclassification from long-term to current liability $ — $ — $ 33,376 Supplemental Disclosures of Significant Non-Cash Investing Activities: Material inventory transfers to oil and natural gas properties $ 2,707 $ 3,424 $ 1,596 Supplemental Disclosures of Cash Payments (Receipts): Interest, net of amounts capitalized $ 29,792 $ 29,211 $ 29,962 Income taxes payments $ 3,633 $ 699 $ 222 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Business Combination and Asset Acquisition [Abstract] | |
Summary of Pro Forma Information | The following unaudited pro forma information is not necessarily indicative of the results that would have been achieved if the CJWS acquisition had occurred in the past, and should not be relied upon as an indication of the operating results that the Company would have achieved if the acquisition had occurred at the beginning of the periods presented, and our operating results, or the future results. Pro Forma Year Ended December 31, 2021 2020 (unaudited) (in thousands) Revenue $ 664,549 $ 657,796 Net income (loss) $ 740 $ (250,884) |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share | Year Ended December 31, 2022 2021 2020 (in thousands except per share amounts) Basic EPS calculation Net income (loss) $ 250,168 $ (15,542) $ (262,895) Weighted-average shares of common stock outstanding 78,517 80,209 79,802 Basic income (loss) per share $ 3.19 $ (0.19) $ (3.29) Diluted EPS calculation Net income (loss) $ 250,168 $ (15,542) $ (262,895) Weighted-average shares of common stock outstanding 78,517 80,209 79,802 Dilutive effect of potentially dilutive securities (1) 4,069 — — Weighted-average common shares outstanding - diluted 82,586 80,209 79,802 Diluted income (loss) per share $ 3.03 $ (0.19) $ (3.29) __________ |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | As a result of adoption of this standard, we are now required to disclose the following information regarding revenue from contracts with customers on a disaggregated basis. Year Ended December 31, 2022 2021 2020 (in thousands) Oil sales $ 806,631 $ 587,613 $ 362,976 Natural gas sales 29,515 32,679 14,041 Natural gas liquids sales 6,303 5,183 1,646 Service revenue 181,400 35,840 — Electricity sales 30,833 35,636 25,813 Marketing revenues 289 3,921 1,426 Other revenues 479 477 150 Revenues from contracts with customers 1,055,450 701,349 406,052 (Losses) gains on oil and gas sales derivatives (137,109) (156,399) 117,781 Total revenues and other $ 918,341 $ 544,950 $ 523,833 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
Schedule of Segment Information | The following table represents selected financial information for the periods presented regarding the Company's business segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis. Year Ended December 31, 2022 E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company (in thousands) Revenues (1) $ 874,190 $ 184,448 $ (3,188) $ 1,055,450 Net income (loss) before income taxes $ 303,178 $ 14,747 $ (110,193) $ 207,732 Adjusted EBITDA $ 411,811 $ 26,113 $ (57,976) $ 379,948 Capital expenditures $ 141,930 $ 8,455 $ 2,536 $ 152,921 Total assets $ 1,563,251 $ 83,461 $ (15,682) $ 1,631,030 Year Ended December 31, 2021 E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company (in thousands) Revenues (1) $ 665,509 $ 35,840 $ — $ 701,349 Net income (loss) before income taxes $ 82,826 $ 1 $ (96,956) $ (14,129) Adjusted EBITDA $ 251,146 $ 4,310 $ (43,310) $ 212,146 Capital expenditures $ 129,479 $ 1,029 $ 2,211 $ 132,719 Total assets $ 1,450,157 $ 81,093 $ (74,771) $ 1,456,479 __________ |
Adjusted EBITDA Reconciliation | Year Ended December 31, 2022 Well Servicing and Abandonment Corporate/Eliminations Consolidated Company (in thousands) Adjusted EBITDA reconciliation to net income (loss): Net income (loss) $ 303,178 $ 14,747 $ (67,757) $ 250,168 Add (Subtract): Interest expense — 23 30,894 30,917 Income tax benefit — — (42,436) (42,436) Depreciation, depletion, and amortization 139,886 12,548 4,413 156,847 Losses on derivatives 48,314 — — 48,314 Net cash paid for scheduled derivative settlements (88,023) — — (88,023) Other operating expenses (income) 3,827 (1,690) 1,585 3,722 Stock compensation expense 1,361 287 15,325 16,973 Non-recurring costs (1) 3,268 198 — 3,466 Adjusted EBITDA $ 411,811 $ 26,113 $ (57,976) $ 379,948 __________ (1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022 and the executive transition costs in the fourth quarter of 2022. Year Ended December 31, 2021 E&P Well Servicing and Abandonment Corporate/Eliminations Consolidated Company (in thousands) Adjusted EBITDA reconciliation to net income (loss): Net income (loss) $ 82,825 $ 1 $ (98,368) $ (15,542) Add (Subtract): Interest expense — — 31,964 31,964 Income tax expense — — 1,413 1,413 Depreciation, depletion, and amortization 136,915 2,974 4,606 144,495 Losses on derivatives 117,822 — — 117,822 Net cash paid for scheduled derivative settlements (87,625) — — (87,625) Other operating expenses 109 — 2,992 3,101 Stock compensation expense 1,100 — 12,683 13,783 Non-recurring costs (1) — 1,335 1,400 2,735 Adjusted EBITDA $ 251,146 $ 4,310 $ (43,310) $ 212,146 __________ (1) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity for the fourth quarter of 2021. |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
Components of Lease Expense | The components of lease expense are as follows: Year Ended December 31, 2022 (in thousands) Lease Cost Operating lease cost $ 1,992 Total net lease cost $ 1,992 |
Balance Sheet Information Related to Leases | The following table presents the consolidated balance sheet information related to leases as of December 31, 2022. As of December 31, 2022 Balance Sheet Classification (in thousands) Leases Assets Operating lease assets $ 6,325 Other noncurrent assets Total assets $ 6,325 Liabilities Operating lease liability $ 1,666 Accounts payable and accrued expenses Operating lease noncurrent liability 5,213 Other noncurrent liabilities Total liabilities $ 6,879 As of December 31, 2022 Long-Term and Discount Rate Weighted-average remaining lease term: Operating Lease 4.3 years Weighted-average discount rate: Operating Lease 5 % |
Schedule of Maturity | The following table presents a schedule of future minimum lease payments required under all operating lease agreements as of December 31, 2022. As of December 31, 2022 Operating Leases (in thousands) 2023 $ 1,963 2024 1,650 2025 1,542 2026 1,549 2027 935 Total lease payments 7,639 Less imputed interest (760) Total lease obligations 6,879 Less current obligations (1,666) Long-term lease obligations $ 5,213 |
Cash Flow Information Related to Leases | Supplemental consolidated statement of cash flow information related to leases is as follows: Year Ended December 31, 2022 (in thousands) Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 2,128 ROU assets obtained in exchange for operating lease liabilities $ 7,956 |
Basis of Presentation and Sig_4
Basis of Presentation and Significant Accounting Policies - Narrative (Details) | 3 Months Ended | 9 Months Ended | 12 Months Ended | 15 Months Ended | |||
Dec. 31, 2021 USD ($) business | Mar. 31, 2020 USD ($) | Sep. 30, 2022 business | Dec. 31, 2022 USD ($) segment | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Dec. 31, 2022 USD ($) segment | |
Public Utilities, General Disclosures [Line Items] | |||||||
Number of reportable segments | segment | 2 | ||||||
Business segments | 2 | 1 | 2 | ||||
Capitalized interest | $ 1,000,000 | $ 2,000,000 | $ 1,000,000 | ||||
Capitalized exploratory well costs | $ 0 | 0 | 0 | 0 | $ 0 | ||
Capitalized overhead | 7,000,000 | 6,000,000 | 7,000,000 | 6,000,000 | 6,000,000 | ||
Net capitalized costs attributable to unproved properties | 292,000,000 | 248,000,000 | 292,000,000 | 248,000,000 | |||
Impairment of oil and gas properties | 0 | 0 | $ 289,085,000 | ||||
Asset retirement obligation, noncurrent | $ 143,926,000 | $ 158,491,000 | $ 143,926,000 | $ 158,491,000 | |||
Largest customers | Sales | Customer one | E&P | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Concentration risk | 33% | 30% | 44% | ||||
Largest customers | Sales | Customer two | E&P | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Concentration risk | 16% | 16% | 20% | ||||
Largest customers | Sales | Customer three | E&P | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Concentration risk | 10% | 14% | 12% | ||||
Largest customers | Sales | Customer four | E&P | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Concentration risk | 12% | ||||||
Largest customers | Trade accounts receivable | Customer one | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Concentration risk | 33% | 28% | |||||
Largest customers | Trade accounts receivable | Customer two | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Concentration risk | 16% | 13% | |||||
Largest customers | Trade accounts receivable | Customer three | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Concentration risk | 13% | 11% | |||||
Buildings and leasehold improvements | Minimum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Expected useful life | 15 years | ||||||
Buildings and leasehold improvements | Maximum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Expected useful life | 39 years | ||||||
Plant and pipeline | Minimum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Expected useful life | 20 years | ||||||
Plant and pipeline | Maximum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Expected useful life | 30 years | ||||||
Furniture and office equipment | Minimum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Expected useful life | 1 year | ||||||
Furniture and office equipment | Maximum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Expected useful life | 10 years | ||||||
Vehicles | Minimum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Expected useful life | 1 year | ||||||
Vehicles | Maximum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Expected useful life | 10 years | ||||||
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs) | Minimum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Vesting period | 1 year | ||||||
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs) | Maximum | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Vesting period | 3 years | ||||||
Unproved Oil and Gas Properties | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Impairment of oil and gas properties | $ 0 | ||||||
Proved Oil and Gas Properties | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Impairment of oil and gas properties | $ 289,000,000 |
Basis of Presentation and Sig_5
Basis of Presentation and Significant Accounting Policies - Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | |
May 31, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning balance | $ 163,925 | $ 160,192 | |
Liabilities incurred including from acquisitions | $ 6,000 | 3,028 | 1,350 |
Settlements and payments | (19,558) | (17,900) | |
Accretion expense | 10,848 | 10,936 | |
Reduction due to property sales | (1,210) | (22,199) | |
Revisions | 21,458 | 31,546 | |
Ending balance | $ 178,491 | $ 163,925 |
Oil and Natural Gas Propertie_3
Oil and Natural Gas Properties and Other Property and Equipment - Aggregate Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Extractive Industries [Abstract] | ||
Proved properties | $ 1,477,791 | $ 1,246,380 |
Unproved properties | 248,073 | 291,514 |
Oil and natural gas properties | 1,725,864 | 1,537,894 |
Less accumulated depletion and amortization | (465,889) | (340,328) |
Total oil and natural gas properties, net | $ 1,259,975 | $ 1,197,566 |
Oil and Natural Gas Propertie_4
Oil and Natural Gas Properties and Other Property and Equipment - Other Property and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | $ 155,619 | $ 140,710 |
Less accumulated depreciation | (55,781) | (36,927) |
Total other property and equipment, net | 99,838 | 103,783 |
Cogeneration facilities, natural gas plants and pipelines | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 58,357 | 54,237 |
Vehicles and service equipment | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 65,195 | 55,521 |
Furniture and equipment | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 23,779 | 22,665 |
Land | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 6,102 | 6,101 |
Buildings and leasehold improvements | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | $ 2,186 | $ 2,186 |
Debt - Outstanding Debt (Detail
Debt - Outstanding Debt (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 | Feb. 28, 2018 |
Debt Instrument [Line Items] | |||
Long-Term Debt - Principal Amount | $ 400,000,000 | $ 400,000,000 | |
Less: Debt Issuance Costs | (4,265,000) | (5,434,000) | |
Long-Term Debt, net | 395,735,000 | 394,566,000 | |
Unsecured debt | 2026 Notes | |||
Debt Instrument [Line Items] | |||
Long-Term Debt - Principal Amount | $ 400,000,000 | 400,000,000 | |
Interest Rate | 7% | 7% | |
Revolving credit facility | Line of credit | 2021 RBL Facility | |||
Debt Instrument [Line Items] | |||
Long-Term Debt - Principal Amount | $ 0 | $ 0 | |
Variable rate | 9.50% | 5.30% | |
Security | 90% | ||
Revolving credit facility | Line of credit | 2022 ABL Facility | |||
Debt Instrument [Line Items] | |||
Long-Term Debt - Principal Amount | $ 0 | ||
Variable rate | 8.30% |
Debt - Narrative (Details)
Debt - Narrative (Details) | 1 Months Ended | 12 Months Ended | ||||||||
Aug. 09, 2022 USD ($) | Aug. 26, 2021 USD ($) | Nov. 30, 2022 USD ($) | May 31, 2022 USD ($) | Feb. 28, 2018 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Feb. 29, 2020 USD ($) | Jul. 31, 2017 USD ($) | |
Debt Instrument [Line Items] | ||||||||||
Debt issuance costs for the 2026 Senior Unsecured Notes | $ 4,265,000 | $ 5,434,000 | ||||||||
Amortization of debt issuance costs | 2,590,000 | 4,430,000 | $ 5,351,000 | |||||||
Net income (loss) | 250,168,000 | (15,542,000) | (262,895,000) | |||||||
Bond repurchase program, authorized amount | $ 75,000,000 | |||||||||
C&J Well Services | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Net income (loss) | 15,000,000 | |||||||||
Interest expense | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Amortization of debt issuance costs | 2,000,000 | 4,000,000 | $ 5,000,000 | |||||||
2026 Notes | Unsecured debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fair value of debt | $ 369,000,000 | 400,000,000 | ||||||||
Principal amount of debt issued | $ 400,000,000 | |||||||||
Interest Rate | 7% | 7% | ||||||||
Issuance of 2026 Senior Unsecured Notes | $ 391,000,000 | |||||||||
Redemption price in event of change in control | 101% | |||||||||
Revolving credit facility | RBL Facility | Line of credit | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Credit facility, issuance costs, net of amortization | $ 4,000,000 | 5,000,000 | ||||||||
Revolving credit facility | 2017 RBL Facility | Line of credit | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Unamortized debt issuance costs | 3,000,000 | |||||||||
Maximum borrowing capacity | $ 1,500,000,000 | |||||||||
Borrowing base elected | $ 200,000,000 | |||||||||
Borrowings outstanding | 0 | |||||||||
Revolving credit facility | 2021 RBL Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Initial borrowing base, aggregate amount | $ 200,000,000 | |||||||||
Revolving credit facility | 2021 RBL Facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin | 0.10% | |||||||||
Revolving credit facility | 2021 RBL Facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin | 0.50% | |||||||||
Revolving credit facility | 2021 RBL Facility | Line of credit | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Professional fees | 4,000,000 | |||||||||
Maximum borrowing capacity | 500,000,000 | |||||||||
Borrowing base elected | $ 200,000,000 | $ 250,000,000 | $ 250,000,000 | $ 200,000,000 | ||||||
Commitment fee amount | $ 200,000,000 | |||||||||
Maximum borrowing capacity exceed, remediation period (within) | 30 days | |||||||||
Maximum borrowing capacity exceed, cure deficiency period (within) | 6 months | |||||||||
Consolidated cash balance trigger to prepay borrowing | $ 20,000,000 | |||||||||
Commitment fee | 0.50% | |||||||||
Leverage ratio (no more than) | 3 | |||||||||
Current ratio (at least) | 1 | |||||||||
Current ratio at period end | 1.7 | |||||||||
Reduction in borrowing base if unsecured indebtedness is incurred | 25% | |||||||||
Minimum availability of borrowing base required which will permit repurchase of equity and indebtedness | 20% | |||||||||
Maximum pro forma leverage ratio allowable which will permit repurchase of equity and indebtedness | 2 | |||||||||
Repurchase of equity and debt, percentage of maximum remaining borrowing capacity | 75% | |||||||||
Repurchase of restricted payments of equity and debt | 1.5 | |||||||||
Free cash flow percentage | 100% | |||||||||
Letters of credit outstanding | $ 7,000,000 | |||||||||
Available borrowing capacity | $ 193,000,000 | |||||||||
Revolving credit facility | 2021 RBL Facility | Line of credit | Base Rate | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin | 2% | |||||||||
Revolving credit facility | 2021 RBL Facility | Line of credit | Base Rate | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin | 3% | |||||||||
Revolving credit facility | 2021 RBL Facility | Line of credit | Benchmark Rate | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin | 3% | |||||||||
Revolving credit facility | 2021 RBL Facility | Line of credit | Benchmark Rate | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin | 4% | |||||||||
Revolving credit facility | 2022 ABL Facility | Line of credit | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum borrowing capacity | $ 15,000,000 | |||||||||
Percentage of borrowing capacity, line of credit facility | 0.80 | |||||||||
Borrowings outstanding | $ 0 | |||||||||
Letters of credit outstanding | 2,000,000 | |||||||||
Available borrowing capacity | $ 13,000,000 | |||||||||
Revolving credit facility | 2022 ABL Facility | Line of credit | C&J Well Services | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum ratio of total liabilities to total net worth | 1.5 | 0.2 | ||||||||
Maximum percentage of revolving advances outstanding | 0.90 | |||||||||
Maximum net income before taxes | $ 1 | |||||||||
Advances outstanding | $ 0 | |||||||||
Revolving credit facility | 2022 ABL Facility | Line of credit | Prime Rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Basis spread on variable rate, with derivatives | 1.25% | |||||||||
Letter of credit | 2021 RBL Facility | Line of credit | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum borrowing capacity | $ 20,000,000 | |||||||||
Letter of credit | 2022 ABL Facility | Line of credit | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maximum borrowing capacity | $ 7,500,000 | |||||||||
Line of credit | RBL Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Leverage ratio at period end | 1.2 |
Derivatives - Narrative (Detail
Derivatives - Narrative (Details) MMBTU / d in Thousands, MMBTU in Thousands, $ in Millions | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 12 Months Ended | |||||||||
Jan. 31, 2025 bbl / d $ / MMBoe bbl | Dec. 31, 2023 MMBTU / d MMBTU $ / bbl $ / MMBtu | Mar. 31, 2026 bbl / d $ / MMBoe bbl | Mar. 31, 2025 bbl / d $ / MMBoe bbl | Dec. 31, 2023 $ / bbl $ / MMBtu bbl | Sep. 30, 2023 $ / bbl $ / MMBtu bbl | Jun. 30, 2023 $ / MMBtu $ / bbl bbl | Mar. 31, 2023 $ / bbl $ / MMBtu bbl | Oct. 31, 2023 MMBTU / d MMBTU $ / MMBtu | Dec. 31, 2025 $ / bbl $ / MMBtu bbl | Dec. 31, 2024 $ / MMBtu $ / bbl bbl | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Derivative [Line Items] | ||||||||||||||
Target period to cover operating expenses and fixed charges (up to) | 3 years | |||||||||||||
Target period for fixing the price natural gas purchases used in steam operations (up to) | 3 years | |||||||||||||
Deferred premiums, remaining | $ | $ 5 | |||||||||||||
Net cash paid (received) settlements | $ | $ 88 | $ 92 | $ (142) | |||||||||||
Forecast | Swaps | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Hedged volume (bbls) | bbl | 1,196,000 | 1,211,717 | 1,387,750 | 1,385,278 | 0 | 3,392,048 | ||||||||
Weighted-average price ($/bbl) | 76.18 | 76.18 | 76.26 | 77.01 | 77.15 | 0 | 76.12 | |||||||
Forecast | Producer Collar, Purchased Puts | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Hedged volume (bbls) | bbl | 3,627 | 472,500 | 270,000 | 368,000 | 368,000 | 364,000 | 360,000 | 2,212,500 | 1,098,000 | |||||
Hedged volume (bbls/d) | bbl / d | 117 | 5,250 | 3,000 | |||||||||||
Forecast | Producer Collar, Purchased Puts | Maximum | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Weighted-average price ($/bbl) | $ / MMBoe | 88.50 | 82.21 | 88.35 | |||||||||||
Forecast | Producer Collar, Purchased Puts | Minimum | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Weighted-average price ($/bbl) | $ / MMBoe | 60 | 60 | 60 | |||||||||||
Forecast | Put Spread, Long | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Hedged volume (bbls) | bbl | 644,000 | 644,000 | 637,000 | 630,000 | 0 | 1,647,000 | ||||||||
Forecast | Put Spread, Long | Maximum | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Weighted-average price ($/bbl) | 50 | |||||||||||||
Forecast | Put Spread, Long | Minimum | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Weighted-average price ($/bbl) | 40 | |||||||||||||
Forecast | Put Spread, Short | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Hedged volume (bbls) | bbl | 92,000 | 92,000 | 91,000 | 90,000 | 0 | 366,000 | ||||||||
Forecast | Put Spread, Short | Maximum | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Weighted-average price ($/bbl) | 50 | |||||||||||||
Forecast | Put Spread, Short | Minimum | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Weighted-average price ($/bbl) | 40 | |||||||||||||
Forecast | NWPL/HH - basis swaps | ||||||||||||||
Derivative [Line Items] | ||||||||||||||
Hedged volume, terminated | MMBTU | 610 | 4,900 | ||||||||||||
Hedged volume, terminated per day | MMBTU / d | 10 | 20 | ||||||||||||
Weighted-average price ($/mmbtu) | $ / MMBtu | 1.12 | 1.12 | 1.12 | 1.12 | 1.12 | 1.12 | 0 | 0 |
Derivatives - Derivative Transa
Derivatives - Derivative Transactions Resulting in Crude Oil Production and Gas Purchases Hedges (Details) - Forecast MMBTU in Thousands | 1 Months Ended | 2 Months Ended | 3 Months Ended | 8 Months Ended | 12 Months Ended | ||||||
Jan. 31, 2025 $ / MMBoe bbl | Dec. 31, 2023 MMBTU $ / MMBtu $ / bbl | Mar. 31, 2026 $ / MMBoe bbl | Mar. 31, 2025 $ / MMBoe bbl | Dec. 31, 2023 MMBTU $ / MMBtu $ / bbl bbl | Sep. 30, 2023 MMBTU $ / MMBtu $ / bbl bbl | Jun. 30, 2023 MMBTU $ / MMBoe $ / MMBtu $ / bbl bbl | Mar. 31, 2023 MMBTU $ / MMBtu $ / bbl $ / MMBoe bbl | Oct. 31, 2023 MMBTU $ / MMBtu | Dec. 31, 2025 MMBTU $ / MMBtu $ / bbl bbl | Dec. 31, 2024 MMBTU $ / MMBtu $ / bbl bbl | |
Swaps | |||||||||||
Derivative [Line Items] | |||||||||||
Hedged volume (bbls) | bbl | 1,196,000 | 1,211,717 | 1,387,750 | 1,385,278 | 0 | 3,392,048 | |||||
Weighted-average price ($/bbl) | 76.18 | 76.18 | 76.26 | 77.01 | 77.15 | 0 | 76.12 | ||||
Put Spread, Long | |||||||||||
Derivative [Line Items] | |||||||||||
Hedged volume (bbls) | bbl | 644,000 | 644,000 | 637,000 | 630,000 | 0 | 1,647,000 | |||||
Put Spread, Short | |||||||||||
Derivative [Line Items] | |||||||||||
Hedged volume (bbls) | bbl | 92,000 | 92,000 | 91,000 | 90,000 | 0 | 366,000 | |||||
Producer Collar, Purchased Puts | |||||||||||
Derivative [Line Items] | |||||||||||
Hedged volume (bbls) | bbl | 3,627 | 472,500 | 270,000 | 368,000 | 368,000 | 364,000 | 360,000 | 2,212,500 | 1,098,000 | ||
Consumer Collars | |||||||||||
Derivative [Line Items] | |||||||||||
Hedged volume (mmbtu) | MMBTU | 0 | 0 | 1,820 | 2,110 | 0 | 0 | |||||
Weighted-average price ($/mmbtu) | $ / MMBtu | 0 | 0 | 0 | 0 | 0 | ||||||
NWPL - Natural Gas Purchases | |||||||||||
Derivative [Line Items] | |||||||||||
Hedged volume (mmbtu) | MMBTU | 3,680 | 3,680 | 3,640 | 1,800 | 6,080 | 7,320 | |||||
Weighted-average price ($/mmbtu) | $ / MMBtu | 5.34 | 5.34 | 5.34 | 5.34 | 6.40 | 4.27 | 4.27 | ||||
NWPL/HH - basis swaps | |||||||||||
Derivative [Line Items] | |||||||||||
Hedged volume (mmbtu) | MMBTU | 1,840 | 1,840 | 1,820 | 1,800 | 0 | 0 | |||||
Weighted-average price ($/mmbtu) | $ / MMBtu | 1.12 | 1.12 | 1.12 | 1.12 | 1.12 | 1.12 | 0 | 0 | |||
Hedged volume, terminated | MMBTU | 610 | 4,900 | |||||||||
Minimum | Put Spread, Long | |||||||||||
Derivative [Line Items] | |||||||||||
Weighted-average price ($/bbl) | 40 | ||||||||||
Minimum | Put Spread, Short | |||||||||||
Derivative [Line Items] | |||||||||||
Weighted-average price ($/bbl) | 40 | ||||||||||
Minimum | Producer Collar, Purchased Puts | |||||||||||
Derivative [Line Items] | |||||||||||
Weighted-average price ($/bbl) | $ / MMBoe | 60 | 60 | 60 | ||||||||
Weighted-average price ($/mmbtu) | 40 | 40 | 40 | 40 | 40 | 58.35 | 40 | ||||
Minimum | Consumer Collars | |||||||||||
Derivative [Line Items] | |||||||||||
Weighted-average price ($/mmbtu) | $ / MMBoe | 2.75 | 2.75 | |||||||||
Maximum | Put Spread, Long | |||||||||||
Derivative [Line Items] | |||||||||||
Weighted-average price ($/bbl) | 50 | ||||||||||
Maximum | Put Spread, Short | |||||||||||
Derivative [Line Items] | |||||||||||
Weighted-average price ($/bbl) | 50 | ||||||||||
Maximum | Producer Collar, Purchased Puts | |||||||||||
Derivative [Line Items] | |||||||||||
Weighted-average price ($/bbl) | $ / MMBoe | 88.50 | 82.21 | 88.35 | ||||||||
Weighted-average price ($/mmbtu) | 106 | 106 | 106 | 106 | 106 | 91.45 | 105 | ||||
Maximum | Consumer Collars | |||||||||||
Derivative [Line Items] | |||||||||||
Weighted-average price ($/mmbtu) | $ / MMBoe | 4 | 4 |
Derivatives - Fair Values (Gros
Derivatives - Fair Values (Gross and Net) of Outstanding Derivatives (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative Liability [Abstract] | ||
Derivative Assets (Liabilities), at Fair Value, Net, Total | $ (8,305) | $ (47,132) |
Commodity Contracts | Current assets | ||
Derivative Asset [Abstract] | ||
Gross Amounts Recognized at Fair Value | 66,974 | 5,360 |
Gross Amounts Offset in the Balance Sheet | (30,607) | (5,360) |
Derivative Asset, Total | 36,367 | 0 |
Commodity Contracts | Non-current assets | ||
Derivative Asset [Abstract] | ||
Gross Amounts Recognized at Fair Value | 39,886 | 29,828 |
Gross Amounts Offset in the Balance Sheet | (39,810) | (28,758) |
Derivative Asset, Total | 76 | 1,070 |
Commodity Contracts | Current liabilities | ||
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | (61,713) | (34,985) |
Derivative Liability, Fair Value, Gross Asset | 30,607 | 5,360 |
Derivative Liability | (31,106) | (29,625) |
Commodity Contracts | Non-current liabilities | ||
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | (53,452) | (47,335) |
Derivative Liability, Fair Value, Gross Asset | 39,810 | 28,758 |
Derivative Liability | $ (13,642) | $ (18,577) |
Derivatives - Gains and Losses
Derivatives - Gains and Losses of Derivatives Instruments in Statement of Operations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative [Line Items] | |||
(Losses) gains on derivatives | $ (48,314) | $ (117,822) | $ 116,746 |
Oil, natural gas and natural gas liquid sales | |||
Derivative [Line Items] | |||
(Losses) gains on derivatives | (137,109) | (156,399) | 117,781 |
Natural gas sales | |||
Derivative [Line Items] | |||
(Losses) gains on derivatives | $ 88,795 | $ 38,577 | $ (1,035) |
Commitments and Contingencies -
Commitments and Contingencies - Future Net Minimum Payments for Purchase Obligations and Operating Leases (Details) $ in Thousands | 1 Months Ended | 12 Months Ended |
Nov. 30, 2022 well | Dec. 31, 2022 USD ($) well | |
Total | ||
2023 | $ 19,743 | |
2024 | 18,253 | |
2025 | 8,234 | |
2026 | 8,082 | |
2027 | 8,083 | |
Thereafter | 43,521 | |
Total | $ 105,916 | |
Drilling commitment, number of wells | well | 57 | |
Drilling commitment, revised total of number of wells by 2023 | well | 28 | |
Processing, transportation and storage contracts | ||
Minimum purchase obligations | ||
2023 | $ 11,343 | |
2024 | 9,553 | |
2025 | 8,234 | |
2026 | 8,082 | |
2027 | 8,083 | |
Thereafter | 43,521 | |
Total | 88,816 | |
Drilling commitment | ||
Minimum purchase obligations | ||
2023 | 8,400 | |
2024 | 8,700 | |
2025 | 0 | |
2026 | 0 | |
2027 | 0 | |
Thereafter | 0 | |
Total | ||
Total | $ 17,100 |
Stockholders' Equity - Cash Div
Stockholders' Equity - Cash Dividend (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Feb. 28, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Class of Stock [Line Items] | ||||
Common stock, dividends paid (in dollars per share) | $ 1.34 | |||
Common stock, dividends declared (in dollars per share) | $ 1.34 | $ 0.20 | $ 0.12 | |
Dividends paid on common stock | $ 109,455 | $ 11,486 | $ 19,463 | |
Cash Dividend | ||||
Class of Stock [Line Items] | ||||
Common stock, dividends paid (in dollars per share) | $ 0.24 | |||
Dividends paid on common stock | $ 109,000 | $ 11,000 | $ 19,000 | |
Cash Dividend | Subsequent Event | Forecast | ||||
Class of Stock [Line Items] | ||||
Common stock, dividends paid (in dollars per share) | $ 0.06 | |||
Variable Rate Dividend | ||||
Class of Stock [Line Items] | ||||
Common stock, dividends paid (in dollars per share) | $ 1.10 | |||
Variable Rate Dividend | Subsequent Event | Forecast | ||||
Class of Stock [Line Items] | ||||
Common stock, dividends paid (in dollars per share) | $ 0.44 |
Stockholders' Equity - Common S
Stockholders' Equity - Common Stock (Narrative) (Details) | Feb. 28, 2017 vote | Dec. 31, 2022 shares | Mar. 01, 2022 shares | Jun. 27, 2018 shares |
Class of Stock [Line Items] | ||||
Number of voting rights per share | vote | 1 | |||
2022 Omnibus Incentive Plan ("2022 Plan") | ||||
Class of Stock [Line Items] | ||||
Shares authorized, common stock (in shares) | 2,300,000 | |||
Number of shares available for grant (in shares) | 1,573,402 | |||
Restated Incentive Plan | ||||
Class of Stock [Line Items] | ||||
Common stock, shares reserved for future issuance (in shares) | 10,000,000 |
Stockholders' Equity - Shares O
Stockholders' Equity - Shares Outstanding (Narrative) (Details) - shares | Dec. 31, 2022 | Dec. 31, 2021 |
Class of Stock [Line Items] | ||
Common stock, shares outstanding (in shares) | 75,767,503 | 80,007,149 |
2017 Omnibus Incentive Plan | ||
Class of Stock [Line Items] | ||
Common stock, shares outstanding (in shares) | 75,767,503 | |
Unvested restricted stock units and performance restricted stock units outstanding (in shares) | 8,110,302 |
Stockholders' Equity - Stock Re
Stockholders' Equity - Stock Repurchase Program (Narrative) (Details) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Feb. 27, 2023 | Apr. 30, 2022 | |
Equity, Class of Treasury Stock [Line Items] | |||||
Number of shares repurchased (in shares) | 5,000,000 | ||||
Repurchase of stock | $ 51,303,000 | $ 2,441,000 | $ 0 | ||
Shares repurchased or acquired (in shares) | 10,528,704 | ||||
Treasury stock, aggregate repurchase value | $ 104,000,000 | ||||
Stock Repurchase Program | |||||
Equity, Class of Treasury Stock [Line Items] | |||||
Increased authorized amount on repurchased shares | $ 102,000,000 | ||||
Authorized amount of repurchases | $ 98,000,000 | $ 150,000,000 | |||
Stock Repurchase Program | Subsequent Event | |||||
Equity, Class of Treasury Stock [Line Items] | |||||
Increased authorized amount on repurchased shares | $ 102,000,000 | ||||
Authorized amount of repurchases | $ 200,000,000 |
Stockholders' Equity - Stock-Ba
Stockholders' Equity - Stock-Based Compensation (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Allocated share-based compensation expense | $ 18 | $ 14 | $ 15 |
Tax benefit from compensation expense | 2 | ||
Performance-based Restricted Stock Units (PSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation costs | $ 8 | ||
Unrecognized compensation cost, weighted average period of recognition | 2 years | ||
Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Unrecognized compensation costs | $ 10 | ||
Unrecognized compensation cost, weighted average period of recognition | 2 years | ||
Minimum | Total Stockholder Return Performance Based Restricted Stock Units Granted in 2022 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Possible range of shares received over amount granted | 0% | ||
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% | ||
Minimum | Total Stockholder Return Performance Based Restricted Stock Units Granted In 2020 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Possible range of shares received over amount granted | 0% | ||
Minimum | Total Cash Return on Invested Capital Performance Based Restricted Stock Units Granted in 2022 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Possible range of shares received over amount granted | 0% | ||
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% | ||
Minimum | Total Return on Invested Capital Performance-Based Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Possible range of shares received over amount granted | 0% | ||
Maximum | Performance-based Restricted Stock Units (PSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Maximum | Total Stockholder Return Performance Based Restricted Stock Units Granted in 2022 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Possible range of shares received over amount granted | 250% | ||
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% | ||
Maximum | Total Stockholder Return Performance Based Restricted Stock Units Granted In 2020 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Possible range of shares received over amount granted | 200% | ||
Maximum | Total Cash Return on Invested Capital Performance Based Restricted Stock Units Granted in 2022 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Possible range of shares received over amount granted | 200% | ||
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% | ||
Maximum | Total Return on Invested Capital Performance-Based Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Possible range of shares received over amount granted | 200% |
Stockholders' Equity - RSUs and
Stockholders' Equity - RSUs and PRUs Activity (Details) shares in Thousands | 12 Months Ended |
Dec. 31, 2022 $ / shares shares | |
Restricted Stock Units (RSUs) | |
Number of shares | |
Outstanding, beginning of period (in shares) | shares | 2,580 |
Granted (in shares) | shares | 1,317 |
Vested (in shares) | shares | (1,145) |
Forfeited (in shares) | shares | (233) |
Outstanding, end of period (in shares) | shares | 2,519 |
Weighted-average Grant Date Fair Value | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 5.67 |
Granted (in dollars per share) | $ / shares | 8.92 |
Vested (in dollars per share) | $ / shares | 6.36 |
Forfeited (in dollars per share) | $ / shares | 6.97 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 6.94 |
Performance-based Restricted Stock Units (PSUs) | |
Number of shares | |
Outstanding, beginning of period (in shares) | shares | 2,085 |
Granted (in shares) | shares | 611 |
Vested (in shares) | shares | (36) |
Forfeited (in shares) | shares | (59) |
Outstanding, end of period (in shares) | shares | 2,601 |
Weighted-average Grant Date Fair Value | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 11 |
Granted (in dollars per share) | $ / shares | 12.03 |
Vested (in dollars per share) | $ / shares | 12.75 |
Forfeited (in dollars per share) | $ / shares | 12.51 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 11.18 |
Defined Contribution Plan (Deta
Defined Contribution Plan (Details) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | 18 Months Ended | |||
Jun. 30, 2021 | Jun. 30, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2022 | |
Retirement Benefits [Abstract] | ||||||
Defined contribution plan, matching contribution, percentage of employee's gross pay (up to) | 3% | 6% | 6% | |||
Defined contribution plan, matching contribution percentage | 100% | 100% | ||||
Defined contribution plan, cost | $ 6.2 | $ 1.6 | $ 1 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Components Of Income Tax Expense (Benefit) [Line Items] | |||
Effective tax rate | (20.40%) | (10.00%) | 2.80% |
Net operating loss carryforwards | $ 107,000,000 | ||
Income tax (benefit) expense | (42,436,000) | $ 1,413,000 | $ (7,218,000) |
Income tax benefit related to valuation allowance | 78,000,000 | ||
Valuation allowance | 0 | 77,546,000 | |
Uncertain tax benefits | 0 | $ 0 | |
Domestic | General Business Tax Credit Carryforward | |||
Components Of Income Tax Expense (Benefit) [Line Items] | |||
Tax credit carryforwards | 82,000,000 | ||
Income tax (benefit) expense | (7,000,000) | ||
State and Local Jurisdiction | |||
Components Of Income Tax Expense (Benefit) [Line Items] | |||
Net operating loss carryforwards | 0 | ||
State and Local Jurisdiction | State Tax Credit Carryforward | |||
Components Of Income Tax Expense (Benefit) [Line Items] | |||
Tax credit carryforwards | $ 8,000,000 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Current taxes: | |||
Federal | $ 642 | $ 0 | $ 0 |
State | 1,597 | 581 | 828 |
Total current taxes | 2,239 | 581 | 828 |
Deferred taxes: | |||
Federal | (44,053) | 832 | 2,653 |
State | (622) | 0 | (10,699) |
Total deferred taxes | (44,675) | 832 | (8,046) |
Total current and deferred taxes | $ (42,436) | $ 1,413 | $ (7,218) |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of the Federal Statutory Tax Rate to the Effective Tax Rate (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosure [Abstract] | |||
Federal statutory rate | 21% | 21% | 21% |
State, net of federal tax benefit | 6.20% | 3.70% | 6.30% |
Nondeductible compensation | 1.80% | (24.50%) | 0% |
Effect of permanent differences | (0.30%) | (4.70%) | (0.60%) |
Tax credits - Prior Year | (11.50%) | (29.50%) | 4.90% |
Tax credits - Current Year | 0% | 21.50% | 1.10% |
State return to provision | (0.30%) | (0.20%) | (1.10%) |
Change in valuation allowance | (37.30%) | 2.70% | (28.80%) |
Effective tax rate | (20.40%) | (10.00%) | 2.80% |
Income Taxes - Significant Comp
Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Deferred tax assets: | ||
Net operating loss carryforwards | $ 22,402 | $ 40,846 |
Accruals | 10,728 | 11,731 |
Asset retirement obligations | 48,994 | 44,437 |
Derivative instruments | 2,280 | 12,776 |
Tax credits | 88,908 | 61,044 |
Other | 2,882 | 3,551 |
Subtotal | 176,194 | 174,385 |
Valuation allowance | 0 | (77,546) |
Total deferred tax assets | 176,194 | 96,839 |
Deferred tax liabilities: | ||
Book tax differences in property basis | (133,350) | (98,670) |
Total deferred tax liabilities | (133,350) | (98,670) |
Net deferred tax asset | $ 42,844 | |
Net deferred tax liability | $ (1,831) |
Supplemental Disclosures to t_3
Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Other Current Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Prepaid expenses | $ 12,330 | $ 26,840 |
Materials and supplies | 8,976 | 9,533 |
Prepaid deposits | 7,266 | 6,415 |
Oil inventories | 4,036 | 2,933 |
Other | 1,117 | 225 |
Total other current assets | $ 33,725 | $ 45,946 |
Supplemental Disclosures to t_4
Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Narrative (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2022 | Oct. 31, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Reclassification [Line Items] | |||||
Operating lease assets | $ 6,325 | ||||
Deferred financing costs, non-current, net of amortization | 4,000 | $ 5,000 | |||
Greenhouse gas liability, noncurrent | 23,000 | 18,000 | |||
Operating lease noncurrent liability | 5,213 | ||||
Other operating expense (income) | 3,722 | 3,101 | $ 5,781 | ||
Supplemental property tax assessment | $ 2,000 | 3,000 | |||
Gain on sale | 2,000 | ||||
Income from employee retention credits | 2,000 | ||||
Other expenses | 2,000 | ||||
Excess abandonment costs | 3,000 | ||||
Oil tank storage fees | 2,000 | ||||
Drilling rig standby charges | $ 1,000 | ||||
Placerita Field | |||||
Reclassification [Line Items] | |||||
Gain on sale | $ 2,000 | ||||
Piceance Basin | |||||
Reclassification [Line Items] | |||||
Gain (loss) on disposition of oil and gas property | $ 2,000 | 2,000 | |||
Revolving credit facility | 2017 RBL Facility | Line of credit | |||||
Reclassification [Line Items] | |||||
Unamortized debt issuance costs | $ 3,000 |
Supplemental Disclosures to t_5
Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Schedule of Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Accounts payable - trade | $ 40,286 | $ 17,699 |
Accrued expenses | 85,360 | 62,962 |
Royalties payable | 38,264 | 24,816 |
Greenhouse gas liability - current portion | 0 | 7,513 |
Taxes other than income tax liability | 6,640 | 8,273 |
Accrued interest | 10,885 | 10,736 |
Dividends payable | 0 | 4,800 |
Asset retirement obligation - current portion | 20,000 | 20,000 |
Total lease obligations | 1,666 | 0 |
Other | 0 | 725 |
Total accounts payable and accrued expenses | $ 203,101 | $ 157,524 |
Supplemental Disclosures to t_6
Supplemental Disclosures to the Balance Sheets and Statements of Cash Flows - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Supplemental Disclosures of Significant Non-Cash Operating Activities: | |||
Greenhouse gas liability - reclassification from current liability to long-term | $ 8,000 | $ 0 | $ 0 |
Greenhouse gas liability - reclassification from long-term to current liability | 0 | 0 | 33,376 |
Supplemental Disclosures of Significant Non-Cash Investing Activities: | |||
Material inventory transfers to oil and natural gas properties | 2,707 | 3,424 | 1,596 |
Supplemental Disclosures of Cash Payments (Receipts): | |||
Interest, net of amounts capitalized | 29,792 | 29,211 | 29,962 |
Income taxes payments | $ 3,633 | $ 699 | $ 222 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Additional Information (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||
Oct. 01, 2021 USD ($) | Feb. 28, 2022 USD ($) MMBoe | Jan. 31, 2022 USD ($) MMBoe | Oct. 31, 2021 USD ($) | May 31, 2020 USD ($) a | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Acquisitions, net of cash received | $ 25,917 | $ 50,568 | $ 0 | |||||||
Proceeds received from divestitures | 0 | 14,025 | $ 0 | |||||||
Gain on sale | 2,000 | |||||||||
Antelope Creek Acquisition | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Acquisition amount | $ 18,000 | |||||||||
Boe produced | MMBoe | 0.6 | |||||||||
Various Oil and Gas Properties | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Acquisition amount | 8,000 | |||||||||
Piceance Basin | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain (loss) on disposition of oil and gas property | $ (2,000) | $ (2,000) | ||||||||
Production per day, from acquisition | MMBoe | 1.2 | |||||||||
Placerita Field | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Proceeds received from divestitures | $ 14,000 | |||||||||
Gain on sale | $ 2,000 | |||||||||
C&J Well Services Acquisition | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Consideration transferred in acquisition | $ 53,000 | |||||||||
Acquisitions, net of cash received | $ 51,000 | 2,000 | ||||||||
Transaction costs | $ 3,000 | |||||||||
Chevron North Midway-Sunset Acquisition | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Consideration transferred in acquisition | $ 5,000 | |||||||||
Area of land acquired (in acres) | a | 740 | |||||||||
Payments to acquire business | $ 2,000 | |||||||||
Payment for contingent consideration liability | $ 3,000 | |||||||||
McKittrick Field | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Area of land acquired (in acres) | a | 267 |
Acquisitions and Divestitures_2
Acquisitions and Divestitures - Pro Forma Revenue (Details) - C&J Well Services Acquisition - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Business Acquisition [Line Items] | ||
Revenue | $ 664,549 | $ 657,796 |
Net income (loss) | $ 740 | $ (250,884) |
Earnings Per Share - Narrative
Earnings Per Share - Narrative (Details) - shares | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs) | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Incremental common shares attributable to dilutive effect of share-based payment arrangements (in shares) | 4,069,000 | 0 | 0 |
Earnings Per Share - Schedule o
Earnings Per Share - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Earnings Per Share, Basic [Abstract] | |||
Net income (loss) | $ 250,168 | $ (15,542) | $ (262,895) |
Weighted-average shares of common stock outstanding (in shares) | 78,517 | 80,209 | 79,802 |
Basic (loss) earnings per share (in dollars per share) | $ 3.19 | $ (0.19) | $ (3.29) |
Earnings Per Share, Diluted [Abstract] | |||
Net income (loss) | $ 250,168 | $ (15,542) | $ (262,895) |
Weighted-average shares of common stock outstanding (in shares) | 78,517 | 80,209 | 79,802 |
Dilutive effect of potentially dilutive securities (in shares) | 4,069 | 0 | 0 |
Weighted-average common shares outstanding - diluted (in shares) | 82,586 | 80,209 | 79,802 |
Diluted income (loss) per share (in dollars per share) | $ 3.03 | $ (0.19) | $ (3.29) |
Restricted Stock Units (RSUs) and Performance-based Restricted Stock Units (PSUs) | |||
Earnings Per Share, Diluted [Abstract] | |||
Potentially dilutive securities (in shares) | 3,300 | 100 |
Revenue Recognition - Narrative
Revenue Recognition - Narrative (Details) | 12 Months Ended |
Dec. 31, 2022 | |
Oil, natural gas and natural gas liquid sales | |
Disaggregation of Revenue [Line Items] | |
Payment term (within) | 30 days |
Service revenue | Minimum | |
Disaggregation of Revenue [Line Items] | |
Payment term (within) | 30 days |
Service revenue | Maximum | |
Disaggregation of Revenue [Line Items] | |
Payment term (within) | 60 days |
Revenue Recognition - Disaggreg
Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Revenue [Line Items] | |||
Total revenue, excluding assessed tax | $ 1,055,450 | $ 701,349 | $ 406,052 |
(Losses) gains on derivatives | (137,109) | (156,399) | 117,781 |
Total revenues and other | 918,341 | 544,950 | 523,833 |
Oil sales | |||
Disaggregation of Revenue [Line Items] | |||
Total revenue, excluding assessed tax | 806,631 | 587,613 | 362,976 |
Natural gas sales | |||
Disaggregation of Revenue [Line Items] | |||
Total revenue, excluding assessed tax | 29,515 | 32,679 | 14,041 |
Natural gas liquids sales | |||
Disaggregation of Revenue [Line Items] | |||
Total revenue, excluding assessed tax | 6,303 | 5,183 | 1,646 |
Service revenue | |||
Disaggregation of Revenue [Line Items] | |||
Total revenue, excluding assessed tax | 181,400 | 35,840 | 0 |
Electricity sales | |||
Disaggregation of Revenue [Line Items] | |||
Total revenue, excluding assessed tax | 30,833 | 35,636 | 25,813 |
Marketing revenues | |||
Disaggregation of Revenue [Line Items] | |||
Total revenue, excluding assessed tax | 289 | 3,921 | 1,426 |
Other revenues | |||
Disaggregation of Revenue [Line Items] | |||
Total revenue, excluding assessed tax | $ 479 | $ 477 | $ 150 |
Segment Information - Schedule
Segment Information - Schedule of Segment Information (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | 15 Months Ended | ||
Dec. 31, 2021 USD ($) business | Sep. 30, 2022 business | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Dec. 31, 2022 USD ($) segment | |
Segment Reporting Information [Line Items] | ||||||
Business segments | 2 | 1 | 2 | |||
Total revenue, excluding assessed tax | $ 1,055,450 | $ 701,349 | $ 406,052 | |||
Expenses during consolidation | 679,550 | 526,868 | 759,623 | |||
Net (loss) income before income taxes | 207,732 | (14,129) | (270,113) | |||
Adjusted EBITDA | 379,948 | 212,146 | ||||
Capital expenditures | 152,921 | 132,719 | $ 76,480 | |||
Total assets | $ 1,456,479 | 1,631,030 | 1,456,479 | $ 1,631,030 | ||
Intersegment Eliminations | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenue, excluding assessed tax | 3,000 | |||||
Expenses during consolidation | 3,000 | |||||
Corporate/Eliminations | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenue, excluding assessed tax | (3,188) | 0 | ||||
Net (loss) income before income taxes | (110,193) | (96,956) | ||||
Adjusted EBITDA | (57,976) | (43,310) | ||||
Capital expenditures | 2,536 | 2,211 | ||||
Total assets | (74,771) | (15,682) | (74,771) | (15,682) | ||
E&P | Operating Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenue, excluding assessed tax | 874,190 | 665,509 | ||||
Net (loss) income before income taxes | 303,178 | 82,826 | ||||
Adjusted EBITDA | 411,811 | 251,146 | ||||
Capital expenditures | 141,930 | 129,479 | ||||
Total assets | 1,450,157 | 1,563,251 | 1,450,157 | 1,563,251 | ||
Well Servicing and Abandonment | Operating Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Total revenue, excluding assessed tax | 184,448 | 35,840 | ||||
Net (loss) income before income taxes | 14,747 | 1 | ||||
Adjusted EBITDA | 26,113 | 4,310 | ||||
Capital expenditures | 8,455 | 1,029 | ||||
Total assets | $ 81,093 | $ 83,461 | $ 81,093 | $ 83,461 |
Segment Information - Adjusted
Segment Information - Adjusted EBITDA Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Segment Reporting Information [Line Items] | |||
Net income (loss) | $ 250,168 | $ (15,542) | $ (262,895) |
Interest expense | 30,917 | 31,964 | 34,295 |
Income tax (benefit) expense | (42,436) | 1,413 | (7,218) |
Depreciation, depletion and amortization | 156,847 | 144,495 | 139,180 |
Losses on derivatives | 48,314 | 117,822 | (116,746) |
Net cash paid for scheduled derivative settlements | (88,023) | (87,625) | |
Other operating expense | 3,722 | 3,101 | 5,781 |
Stock-based compensation expense | 16,973 | 13,783 | $ 14,630 |
Non-recurring costs(1) | 3,466 | 2,735 | |
Adjusted EBITDA | 379,948 | 212,146 | |
Operating Segments | E&P | |||
Segment Reporting Information [Line Items] | |||
Net income (loss) | 303,178 | 82,825 | |
Interest expense | 0 | 0 | |
Income tax (benefit) expense | 0 | 0 | |
Depreciation, depletion and amortization | 139,886 | 136,915 | |
Losses on derivatives | 48,314 | 117,822 | |
Net cash paid for scheduled derivative settlements | (88,023) | (87,625) | |
Other operating expense | 3,827 | 109 | |
Stock-based compensation expense | 1,361 | 1,100 | |
Non-recurring costs(1) | 3,268 | 0 | |
Adjusted EBITDA | 411,811 | 251,146 | |
Operating Segments | Well Servicing and Abandonment | |||
Segment Reporting Information [Line Items] | |||
Net income (loss) | 14,747 | 1 | |
Interest expense | 23 | 0 | |
Income tax (benefit) expense | 0 | 0 | |
Depreciation, depletion and amortization | 12,548 | 2,974 | |
Losses on derivatives | 0 | 0 | |
Net cash paid for scheduled derivative settlements | 0 | 0 | |
Other operating expense | (1,690) | 0 | |
Stock-based compensation expense | 287 | 0 | |
Non-recurring costs(1) | 198 | 1,335 | |
Adjusted EBITDA | 26,113 | 4,310 | |
Corporate/Eliminations | |||
Segment Reporting Information [Line Items] | |||
Net income (loss) | (67,757) | (98,368) | |
Interest expense | 30,894 | 31,964 | |
Income tax (benefit) expense | (42,436) | 1,413 | |
Depreciation, depletion and amortization | 4,413 | 4,606 | |
Losses on derivatives | 0 | 0 | |
Net cash paid for scheduled derivative settlements | 0 | 0 | |
Other operating expense | 1,585 | 2,992 | |
Stock-based compensation expense | 15,325 | 12,683 | |
Non-recurring costs(1) | 0 | 1,400 | |
Adjusted EBITDA | $ (57,976) | $ (43,310) |
Leases - Lease Cost (Details)
Leases - Lease Cost (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Lease Cost | |
Operating lease cost | $ 1,992 |
Total net lease cost | $ 1,992 |
Leases - Balance Sheet (Details
Leases - Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Assets | ||
Operating lease assets | $ 6,325 | |
Total assets | $ 6,325 | |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other Assets, Noncurrent | |
Liabilities | ||
Operating lease liability | $ 1,666 | $ 0 |
Operating lease noncurrent liability | 5,213 | |
Total liabilities | $ 6,879 | |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Accounts Payable and Accrued Liabilities, Current | |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other Liabilities, Noncurrent | |
Weighted average remaining lease term (in years) | 4 years 3 months 18 days | |
Weighted average discount rate | 5% |
Leases - Maturity Schedule (Det
Leases - Maturity Schedule (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Leases [Abstract] | ||
2023 | $ 1,963 | |
2024 | 1,650 | |
2025 | 1,542 | |
2026 | 1,549 | |
2027 | 935 | |
Total lease payments | 7,639 | |
Less imputed interest | (760) | |
Total liabilities | 6,879 | |
Less current obligations | (1,666) | $ 0 |
Operating lease noncurrent liability | $ 5,213 |
Leases - Cash Flow (Details)
Leases - Cash Flow (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Cash paid for amounts included in the measurement of lease liabilities | |
Operating cash flows from operating leases | $ 2,128 |
ROU assets obtained in exchange for operating lease liabilities | $ 7,956 |
Uncategorized Items - bry-20221
Label | Element | Value |
ABL Facility 2022 [Member] | ||
Proceeds from Long-Term Lines of Credit | us-gaap_ProceedsFromLongTermLinesOfCredit | $ 0 |
Repayments of Long-Term Lines of Credit | us-gaap_RepaymentsOfLongTermLinesOfCredit | $ 0 |