Cover page
Cover page - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Feb. 08, 2024 | Jun. 30, 2023 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2023 | ||
Document Transition Report | false | ||
Entity File Number | 001-31539 | ||
Entity Registrant Name | SM ENERGY CO | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 41-0518430 | ||
Entity Address, Address Line One | 1700 Lincoln Street, Suite 3200 | ||
Entity Address, City or Town | Denver | ||
Entity Address, State or Province | CO | ||
Entity Address, Postal Zip Code | 80203 | ||
City Area Code | (303) | ||
Local Phone Number | 861-8140 | ||
Title of 12(b) Security | Common stock, $0.01 par value | ||
Trading Symbol | SM | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Public Float | $ 3,683,521,784 | ||
Entity Common Stock, Shares Outstanding | 115,746,540 | ||
Documents Incorporated by Reference | Certain information required by Items 10, 11, 12, 13, and 14 of Part III of this report is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 2024 annual meeting of stockholders, to be filed within 120 days after December 31, 2023. | ||
Entity Central Index Key | 0000893538 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Document Financial Statement Error Correction [Flag] | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Auditor [Line Items] | |
Auditor Firm ID | 42 |
Auditor Name | Ernst & Young LLP |
Auditor Location | Denver, Colorado |
CONSOLIDATED BALANCE SHEETS (in
CONSOLIDATED BALANCE SHEETS (in thousands, except share data) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Current assets: | ||
Cash and cash equivalents | $ 616,164 | $ 444,998 |
Accounts receivable | 231,165 | 233,297 |
Derivative assets | 56,442 | 48,677 |
Prepaid expenses and other | 12,668 | 10,231 |
Total current assets | 916,439 | 737,203 |
Property and equipment (successful efforts method): | ||
Proved oil and gas properties | 11,477,358 | 10,258,368 |
Accumulated depletion, depreciation, and amortization | (6,830,253) | (6,188,147) |
Unproved oil and gas properties, net of valuation allowance of $35,362 and $38,008, respectively | 335,620 | 487,192 |
Wells in progress | 358,080 | 287,267 |
Other property and equipment, net of accumulated depreciation of $59,669 and $56,512, respectively | 35,615 | 38,099 |
Total property and equipment, net | 5,376,420 | 4,882,779 |
Noncurrent assets: | ||
Derivative assets | 8,672 | 24,465 |
Other noncurrent assets | 78,454 | 71,592 |
Total noncurrent assets | 87,126 | 96,057 |
Total assets | 6,379,985 | 5,716,039 |
Current liabilities: | ||
Accounts payable and accrued expenses | 611,598 | 532,289 |
Derivative liabilities | 6,789 | 56,181 |
Other current liabilities | 15,425 | 10,114 |
Total current liabilities | 633,812 | 598,584 |
Noncurrent liabilities: | ||
Revolving credit facility | 0 | 0 |
Senior Notes, net | 1,575,334 | 1,572,210 |
Asset retirement obligations | 118,774 | 108,233 |
Net deferred tax liabilities | 369,903 | 280,811 |
Derivative liabilities | 1,273 | 1,142 |
Other noncurrent liabilities | 65,039 | 69,601 |
Total noncurrent liabilities | 2,130,323 | 2,031,997 |
Commitments and contingencies (note 6) | ||
Stockholders’ equity: | ||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 115,745,393 and 121,931,676 shares, respectively | 1,157 | 1,219 |
Additional paid-in capital | 1,565,021 | 1,779,703 |
Retained earnings | 2,052,279 | 1,308,558 |
Accumulated other comprehensive loss | (2,607) | (4,022) |
Total stockholders’ equity | 3,615,850 | 3,085,458 |
Total liabilities and stockholders’ equity | $ 6,379,985 | $ 5,716,039 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEET (PARENTHETICAL) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Unproved oil and gas properties, net of valuation allowance | $ 35,362 | $ 38,008 |
Other property and equipment, net of accumulated depreciation | $ 59,669 | $ 56,512 |
Common Stock, par value per share | $ 0.01 | $ 0.01 |
Common Stock, shares authorized | 200,000,000 | 200,000,000 |
Common Stock, shares issued | 115,745,393 | 121,931,676 |
Common Stock, shares outstanding | 115,745,393 | 121,931,676 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating revenues and other income: | |||
Oil, gas, and NGL production revenue | $ 2,363,889 | $ 3,345,906 | $ 2,597,915 |
Other operating income | 9,997 | 12,741 | 24,979 |
Total operating revenues and other income | 2,373,886 | 3,358,647 | 2,622,894 |
Operating expenses: | |||
Oil, gas, and NGL production expense | 563,543 | 620,912 | 505,416 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 690,481 | 603,780 | 774,386 |
Exploration | 59,480 | 54,943 | 39,296 |
Impairment | 0 | 7,468 | 35,000 |
General and administrative | 121,063 | 114,558 | 111,945 |
Net derivative (gain) loss | (68,154) | 374,012 | 901,659 |
Other operating expense, net | 20,567 | 3,493 | 46,069 |
Total operating expenses | 1,386,980 | 1,779,166 | 2,413,771 |
Income from operations | 986,906 | 1,579,481 | 209,123 |
Interest expense | (91,630) | (120,346) | (160,353) |
Interest income | 19,854 | 5,774 | 1,716 |
Loss on extinguishment of debt | 0 | (67,605) | (2,139) |
Other non-operating expense | (928) | (1,534) | (2,180) |
Income from before income taxes | 914,202 | 1,395,770 | 46,167 |
Income tax expense | (96,322) | (283,818) | (9,938) |
Net income | $ 817,880 | $ 1,111,952 | $ 36,229 |
Basic weighted-average common shares outstanding | 118,678 | 122,351 | 119,043 |
Diluted weighted-average common shares outstanding | 119,240 | 124,084 | 123,690 |
Basic net income per common share | $ 6.89 | $ 9.09 | $ 0.30 |
Diluted net income per common share | $ 6.86 | $ 8.96 | $ 0.29 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 817,880 | $ 1,111,952 | $ 36,229 | |
Other comprehensive income, net of tax: | ||||
Pension liability adjustment (1) | [1] | 1,415 | 8,827 | 749 |
Total other comprehensive income, net of tax | 1,415 | 8,827 | 749 | |
Total comprehensive income | $ 819,295 | $ 1,120,779 | $ 36,978 | |
[1] Please refer to Note 11 – Pension Benefits for additional discussion of the pension liability adjustment. |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (in thousands, except share data and dividends per share) - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Loss |
Net cash dividends declared per share | $ 0.02 | ||||
Balances, Common Stock, Shares, Outstanding, Beginning at Dec. 31, 2020 | 114,742,304 | ||||
Balances, Total Stockholders' Equity, Beginning at Dec. 31, 2020 | $ 2,016,160 | $ 1,147 | $ 1,827,914 | $ 200,697 | $ (13,598) |
Increase (Decrease) in Stockholders' Equity | |||||
Net income | 36,229 | 36,229 | |||
Other comprehensive income | 749 | 749 | |||
Net cash dividends declared | (2,393) | (2,393) | |||
Issuance of common stock under Employee Stock Purchase Plan (Shares) | 313,773 | ||||
Issuance of common stock under Employee Stock Purchase Plan (Amount) | 2,639 | $ 3 | 2,636 | ||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Shares) | 827,572 | ||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Amount) | (9,072) | $ 9 | (9,081) | ||
Stock-based compensation expense (Shares) | 60,510 | ||||
Stock-based compensation expense (Amount) | 18,819 | $ 1 | 18,818 | ||
Issuance of common stock through cashless exercise of Warrants (Shares) | 5,918,089 | ||||
Issuance of common stock through cashless exercise of Warrants (Amount) | $ 59 | ||||
Other | 0 | 59 | |||
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2021 | 121,862,248 | ||||
Balances, Total Stockholders' Equity, Ending at Dec. 31, 2021 | $ 2,063,131 | $ 1,219 | 1,840,228 | 234,533 | (12,849) |
Net cash dividends declared per share | $ 0.31 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | $ 1,111,952 | 1,111,952 | |||
Other comprehensive income | 8,827 | 8,827 | |||
Net cash dividends declared | (37,927) | (37,927) | |||
Issuance of common stock under Employee Stock Purchase Plan (Shares) | 113,785 | ||||
Issuance of common stock under Employee Stock Purchase Plan (Amount) | 3,039 | $ 1 | 3,038 | ||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Shares) | 1,291,427 | ||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Amount) | (25,129) | $ 13 | (25,142) | ||
Stock-based compensation expense (Shares) | 29,471 | ||||
Stock-based compensation expense (Amount) | $ 18,772 | 18,772 | |||
Issuance of common stock through cashless exercise of Warrants (Shares) | 0 | ||||
Stock Repurchased and Retired During Period, Shares | (1,365,000) | (1,365,255) | |||
Stock Repurchased and Retired During Period, Value | $ (14) | ||||
Other | $ (57,207) | (57,193) | |||
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2022 | 121,931,676 | 121,931,676 | |||
Balances, Total Stockholders' Equity, Ending at Dec. 31, 2022 | $ 3,085,458 | $ 1,219 | 1,779,703 | 1,308,558 | (4,022) |
Net cash dividends declared per share | $ 0.63 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net income | $ 817,880 | 817,880 | |||
Other comprehensive income | 1,415 | 1,415 | |||
Net cash dividends declared | (74,159) | (74,159) | |||
Issuance of common stock under Employee Stock Purchase Plan (Shares) | 114,427 | ||||
Issuance of common stock under Employee Stock Purchase Plan (Amount) | 3,058 | $ 1 | 3,057 | ||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Shares) | 554,216 | ||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Amount) | (7,882) | $ 6 | (7,888) | ||
Stock-based compensation expense (Shares) | 56,872 | ||||
Stock-based compensation expense (Amount) | $ 20,250 | $ 1 | 20,249 | ||
Issuance of common stock through cashless exercise of Warrants (Shares) | 19,037 | ||||
Stock Repurchased and Retired During Period, Shares | (6,931,000) | (6,930,835) | |||
Stock Repurchased and Retired During Period, Value | $ (230,170) | $ (70) | (230,100) | ||
Other | $ 0 | ||||
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2023 | 115,745,393 | 115,745,393 | |||
Balances, Total Stockholders' Equity, Ending at Dec. 31, 2023 | $ 3,615,850 | $ 1,157 | $ 1,565,021 | $ 2,052,279 | $ (2,607) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Cash flows from operating activities: | ||||
Net income | $ 817,880 | $ 1,111,952 | $ 36,229 | |
Adjustments to reconcile net income to net cash provided by operating activities: | ||||
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 690,481 | 603,780 | 774,386 | |
Impairment | 0 | 7,468 | 35,000 | |
Stock-based compensation expense | 20,250 | 18,772 | 18,819 | |
Net derivative (gain) loss | (68,154) | 374,012 | 901,659 | |
Net derivative settlement gain (loss) | 26,921 | (710,700) | (748,958) | |
Amortization of debt discount and deferred financing costs | 5,486 | 10,281 | 17,275 | |
Loss on extinguishment of debt | 0 | 67,605 | 2,139 | |
Deferred income taxes | 88,256 | 269,057 | 9,565 | |
Other, net | (2,175) | 6,242 | (3,753) | |
Changes in working capital: | ||||
Accounts receivable | (10,191) | 38,554 | (101,047) | |
Prepaid expenses and other | (2,437) | (1,055) | 220 | |
Accounts payable and accrued expenses | 8,077 | (109,562) | 218,238 | |
Net cash provided by operating activities | 1,574,394 | 1,686,406 | 1,159,772 | |
Cash flows from investing activities: | ||||
Capital expenditures | (989,411) | (879,934) | (674,841) | |
Acquisition of proved and unproved oil and gas properties | (109,931) | (7) | (3,321) | |
Other, net | 657 | (322) | 10,927 | |
Net cash used in investing activities | (1,098,685) | (880,263) | (667,235) | |
Cash flows from financing activities: | ||||
Proceeds from revolving credit facility | 0 | 0 | 1,832,500 | |
Repayment of revolving credit facility | 0 | 0 | (1,925,500) | |
Net proceeds from Senior Notes | 0 | 0 | 392,771 | |
Cash paid to repurchase Senior Notes | 0 | 584,946 | 450,776 | |
Repurchase of common stock | (228,105) | (57,207) | 0 | |
Net proceeds from sale of common stock | 3,058 | 3,039 | 2,639 | |
Dividends paid | (71,614) | (19,637) | (2,393) | |
Net share settlement from issuance of stock awards | (7,882) | (25,129) | (9,072) | |
Other, net | 0 | (9,981) | 0 | |
Net cash used in financing activities | (304,543) | (693,861) | (159,831) | |
Net change in cash, cash equivalents, and restricted cash | 171,166 | 112,282 | 332,706 | |
Cash, cash equivalents, and restricted cash at beginning of period | 444,998 | 332,716 | 10 | |
Cash, cash equivalents, and restricted cash at end of period | 616,164 | 444,998 | 332,716 | |
Supplemental Cash Flow Information - Operating Activities: | ||||
Cash paid for interest, net of capitalized interest | (86,947) | (134,240) | (136,606) | |
Net cash paid for income taxes | (8,975) | (10,576) | (864) | |
Supplemental Cash Flow Information - Investing Activities: | ||||
Changes in capital expenditure accruals | $ 80,794 | 29,789 | (10,826) | |
Non-cash investing and financing activities | ||||
Non-cash financing activities (1) | [1] | |||
[1] (1) Please refer to Note 5 – Long-Term Debt for discussion of the debt transactions completed during the years ended December 31, 2022, and 2021. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 1 – Summary of Significant Accounting Policies Description of Operations SM Energy Company, together with its consolidated subsidiaries, is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of Texas. Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the accompanying consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2023, through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of DD&A expense, impairment of proved and unproved oil and gas properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements. Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. Accounts Receivable The Company’s accounts receivable primarily consist of receivables due from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had minimal bad debts. Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. Please refer to Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses for additional disclosure. Concentration of Credit Risk and Major Customers The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is regularly reviewed. The Company does not believe the loss of any single purchaser of its production would materially affect its operating results, as oil, gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating areas. The following major customers and entities under common control accounted for 10 percent or more of the Company’s total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2023 2022 2021 Major customer #1 24 % 24 % 27 % Major customer #2 11 % 7 % 9 % Major customer #3 6 % 8 % 15 % Group #1 of entities under common control 22 % 24 % 18 % For its commodity derivative instruments, the Company’s policy is to only enter into contracts with affiliates of the lenders under its Credit Agreement as its derivative counterparties, and each counterparty must have certain minimum investment grade senior unsecured debt ratings. The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operation. The Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment. Oil and Gas Producing Activities Proved properties . The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, property acquisition costs and development costs are capitalized when incurred. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated net proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same asset group basis; however, the units-of-production method is based on estimated total net proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Proved oil and gas property costs are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties . The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on an asset group basis, neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the accompanying statements of operations in the amount of such excess. Exploratory . Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting for oil and gas properties, exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows. Please refer to Note 8 – Fair Value Measurements for additional information. Other Property and Equipment Other property and equipment such as facilities, equipment inventory, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three Facilities and equipment inventory costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of facilities and equipment inventory, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. For facilities, the valuation includes consideration of the proved and unproved assets supported by the facilities, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, changes in inflation factors, or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 14 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2023, and 2022. Derivative Financial Instruments The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials for its expected future oil, gas, and NGL production, and the associated effect on cash flows. These instruments typically include commodity price swaps and collar arrangements, as well as, basis swaps and roll differential swaps. Commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on net derivative settlements are included within the cash flows from operating activities section of the accompanying statements of cash flows. Please refer to Note 7 – Derivative Financial Instruments for additional discussion. Revenue Recognition The Company derives revenue predominately from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. The Company uses knowledge of its properties, contractual arrangements, historical performance, NYMEX, local spot market, and OPIS prices, and other factors as the basis of these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received. Please refer to Note 2 – Revenue from Contracts with Customers for additional discussion. Stock-Based Compensation At December 31, 2023, the Company had stock-based employee compensation plans that included RSUs and Performance Share Units (“PSU or “PSUs”) issued to employees, RSUs and restricted stock issued to non-employee directors, and an employee stock purchase plan available to eligible employees. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur. Please refer to Note 10 – Compensation Plans for additional discussion . Income Taxes The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the accompanying consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. The cumulative effect of enacted tax rate changes on the net balance of reported amounts of assets and liabilities is recognized in the period of enactment. The Company’s policy is to record interest related to income taxes in the interest expense line item in the accompanying statements of operations, and to record penalties related to income taxes in the other non-operating expense line item in the accompanying statements of operations. Please refer to Note 4 – Income Taxes for additional discussion. Earnings per Share The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Please refer to Note 9 – Earnings Per Share for additional discussion. Comprehensive Income (Loss) Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that, under GAAP, are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. Please refer to Note 11 – Pension Benefits for detail on the changes in the balances of components comprising other comprehensive income. Fair Value of Financial Instruments The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt , are recorded at cost, net of unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurements. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Leases The Company accounts for leases in accordance with ASC Topic 842, Leases , (“Topic 842”), which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component. Certain leases may contain both lease and non-lease components. The Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include those to determine the discount rate and lease term. Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a right-of-use (“ROU”) asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Exercising an early termination option may result in an early termination penalty depending on the terms of the underlying agreement. The Company excludes from the balance sheet leases with terms that are less than one year. An ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of an ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance. Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. As discussed above, excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. Please refer to Note 12 – Leases for additional discussion. Industry Segment and Geographic Information The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a single industry segment. Off-Balance Sheet Arrangements The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated into the Company’s consolidated financial statements. The Company has not been involved in any unconsolidated SPE transactions during 2023 or 2022, or through the filing of this report. Recently Issued Accounting Standards In October 2023, the FASB issued ASU No. 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative (“ASU 2023-06”). ASU 2023-06 was issued to modify the disclosure or presentation requirements of a variety of topics in the codification. The effective date for each amendment will be the date on which the SEC’s removal of the related disclosure from Regulation S-X or Regulation S-K becomes effective, with early adoption prohibited. The Company evaluated ASU 2023-06 and does not expect the adoption of the applicable amendments to have a material effect on its consolidated financial statements and related disclosures. In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ( “ASU 2023-07” ). ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a retrospective basis to all prior periods presented in the financial statements. The Company is within the scope of this ASU and is evaluating the impact of this ASU on its consolidated financial statement disclosures. In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ( “ASU 2023-09” ). ASU 2023-09 was issued to improve the disclosures related to rate reconciliations and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The guidance should be applied on a prospective basis, however, retrospective application is permitted. The Company is within the scope of this ASU and is evaluating the impact of this ASU on its consolidated financial statement disclosures. As of the filing of this report, the Company has not elected to early adopt ASU 2023-07 or ASU 2023-09. As of December 31, 2023, and through the filing of this report, no other ASUs have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s consolidated financial statements and related disclosures. |
Revenue from Contracts with Cus
Revenue from Contracts with Customers | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contracts with Customers | Note 2 – Revenue from Contracts with Customers The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs from its Midland Basin and South Texas assets. Oil, gas, and NGL production revenue presented within the accompanying statements of operations reflects revenue generated from contracts with customers. The tables below present oil, gas, and NGL production revenue by product type for each of the Company’s operating areas for the years ended December 31, 2023, 2022, and 2021: For the year ended December 31, 2023 Midland Basin South Texas Total (in thousands) Oil production revenue $ 1,347,780 $ 465,995 $ 1,813,775 Gas production revenue 175,183 152,700 327,883 NGL production revenue 687 221,544 222,231 Total $ 1,523,650 $ 840,239 $ 2,363,889 Relative percentage 64 % 36 % 100 % For the year ended December 31, 2022 Midland Basin South Texas Total (in thousands) Oil production revenue $ 1,816,597 $ 453,471 $ 2,270,068 Gas production revenue 432,831 358,049 790,880 NGL production revenue 986 283,972 284,958 Total $ 2,250,414 $ 1,095,492 $ 3,345,906 Relative percentage 67 % 33 % 100 % For the year ended December 31, 2021 Midland Basin South Texas Total (in thousands) Oil production revenue $ 1,701,915 $ 189,911 $ 1,891,826 Gas production revenue 326,115 199,364 525,479 NGL production revenue 381 180,229 180,610 Total $ 2,028,411 $ 569,504 $ 2,597,915 Relative percentage 78 % 22 % 100 % The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Transfer of control determines the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred by the Company prior to transfer of control are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred at or near the wellhead, sales are based on a wellhead market price that may be affected by fees and other deductions incurred by the purchaser subsequent to the transfer of control. In general, the Company generates production revenue from a combination of the following types of contracts: • The Company sells oil and gas production at or near the wellhead and receives an agreed-upon market price from the purchaser. Under this type of arrangement, control transfers at or near the wellhead. • The Company has certain processing arrangements that include the delivery of unprocessed gas to a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. The Company also has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers, relate to the point in time when control transfers to purchasers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained. The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period. Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of December 31, 2023, and 2022, were $175.3 million and $184.5 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. |
Equity
Equity | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Stockholders' Equity Note Disclosure | Note 3 – Equity Stock Repurchase Program During 2022, the Company’s Board of Directors approved the Stock Repurchase Program authorizing the Company to repurchase up to $500.0 million in aggregate value of its common stock through December 31, 2024. The Stock Repurchase Program permits the Company to repurchase shares of its common stock from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of the Credit Agreement and the indentures governing the Senior Notes, as defined in Note 5 – Long-Term Debt . The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of the Company’s common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by the Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of its shares will be repurchased by the Company. The following table presents the Company’s common stock repurchase activity for the years ended December 31, 2023, and 2022: For the Years Ended December 31, 2023 2022 (in thousands, except per share data) Shares of common stock repurchased (1) 6,931 1,365 Weighted-average price per share (2) $ 32.89 $ 41.88 Cost of shares of common stock repurchased (2) (3) $ 227,966 $ 57,179 ____________________________________________ (1) All repurchased shares of the Company’s common stock were retired upon repurchase. (2) Amounts exclude excise taxes, commissions, and fees. (3) Amounts may not calculate due to rounding. As of the filing of this report, $214.9 million remains available for repurchases of the Company’s outstanding common stock through December 31, 2024, under the Stock Repurchase Program. Dividends During 2023, the Company’s Board of Directors approved an increase to the Company’s fixed dividend to $0.72 per share annually, to be paid in quarterly increments of $0.18 per share, beginning in the first quarter of 2024. During the year ended December 31, 2023, net cash dividends declared totaled $74.2 million. Warrants On June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its then outstanding common stock, at an exercise price of $0.01 per share (“Warrants”). The Warrants became exercisable at the election of the holders on January 15, 2021, pursuant to the terms of the Warrant Agreement, dated June 17, 2020, and all of the Warrants were exercised prior to their expiration date of June 30, 2023. The following table presents activity related to warrants exercised during the periods presented: For the Years Ended December 31, 2023 2022 2021 (in thousands, except per share data) Warrants exercised 19 — 5,922 Shares of common stock issued as a result of cashless exercise of warrants 19 — 5,918 Weighted-average share price on exercise date $ 29.09 $ — $ 15.45 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 4 – Income Taxes The provision for income taxes consisted of the following: For the Years Ended December 31, 2023 2022 2021 (in thousands) Current portion of income tax (expense) benefit Federal $ (8,461) $ (9,230) $ — State 395 (5,531) (373) Deferred portion of income tax expense (88,256) (269,057) (9,565) Income tax expense $ (96,322) $ (283,818) $ (9,938) Effective tax rate 10.5 % 20.3 % 21.5 % The components of the net deferred tax liabilities are as follows: As of December 31, 2023 2022 (in thousands) Deferred tax liabilities: Oil and gas properties excluding asset retirement obligation liabilities $ 450,634 $ 358,537 Derivative assets 12,319 3,416 Other 6,283 6,059 Total deferred tax liabilities 469,236 368,012 Deferred tax assets: Credit carryover, net 56,097 161 Asset retirement obligation liabilities 26,592 24,899 Lease liabilities 4,454 4,525 Federal and state tax net operating loss carryovers 3,271 28,151 Legal liabilities 2,838 — Pension 2,453 3,970 Interest carryforward 1,031 22,667 Other 4,003 4,444 Total deferred tax assets 100,739 88,817 Valuation allowance (1,406) (1,616) Net deferred tax assets 99,333 87,201 Net deferred tax liabilities $ 369,903 $ 280,811 Current federal income tax refundable (payable) $ (4,899) $ 770 Current state income tax refundable (payable) $ 1,253 $ (5,316) As of December 31, 2023, the Company had utilized all of its remaining federal net operating loss (“NOL”) carryovers and had gross state NOL carryforwards of $74.0 million. Other than in states with no NOL carryforward expiration, the Company’s state NOL carryforwards expire between 2029 and 2039. The Company’s current valuation allowance includes an amount for state NOL carryforwards and state tax credits, which are expected to expire before they can be utilized. The Company commissioned a multi-year R&D credit study in 2022, which was completed during 2023, and resulted in a favorable adjustment to the Company’s effective tax rate and a reduction of the Company’s 2022 and 2023 tax obligations. After utilizing a portion of the credits for the 2022 and 2023 tax years, the recorded net carryover R&D credit, as of December 31, 2023, expected to be utilized in future periods totaled $56.1 million. The R&D credits expire between 2037 and 2043. Income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences primarily relate to the effect of federal tax credits, state income taxes, changes in valuation allowances, excess tax benefits and deficiencies from stock-based compensation awards, tax deduction limitations on compensation of covered individuals, the cumulative impact of other smaller permanent differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balances. These differences for the years ended December 31, 2023, 2022, and 2021, are presented below: For the Years Ended December 31, 2023 2022 2021 (in thousands) Federal statutory tax expense $ (191,983) $ (293,112) $ (9,695) (Increase) decrease in tax resulting from: Net federal R&D tax credit 92,420 — — Change in valuation allowance 210 16,845 (5,073) State tax (expense) benefit, net of federal effect 5,166 (9,870) (211) Other (2,135) 2,319 5,041 Income tax expense $ (96,322) $ (283,818) $ (9,938) Acquisitions, divestitures, drilling activity, and basis differentials, which impact the prices received for oil, gas, and NGLs, impact the apportionment of taxable income to the states where the Company owns oil and gas properties. As these factors change, the Company’s state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total state income tax expense reported. Items affecting state apportionment factors are evaluated upon completion of the prior year income tax return, after significant acquisitions and divestitures, if there are significant changes in drilling activity, or if estimated state revenue changes occur during the year. For all years before 2020, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities. The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2024, except for any potential changes related to the Company’s R&D credit study discussed above and any potential 2024 R&D credit claims. The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2023 2022 2021 (in thousands) Beginning balance $ 446 $ 446 $ 446 Additions based on tax positions related to current year 23,713 — — Ending balance $ 24,159 $ 446 $ 446 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Note 5 – Long-Term Debt Credit Agreement The Company’s Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of December 31, 2023, the borrowing base and aggregate lender commitments under the Credit Agreement were $2.5 billion and $1.25 billion, respectively. The revolving credit facility is secured by substantially all of the Company’s proved oil and gas properties. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both the Company’s proved oil and gas properties reflected in the Company’s most recent reserve report; and commodity derivative contracts, each as determined by the Company’s lender group. The next scheduled borrowing base redetermination date is April 1, 2024. The Credit Agreement is scheduled to mature on the earlier of August 2, 2027 (“Stated Maturity Date”), or 91 days prior to the maturity date of any of the Company’s outstanding Senior Notes, as defined below, to the extent that, on or before such date, the respective Senior Notes have not been repaid, exchanged, repurchased, refinanced, or otherwise redeemed in full, and, if refinanced or exchanged, with a scheduled maturity date that is not earlier than at least 180 days after the Stated Maturity Date. The financial covenants under the Credit Agreement are discussed under Covenants below. Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement, as presented in the table below. At the Company’s election, borrowings under the Credit Agreement may be in the form of SOFR, Alternate Base Rate (“ABR”), or Swingline loans. SOFR loans accrue interest at SOFR plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid. Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% SOFR Loans 2.000 % 2.250 % 2.500 % 2.750 % 3.000 % ABR Loans or Swingline Loans 1.000 % 1.250 % 1.500 % 1.750 % 2.000 % Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 % The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of February 8, 2024, December 31, 2023, and December 31, 2022: As of February 8, 2024 As of December 31, 2023 As of December 31, 2022 (in thousands) Revolving credit facility (1) $ — $ — $ — Letters of credit (2) 2,500 2,500 6,000 Available borrowing capacity 1,247,500 1,247,500 1,244,000 Total aggregate lender commitment amount $ 1,250,000 $ 1,250,000 $ 1,250,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $8.5 million and $10.8 million as of December 31, 2023, and 2022, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis. Senior Notes The Company’s Senior Notes, net line item on the accompanying balance sheets as of December 31, 2023, and 2022, consisted of the following (collectively referred to as “Senior Notes”): As of December 31, 2023 As of December 31, 2022 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net (in thousands) 5.625% Senior Notes due 2025 $ 349,118 $ 896 $ 348,222 $ 349,118 $ 1,528 $ 347,590 6.75% Senior Notes due 2026 419,235 1,868 417,367 419,235 2,569 416,666 6.625% Senior Notes due 2027 416,791 2,395 414,396 416,791 3,172 413,619 6.5% Senior Notes due 2028 400,000 4,651 395,349 400,000 5,665 394,335 Total $ 1,585,144 $ 9,810 $ 1,575,334 $ 1,585,144 $ 12,934 $ 1,572,210 The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices that may include a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes. Fees incurred upon issuance of each series of Senior Notes are being amortized as deferred financing costs over the life of the respective notes, unless earlier redeemed or retired, in which case amortization has been proportionately accelerated. 2025 Senior Notes. On May 21, 2015, the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025, at par, which mature on June 1, 2025 (“2025 Senior Notes”). The Company received net proceeds of $491.0 million after deducting fees of $9.0 million. 2026 Senior Notes. On September 12, 2016, the Company issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026, at par, which mature on September 15, 2026 (“2026 Senior Notes”). The Company received net proceeds of $491.6 million after deducting fees of $8.4 million. 2027 Senior Notes. On August 20, 2018, the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027, at par, which mature on January 15, 2027 (“2027 Senior Notes”). The Company received net proceeds of $492.1 million after deducting fees of $7.9 million. 2028 Senior Notes. On June 23, 2021, the Company issued $400.0 million in aggregate principal amount of 6.5% Senior Notes due 2028, at par, which mature on July 15, 2028 (“2028 Senior Notes”). The Company received net proceeds of $392.8 million after deducting fees of $7.2 million. Senior Notes Activity On February 14, 2022, the Company redeemed the $104.8 million of aggregate principal amount outstanding of its 5.0% Senior Notes due 2024 (“2024 Senior Notes”), with cash on hand, pursuant to the terms of the indenture governing the 2024 Senior Notes which provided for a redemption price equal to 100 percent of the principal amount of the 2024 Senior Notes on the date of redemption, plus accrued and unpaid interest. Upon redemption, the Company accelerated the amortization of all remaining previously unamortized deferred financing costs. The Company canceled all redeemed 2024 Senior Notes upon settlement. On June 23, 2021, the Company issued $400.0 million in aggregate principal amount of its 2028 Senior Notes, as described above. The net proceeds of $392.8 million were used to repurchase $193.1 million and $172.3 million of outstanding principal amount of the Company’s 6.125% Senior Notes due 2022 (“2022 Senior Notes”) and 2024 Senior Notes, respectively, through a cash tender offer (“Tender Offer”), and to redeem the remaining $19.3 million of 2022 Senior Notes not repurchased as part of the Tender Offer (“2022 Senior Notes Redemption”). The Company paid total consideration, excluding accrued interest, of $385.3 million, and recorded a net loss on extinguishment of debt of $2.1 million for the year ended December 31, 2021, which included the accelerated expense recognition of $1.5 million of the remaining unamortized deferred financing costs and $0.6 million of net premiums. The Company canceled all repurchased and redeemed 2022 Senior Notes and 2024 Senior Notes upon settlement. Senior Secured Notes Activity On June 17, 2022, the Company redeemed all of the $446.7 million of aggregate principal amount outstanding of its 10.0% Senior Secured Notes due 2025 (“2025 Senior Secured Notes”), with cash on hand, at a redemption price equal to 107.5 percent of the principal amount outstanding on the date of the redemption, plus accrued and unpaid interest. Upon redemption, the Company recorded a net loss on extinguishment of debt of $67.2 million which included $33.5 million of premium paid, $26.3 million of accelerated expense recognition of the unamortized debt discount, and $7.4 million of accelerated expense recognition of the remaining unamortized deferred financing costs. The Company canceled all redeemed 2025 Senior Secured Notes upon settlement. On July 1, 2021, the 1.50% Senior Secured Convertible Notes (“2021 Senior Secured Convertible Notes”) matured, and on that day, the Company used borrowings under its revolving credit facility to retire, at par, the outstanding principal amount of $65.5 million. Covenants The Company is subject to certain financial and non-financial covenants under the Credit Agreement and the indentures governing the Senior Notes that, among other terms, limit the Company’s ability to incur additional indebtedness, make restricted payments including dividends, sell assets, create liens that secure debt, enter into transactions with affiliates, make certain investments, or merge or consolidate with other entities. The financial covenants under the Credit Agreement require that the Company’s (a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 3.50 to 1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.00 to 1.00 as of the last day of any fiscal quarter. The Company was in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes as of December 31, 2023, and through the filing of this report. Capitalized Interest Capitalized interest costs for the years ended December 31, 2023, 2022, and 2021, totaled $20.4 million, $17.6 million, and $15.0 million, respectively. The amount of interest the Company capitalizes generally fluctuates based on the amount borrowed, the Company’s capital program, and the timing and amount of costs associated with capital projects that are considered in progress. Capitalized interest costs are included in total costs incurred. Please refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional information. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 6 – Commitments and Contingencies Commitments As of December 31, 2023, the Company had entered into various types of agreements as discussed below. The following table presents the annual minimum payments related to these agreements for the next five years, and the total minimum payments thereafter as of December 31, 2023: For the Years Ending December 31, Amount (in thousands) 2024 $ 74,992 2025 52,175 2026 28,133 2027 13,791 2028 12,461 Thereafter 14,655 Total $ 196,207 Drilling Rig Contracts. The Company has drilling rig contracts in place to facilitate its drilling plans. As of December 31, 2023, the Company’s drilling rig commitments totaled $19.1 million under contract terms extending through the third quarter of 2024. If all of these contracts were terminated as of December 31, 2023, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $12.3 million in early termination fees. Subsequent to December 31, 2023, the Company entered into a new drilling rig contract, and as of the filing of this report, the Company’s drilling rig commitments totaled $14.5 million under contract terms extending through the third quarter of 2024. If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $8.9 million in early termination fees. No material expenses related to early termination or standby fees were incurred by the Company during the year ended December 31, 2023, and the Company does not expect to incur material penalties with regard to its drilling rig contracts during 2024. Delivery Commitments. The Company has gathering, processing, transportation throughput, and delivery commitments with various third-parties that require delivery of a minimum amount of oil and produced water. As of December 31, 2023, the Company had commitments to deliver a minimum of 5 MMBbl of oil through July of 2026 and 11 MMBbl of produced water through June of 2027. The Company would be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. As of December 31, 2023, if the Company failed to deliver any product, as applicable, the aggregate undiscounted deficiency payments would total approximately $11.5 million. This amount does not include deficiency payment estimates associated with approximately 1 MMBbl of future oil delivery commitments where the Company cannot predict with accuracy the amount and timing of these payments, as such payments are dependent upon the price of oil in effect at the time of settlement. The Company expects to fulfill the delivery commitments from a combination of production from existing productive wells, future development of proved undeveloped reserves, and future development of resources not yet characterized as proved reserves. Under certain of the Company’s commitments, if the Company is unable to deliver the minimum quantity from its production, it may deliver production acquired from third-parties to satisfy its minimum volume commitments. As of the filing of this report, the Company does not expect to incur material shortfalls with regard to these commitments. Office Leases. The Company leases office space under various operating leases totaling $33.3 million, including maintenance, with certain terms extending into 2033. Rent expense for the years ended December 31, 2023, 2022, and 2021, was $2.5 million, $3.5 million, and $4.8 million, respectively. Electrical Power Purchase Contracts. As of December 31, 2023, the Company had fixed price contracts for the purchase of electrical power through March of 2029 with a total remaining obligation of $41.8 million. Sand Purchase Commitment. As of December 31, 2023, the Company had a sand purchase agreement with a minimum commitment of $46.8 million through March of 2026. As of December 31, 2023, if the Company failed to purchase the minimum amount required by the contract, it would be subject to penalties of up to $10.0 million. As of the filing of this report, the Company does not expect to incur penalties with regard to this agreement. Compression Service Contracts . As of December 31, 2023, the Company had compression service contracts with terms extending through 2027 for equipment being used in field operations with a total remaining obligation of $19.5 million. Miscellaneous Contracts and Leases . As of December 31, 2023, the Company had miscellaneous contracts and leases totaling $24.2 million, primarily related to IT contracts, water purchase agreements, and vehicle leases, with terms extending through 2027. Drilling and Completion Commitments. As of December 31, 2023, the Company had an agreement that includes minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, 2024, the Company will be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. As of December 31, 2023, the liquidated damages could range from zero to a maximum of $8.3 million, with the maximum exposure assuming no additional development activity occurred prior to March 31, 2024. As of the filing of this report, the Company does not expect to incur material liquidated damages with regard to this agreement. Contingencies The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |
Derivative Financial Instruments | Note 7 – Derivative Financial Instruments Summary of Oil, Gas, and NGL Derivative Contracts in Place The Company regularly enters into commodity derivative contracts to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials, and the associated effect on cash flows. All commodity derivative contracts that the Company enters into are for other-than-trading purposes. The Company’s commodity derivative contracts consist of price swap and collar arrangements for oil and gas production, and price swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap price, the Company receives the difference between the index price and the agreed upon swap price. If the index price is higher than the swap price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. The Company has entered into fixed price oil and gas basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production is sold. As of December 31, 2023, the Company had basis swap contracts with fixed price differentials between: • NYMEX WTI and Argus WTI Midland (“WTI Midland”) for a portion of its Midland Basin oil production with sales contracts that settle at WTI Midland prices; • NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal ("WTI Houston MEH”) for a portion of its South Texas oil production with sales contracts that settle at WTI Houston MEH prices; • NYMEX HH and Inside FERC West Texas (“IF Waha”) for a portion of its Midland Basin gas production with sales contracts that settle at IF Waha prices; and • NYMEX HH and Inside FERC Houston Ship Channel (“IF HSC”) for a portion of its South Texas gas production with sales contracts that settle at IF HSC prices. The Company has also entered into oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price differential. The weighted-average fixed price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts. As of December 31, 2023, the Company had commodity derivative contracts outstanding through the fourth quarter of 2025 as summarized in the table below: Contract Period First Quarter Second Quarter Third Quarter Fourth Quarter 2024 2024 2024 2024 2025 Oil Derivatives (volumes in MBbl and prices in $ per Bbl): Swaps ICE Brent Volumes 910 — — — — Weighted-Average Contract Price $ 85.50 $ — $ — $ — $ — Collars NYMEX WTI Volumes 795 1,846 1,669 556 — Weighted-Average Floor Price $ 68.21 $ 67.46 $ 68.93 $ 72.86 $ — Weighted-Average Ceiling Price $ 82.37 $ 85.53 $ 84.00 $ 79.83 $ — Basis Swaps WTI Midland-NYMEX WTI Volumes 1,199 1,193 1,235 1,230 1,807 Weighted-Average Contract Price $ 1.21 $ 1.21 $ 1.21 $ 1.21 $ 1.15 WTI Houston MEH-NYMEX WTI Volumes 256 293 332 309 729 Weighted-Average Contract Price $ 1.83 $ 1.82 $ 1.82 $ 1.82 $ 1.85 Roll Differential Swaps NYMEX WTI Volumes 1,415 1,792 1,964 1,877 — Weighted-Average Contract Price $ 0.57 $ 0.57 $ 0.57 $ 0.57 $ — Gas Derivatives (volumes in BBtu and prices in $ per MMBtu): Swaps NYMEX HH Volumes — 4,186 1,393 — 5,891 Weighted-Average Contract Price $ — $ 3.17 $ 3.39 $ — $ 4.20 Collars NYMEX HH Volumes 8,382 4,432 4,612 5,716 13,217 Weighted-Average Floor Price $ 3.57 $ 3.69 $ 3.68 $ 3.48 $ 3.44 Weighted-Average Ceiling Price $ 7.82 $ 4.00 $ 4.21 $ 5.24 $ 5.06 Basis Swaps IF Waha-NYMEX HH Volumes 5,089 5,285 5,344 5,240 20,501 Weighted-Average Contract Price $ (0.61) $ (1.09) $ (0.99) $ (0.73) $ (0.66) IF HSC-NYMEX HH Volumes 4,957 3,310 3,426 5,750 — Weighted-Average Contract Price $ (0.01) $ (0.34) $ (0.30) $ (0.38) $ — NGL Derivatives (volumes in MBbl and prices in $ per Bbl): Swaps OPIS Propane Mont Belvieu Non-TET Volumes 62 65 68 70 — Weighted-Average Contract Price $ 28.56 $ 28.56 $ 28.56 $ 28.56 $ — Commodity Derivative Contracts Entered Into Subsequent to December 31, 2023 Subsequent to December 31, 2023, and through the filing of this report, the Company entered into the following commodity derivative contracts: Contract Period First Quarter Second Quarter Third Quarter Fourth Quarter 2024 2024 2024 2024 2025 2026 Oil Derivatives (volumes in MBbl and prices in $ per Bbl): Swaps NYMEX WTI Volumes — — — 344 — — Weighted-Average Contract Price $ — $ — $ — $ 71.00 $ — $ — Collars NYMEX WTI Volumes — — 335 344 — — Weighted-Average Floor Price $ — $ — $ 65.00 $ 65.00 $ — $ — Weighted-Average Ceiling Price $ — $ — $ 78.61 $ 76.45 $ — $ — Basis Swaps WTI Midland-NYMEX WTI Volumes — — — — 941 — Weighted-Average Contract Price $ — $ — $ — $ — $ 1.15 $ — WTI Houston MEH-NYMEX WTI Volumes — — — — 684 816 Weighted-Average Contract Price $ — $ — $ — $ — $ 1.95 $ 2.10 Gas Derivatives (volumes in BBtu and prices in $ per MMBtu): Swaps NYMEX HH Volumes — — 1,530 — — — Weighted-Average Contract Price $ — $ — $ 2.99 $ — $ — $ — Collars NYMEX HH Volumes — — — 1,612 4,838 — Weighted-Average Floor Price $ — $ — $ — $ 3.00 $ 3.00 $ — Weighted-Average Ceiling Price $ — $ — $ — $ 4.02 $ 4.22 $ — Basis Swaps IF HSC-NYMEX HH Volumes — — — — 946 — Weighted-Average Contract Price $ — $ — $ — $ — $ 0.0025 $ — NGL Derivatives (volumes in MBbl and prices in $ per Bbl): Swaps OPIS Propane Mont Belvieu Non-TET Volumes 254 322 336 364 396 — Weighted-Average Contract Price $ 32.33 $ 32.57 $ 32.54 $ 32.49 $ 32.86 $ — OPIS Normal Butane Mont Belvieu Non-TET Volumes 28 44 46 49 45 — Weighted-Average Contract Price $ 39.48 $ 39.48 $ 39.48 $ 39.48 $ 39.48 $ — OPIS Isobutane Mont Belvieu Non-TET Volumes 15 24 25 28 25 — Weighted-Average Contract Price $ 41.58 $ 41.58 $ 41.58 $ 41.58 $ 41.58 $ — Derivative Assets and Liabilities Fair Value The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. The fair value of the commodity derivative contracts at December 31, 2023, and 2022, was a net asset of $57.1 million and $15.8 million, respectively. The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category: As of December 31, 2023 As of December 31, 2022 (in thousands) Derivative assets: Current assets $ 56,442 $ 48,677 Noncurrent assets 8,672 24,465 Total derivative assets $ 65,114 $ 73,142 Derivative liabilities: Current liabilities $ 6,789 $ 56,181 Noncurrent liabilities 1,273 1,142 Total derivative liabilities $ 8,062 $ 57,323 Offsetting of Derivative Assets and Liabilities As of December 31, 2023, and 2022, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets. The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts: Derivative Assets as of Derivative Liabilities as of December 31, December 31, December 31, December 31, (in thousands) Gross amounts presented in the accompanying balance sheets $ 65,114 $ 73,142 $ (8,062) $ (57,323) Amounts not offset in the accompanying balance sheets (7,362) (26,136) 7,362 26,136 Net amounts $ 57,752 $ 47,006 $ (700) $ (31,187) The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring such amounts in accumulated other comprehensive loss. The Company had no commodity derivative contracts designated as hedging instruments for the years ended December 31, 2023, 2022, and 2021. Please refer to Note 8 – Fair Value Measurements for more information regarding the Company’s derivative instruments, including its valuation techniques. The following table summarizes the commodity components of the net derivative settlement (gain) loss, and the net derivative (gain) loss line items presented within the accompanying statements of cash flows and the accompanying statements of operations, respectively: For the Years Ended December 31, 2023 2022 2021 (in thousands) Net derivative settlement (gain) loss: Oil contracts $ 26,873 $ 514,641 $ 523,245 Gas contracts (49,156) 171,598 152,361 NGL contracts (4,638) 24,461 73,352 Total net derivative settlement (gain) loss: $ (26,921) $ 710,700 $ 748,958 Net derivative (gain) loss: Oil contracts $ (20,813) $ 284,863 $ 650,959 Gas contracts (42,713) 82,769 172,248 NGL contracts (4,628) 6,380 78,452 Total net derivative (gain) loss: $ (68,154) $ 374,012 $ 901,659 Credit Related Contingent Features As of December 31, 2023, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. The Company does not enter into derivative contracts with counterparties that are not part of the lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value Disclosures | Note 8 – Fair Value Measurements The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: • Level 1 – quoted prices in active markets for identical assets or liabilities • Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable • Level 3 – significant inputs to the valuation model are unobservable The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy: As of December 31, 2023 As of December 31, 2022 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 65,114 $ — $ — $ 73,142 $ — Liabilities: Derivatives (1) $ — $ 8,062 $ — $ — $ 57,323 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on the Company’s policies for determining fair value for the categories discussed below. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivative instruments. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. Please refer to Note 7 – Derivative Financial Instruments for more information regarding the Company’s derivative instruments. Oil and Gas Properties and Other Property and Equipment The Company had no assets included in total property and equipment, net, measured at fair value as of December 31, 2023, or 2022. No impairment expense was recorded for the year ended December 31, 2023. Impairment expense for the years ended December 31, 2022, and 2021, was $7.5 million and $35.0 million, respectively, and consisted of unproved property abandonments and impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of December 31, 2023, and 2022, are recorded at carrying value. Please refer to Note 1 – Summary of Significant Accounting Policies for information on the Company’s policies for determining fair value of its oil and gas producing properties and related impairment expense. Long-Term Debt The following table reflects the fair value of the Company’s Senior Notes obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2023, or 2022, as they were recorded at carrying value, net of any unamortized deferred financing costs. Please refer to Note 5 – Long-Term Debt for additional information. As of December 31, 2023 2022 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 5.625% Senior Notes due 2025 $ 349,118 $ 348,189 $ 349,118 $ 337,821 6.75% Senior Notes due 2026 $ 419,235 $ 420,660 $ 419,235 $ 409,484 6.625% Senior Notes due 2027 $ 416,791 $ 416,549 $ 416,791 $ 402,120 6.5% Senior Notes due 2028 $ 400,000 $ 401,372 $ 400,000 $ 384,520 |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Note 9 – Earnings Per Share Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. For the years ended December 31, 2023, 2022, and 2021, potentially dilutive securities for this calculation consisted primarily of non-vested RSUs, contingent PSUs, and Warrants, all of which were measured using the treasury stock method. The Warrants became exercisable at the election of the holders on January 15, 2021, and all of the Warrants were exercised prior to their expiration date of June 30, 2023. The Warrants were included as potentially dilutive securities on an adjusted weighted-average basis for the portions of the years ended December 31, 2023, 2022, and 2021, during which they were outstanding but not yet exercised. Please refer to Note 3 – Equity for additional detail regarding the terms of the Warrants. PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three Note 10 – Compensation Plans under the heading Performance Share Units . The following table sets forth the calculations of basic and diluted net income per common share: For the Years Ended December 31, 2023 2022 2021 (in thousands, except per share data) Net income $ 817,880 $ 1,111,952 $ 36,229 Basic weighted-average common shares outstanding 118,678 122,351 119,043 Dilutive effect of non-vested RSUs, contingent PSUs, and other 553 1,714 2,582 Dilutive effect of Warrants 9 19 2,065 Diluted weighted-average common shares outstanding 119,240 124,084 123,690 Basic net income per common share $ 6.89 $ 9.09 $ 0.30 Diluted net income per common share $ 6.86 $ 8.96 $ 0.29 |
Compensation Plans
Compensation Plans | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Compensation Plans | Note 10 – Compensation Plans The Company may grant various types of both short-term and long-term incentive-based awards under its compensation plans, such as cash awards, performance-based cash awards, and equity awards to eligible employees. Additionally, the Company grants stock-based compensation to its Board of Directors, and provides an employee stock purchase plan and a 401(k) plan to eligible employees. As of December 31, 2023, approximately 2.8 million shares of common stock were available for grant under the Equity Plan. The issuance of a direct share benefit, such as a share of common stock, a stock option, a restricted share, an RSU or a PSU, counts as one share against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as two shares against the number of shares available to be granted under the Equity Plan based on the final performance multiplier. Performance Share Units The Company has granted PSUs to eligible employees as part of its Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain criteria over a three three The fair value of PSUs is measured at the grant date using a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for each iteration. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three For PSUs granted in 2023 and 2022, which the Company determined to be equity awards, settlement will be determined based on a combination of the following criteria measured over the three The Company initially records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the grant date and may adjust compensation expense in future periods as discussed above. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for PSUs was $2.8 million, $2.6 million, and $6.0 million for the years ended December 31, 2023, 2022, and 2021, respectively. As of December 31, 2023, there was $8.6 million of total unrecognized expense related to non-vested PSUs, which is being amortized through mid-2026. The fair value of PSUs granted in 2023 and 2022 was $7.7 million and $7.4 million, respectively. The fair value of PSUs that vested during the years ended December 31, 2022, and 2021, was $12.3 million and $8.4 million, respectively. A summary of activity is presented in the following table: For the Years Ended December 31, 2023 2022 2021 PSUs (1) Weighted-Average Grant-Date Fair Value (2) PSUs (1) Weighted-Average Grant-Date Fair Value (2) PSUs (1) Weighted-Average Grant-Date Fair Value (2) Non-vested at beginning of year 273,258 $ 26.67 464,483 $ 12.80 830,464 $ 17.52 Granted 256,633 $ 29.93 276,010 $ 26.67 — $ — Vested (15,950) $ 25.50 (461,387) $ 12.81 (352,395) $ 23.81 Forfeited (44,509) $ 26.45 (5,848) $ 18.24 (13,586) $ 15.46 Non-vested at end of year 469,432 $ 27.83 273,258 $ 26.67 464,483 $ 12.80 ____________________________________________ (1) The number of PSUs presented assumes a multiplier of one. The actual final number of shares of common stock to be issued at the end of the three three (2) Amounts represent price per unit. A summary of the shares of common stock issued to settle PSUs is presented in the table below: For the Years Ended December 31, 2022 2021 Shares of common stock issued to settle PSUs (1) 1,004,410 347,742 Less: shares of common stock withheld for income and payroll taxes (349,487) (112,919) Net shares of common stock issued 654,923 234,823 Multiplier earned 2.0 1.0 ____________________________________________ (1) During the year ended December 31, 2023, there were no shares of common stock issued to settle PSUs. During the years ended December 31, 2022, and 2021, the Company settled PSUs that were granted in 2019 and 2018, respectively. The Company and all eligible recipients in 2022 and 2021 mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. Employee Restricted Stock Units The Company has granted RSUs to eligible employees as part of its Equity Plan. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest in one-third increments on each anniversary of the applicable grant date over the applicable vesting period or upon other triggering events as set forth in the Equity Plan. Employees who meet retirement eligibility criteria, as defined by the applicable grant agreement, at the time an RSU award is granted generally vest in six six The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the grant date. The fair value of an RSU is equal to the closing price of the Company’s common stock on the grant date. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for RSUs for the years ended December 31, 2023, 2022, and 2021, was $14.8 million, $13.5 million, and $10.2 million, respectively. As of December 31, 2023, there was $25.7 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through mid-2026. The fair value of RSUs granted to eligible employees in 2023, 2022 and 2021, was $20.2 million, $18.0 million, and $17.0 million, respectively, and the fair value of RSUs that vested during the years ended December 31, 2023, 2022, and 2021, was $13.5 million, $11.2 million, and $9.3 million, respectively. A summary of activity is presented in the following table: For the Years Ended December 31, 2023 2022 2021 RSUs Weighted- Average Grant-Date Fair Value (1) RSUs Weighted- Average Grant-Date Fair Value (1) RSUs Weighted- Average Grant-Date Fair Value (1) Non-vested at beginning of year 1,375,052 $ 22.42 1,841,237 $ 13.79 2,097,860 $ 8.83 Granted 630,474 $ 32.03 526,776 $ 34.08 666,052 $ 25.52 Vested (805,205) $ 16.75 (920,927) $ 12.17 (843,098) $ 11.00 Forfeited (119,777) $ 29.26 (72,034) $ 18.24 (79,577) $ 10.64 Non-vested at end of year 1,080,544 $ 31.49 1,375,052 $ 22.42 1,841,237 $ 13.79 ____________________________________________ (1) Amounts represent price per unit. A summary of the shares of common stock issued to settle RSUs is presented in the table below: For the Years Ended December 31, 2023 2022 2021 Shares of common stock issued to settle RSUs (1) 803,449 920,927 843,098 Less: shares of common stock withheld for income and payroll taxes (249,233) (284,423) (250,349) Net shares of common stock issued 554,216 636,504 592,749 ____________________________________________ (1) During the years ended December 31, 2023, 2022, and 2021, the Company issued shares of common stock to settle RSUs that related to awards granted in previous years. The Company and a majority of eligible recipients in 2023, and all eligible recipients in 2022 and 2021, mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. Director Shares In 2023, 2022, and 2021, the Company issued a total of 56,872, 29,471, and 60,510 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. For the years ended December 31, 2023, 2022, and 2021, the Company recorded $1.6 million, $1.5 million, and $1.2 million, respectively, of compensation expense related to director shares. All shares issued to non-employee directors fully vested on December 31 of the year granted. Employee Stock Purchase Plan Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible compensation, subject to a maximum of 2,500 shares per offering period and a maximum of $25,000 in value related to purchases for each calendar year. The purchase price of the common stock is 85 percent of the lower of the trading price of the common stock on either the first or last day of the six-month offering period. The ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the IRC. A total of 114,427, 113,785, and 313,773 shares were issued under the ESPP in 2023, 2022, and 2021, respectively. Total proceeds to the Company for the issuance of these shares was $3.1 million, $3.0 million, and $2.6 million, for the years ended December 31, 2023, 2022, and 2021, respectively. As of December 31, 2023, the Company had approximately 3.3 million shares of its common stock available for issuance under the ESPP. The Company records compensation expense associated with the ESPP based on the estimated fair value of the ESPP grants as of the beginning of the offering period, and the expense is recognized within general and administrative expense and exploration expense over the six-month offering period. Total compensation expense recorded for the ESPP for the years ended December 31, 2023, 2022, and 2021, was $1.1 million, $1.2 million, and $1.4 million, respectively. The fair value of ESPP grants is measured at the grant date using the Black-Scholes option-pricing model. Expected volatility is calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six-month vesting period. The fair value of ESPP shares issued during the periods reported above were estimated using the following weighted-average assumptions: For the Years Ended December 31, 2023 2022 2021 Risk free interest rate 5.1 % 1.2 % 0.8 % Dividend yield 1.8 % 0.1 % 0.3 % Volatility factor of the expected market price of the Company’s common stock 53.6 % 69.1 % 106.1 % Expected life (in years) 0.5 0.5 0.5 401(k) Plan The Company has a defined contribution plan (“401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. The Company matches either 100 percent or 150 percent of each employee’s contributions, depending on pension plan eligibility, up to six percent of the employee’s base salary and short-term incentive bonus, and may make additional contributions at its discretion. Please refer to Note 11 – Pension Benefits for additional discussion of pension benefits. The Company’s matching contributions to the 401(k) Plan were $5.7 million, $5.5 million, and $3.9 million for the years ended December 31, 2023, 2022, and 2021, respectively. |
Pension Benefits
Pension Benefits | 12 Months Ended |
Dec. 31, 2023 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | |
Pension Benefits | Note 11 – Pension Benefits The Company has a non-contributory defined benefit pension plan covering employees who met age and service requirements and began employment with the Company prior to January 1, 2016 (“Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (“Nonqualified Pension Plan” and together with the Qualified Pension Plan, “Pension Plans”). The Company froze the Pension Plans to new participants, effective January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen continue to earn benefits. Obligations and Funded Status for the Pension Plans The Company recognizes the funded status (i.e., the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment within the other comprehensive income, net of tax, line item in the accompanying consolidated statements of comprehensive income. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. For the Years Ended December 31, 2023 2022 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 65,161 $ 75,760 Service cost 3,706 4,652 Interest cost 3,200 2,314 Actuarial (gain) loss 84 (15,567) Benefits paid (4,883) (1,998) Projected benefit obligation at end of year 67,268 65,161 Change in plan assets: Fair value of plan assets at beginning of year 36,414 35,941 Actual return on plan assets 4,161 (3,529) Employer contribution 10,000 6,000 Benefits paid (4,883) (1,998) Fair value of plan assets at end of year 45,692 36,414 Funded status at end of year $ (21,576) $ (28,747) The Company’s underfunded status for the Pension Plans as of December 31, 2023, and 2022, was $21.6 million and $28.7 million, respectively, and is recognized in the accompanying balance sheets within the other noncurrent liabilities line item. There are no plan assets in the Nonqualified Pension Plan. Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2023 2022 (in thousands) Projected benefit obligation $ 67,268 $ 65,161 Accumulated benefit obligation $ 55,557 $ 55,712 Less: fair value of plan assets (45,692) (36,414) Underfunded accumulated benefit obligation $ 9,865 $ 19,298 Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of the unrecognized net gain or loss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for the year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan. The pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in the accumulated other comprehensive loss line item within the accompanying balance sheets as of December 31, 2023, and 2022, totaled $3.3 million and $5.1 million, respectively, and related to unrecognized actuarial losses. The pension liability adjustments recognized in other comprehensive income during 2023, 2022, and 2021, were as follows: For the Years Ended December 31, 2023 2022 2021 (in thousands) Net actuarial gain (loss) $ 1,737 $ 10,327 $ (612) Amortization of prior service cost — — 13 Amortization of net actuarial loss 68 931 1,240 Settlements — — 312 Total pension liability adjustment, pre-tax 1,805 11,258 953 Tax expense (390) (2,431) (204) Total pension liability adjustment, net $ 1,415 $ 8,827 $ 749 Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2023 2022 2021 (in thousands) Components of net periodic benefit cost: Service cost $ 3,706 $ 4,652 $ 4,455 Interest cost 3,200 2,314 2,089 Expected return on plan assets that reduces periodic pension benefit cost (2,340) (1,711) (1,474) Amortization of prior service cost — — 13 Amortization of net actuarial loss 68 931 1,240 Net periodic benefit cost 4,634 6,186 6,323 Settlements — — 312 Total net benefit cost $ 4,634 $ 6,186 $ 6,635 Pension Plan Assumptions The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows: As of December 31, 2023 2022 Projected benefit obligation: Discount rate 5.0% 5.2% Rate of compensation increase 3.5% 3.5% The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows: For the Years Ended December 31, 2023 2022 2021 Net periodic benefit cost: Discount rate 5.2% 3.1% 2.9% Expected return on plan assets (1) 6.3% 3.6% 4.4% Rate of compensation increase 3.5% 4.8% 4.4% ____________________________________________ (1) There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan. The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy prohibits the direct investment of plan assets in the Company’s securities. The Qualified Pension Plan’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting of expected returns for given levels of risk are applied. The Qualified Pension Plan’s investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations. The weighted-average asset allocation of the Qualified Pension Plan is as follows: Target As of December 31, Asset Category 2024 2023 2022 Equity securities 49.0 % 43.0 % 47.1 % Fixed income securities 26.0 % 25.5 % 21.0 % Other securities 25.0 % 31.5 % 31.9 % Total 100.0 % 100.0 % 100.0 % There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in the plan. The assumption of the expected long-term rate of return on plan assets of the Qualified Pension Plan is based upon the target asset allocation and is determined using forward-looking assumptions in the context of historical returns and volatilities for each asset class, as well as correlations among asset classes. The Company evaluates the expected rate of return on plan assets assumption on an annual basis. Pension Plan Assets The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2023, and 2022, utilizing the fair value hierarchy discussed in Note 8 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual Asset Allocation (1) Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (in thousands) As of December 31, 2023 Equity securities: Domestic (2) 20.3 % $ 9,280 $ 6,097 $ 3,183 $ — International (3) 22.7 % 10,349 10,349 — — Total equity securities 43.0 % 19,629 16,446 3,183 — Fixed income securities: Core fixed income (4) 25.5 % 11,646 11,646 — — Floating rate corporate loans (5) — % — — — — Total fixed income securities 25.5 % 11,646 11,646 — — Other securities: Real estate (6) 4.6 % 2,116 — — 2,116 Collective investment trusts (7) 13.6 % 6,206 — 6,206 — Hedge fund (8) 13.3 % 6,095 1,498 — 4,597 Total other securities 31.5 % 14,417 1,498 6,206 6,713 Total investments 100.0 % $ 45,692 $ 29,590 $ 9,389 $ 6,713 As of December 31, 2022 Equity securities: Domestic (2) 20.7 % $ 7,533 $ 5,012 $ 2,521 $ — International (3) 26.4 % 9,594 9,594 — — Total equity securities 47.1 % 17,127 14,606 2,521 — Fixed income securities: Core fixed income (4) 14.3 % 5,220 5,220 — — Floating rate corporate loans (5) 6.7 % 2,450 2,450 — — Total fixed income securities 21.0 % 7,670 7,670 — — Other securities: Real estate (6) 6.8 % 2,476 — — 2,476 Collective investment trusts (7) 1.9 % 687 — 687 — Hedge fund (8) 23.2 % 8,454 4,133 — 4,321 Total other securities 31.9 % 11,617 4,133 687 6,797 Total investments 100.0 % $ 36,414 $ 26,409 $ 3,208 $ 6,797 ____________________________________________ (1) Percentages may not calculate due to rounding. (2) Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold on demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective investment funds. (3) International equity securities consist of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets that are believed to have strong sustainable financial productivity at attractive valuations. (4) The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. (5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. (6) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. (7) Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. (8) The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. The following is a summary of the changes in Level 3 plan assets (in thousands): Balance at January 1, 2022 $ 6,195 Purchases 400 Realized gain on assets 259 Unrealized loss on assets (57) Disposition — Balance at December 31, 2022 $ 6,797 Purchases — Realized gain on assets 364 Unrealized loss on assets (448) Disposition — Balance at December 31, 2023 $ 6,713 Contributions The Company contributed $10.0 million, $6.0 million, and $6.6 million to the Pension Plans for the years ended December 31, 2023, 2022, and 2021, respectively. The Company expects to make a $10.6 million contribution to the Pension Plans in 2024. Benefit Payments The Pension Plans made actual benefit payments of $4.9 million, $2.0 million, and $6.3 million for the years ended December 31, 2023, 2022, and 2021, respectively. Expected benefit payments over the next 10 years are as follows: For the Years Ending December 31, Amount (in thousands) 2024 $ 6,865 2025 $ 4,455 2026 $ 7,064 2027 $ 5,026 2028 $ 5,281 2029 through 2033 $ 25,587 |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
Lessee Disclosure [Abstract] | |
Leases | Note 12 – Leases As of December 31, 2023, and 2022, the Company had operating leases for asset classes that include office space, office equipment, drilling rigs, midstream agreements, vehicles, and equipment rentals used in field operations. For operating leases recorded on the accompanying balance sheets, remaining lease terms range from less than one year to approximately nine years. Certain leases contain optional extension periods that allow for terms to be extended for up to an additional 10 years, however in order to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. An early termination option exists for certain leases, some of which allow the Company to terminate a lease within one year, however, there are no leases in which material early termination options are reasonably certain to be exercised by the Company. As of December 31, 2023, and 2022, the Company did not have any agreements in place that were classified as finance leases under Topic 842. As of December 31, 2023, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future. Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on the Company’s policies for lease determination and classification. The following table reflects the components of the Company’s total lease costs, whether capitalized or expensed, related to operating leases, including short-term leases, and variable lease payments made for both short-term and long-term leases for the years ended December 31, 2023, and 2022. This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. For the Years Ended December 31, 2023 2022 (in thousands) Operating lease cost $ 15,625 $ 10,174 Short-term lease cost (1) 251,628 175,098 Variable lease cost (2) 11,838 7,085 Total lease cost $ 279,091 $ 192,357 ____________________________________________ (1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements. (2) Variable lease payments relate to the actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are primarily driven by the number of drilling rigs and completion crews operating. Cash paid for amounts included in the measurement of lease liabilities for the years ended December 31, 2023, and 2022, were as follows: For the Years Ended December 31, 2023 2022 (in thousands) Operating cash flows related to operating leases $ 4,181 $ 4,718 Investing cash flows related to operating leases $ 11,300 $ 5,042 Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2023, were as follows: As of December 31, 2023 (in thousands) 2024 $ 17,208 2025 11,242 2026 4,793 2027 2,685 2028 2,054 Thereafter 6,906 Total Lease payments $ 44,888 Less: Imputed interest (1) (5,110) Total $ 39,778 ____________________________________________ (1) The weighted-average discount rate used to determine the operating lease liability as of December 31, 2023, was 6.2 percent. The following table presents supplemental accompanying balance sheet information for operating leases as of December 31, 2023, and 2022: As of December 31, 2023 2022 (in thousands, except discount rate and lease term) Balance sheet classifications of operating leases: Other noncurrent assets $ 32,264 $ 26,368 Other current liabilities $ 15,425 $ 10,114 Other noncurrent liabilities $ 24,352 $ 23,621 ROU assets obtained in exchange for operating lease liabilities $ 19,341 $ 16,186 Weighted-average discount rate 6.2% 5.8% Weighted-average remaining lease term (years) 4 5 |
Accounts Receivable and Account
Accounts Receivable and Accounts Payable and Accrued Expenses | 12 Months Ended |
Dec. 31, 2023 | |
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract] | |
Accounts Receivable and Accounts Payable and Accrued Expenses | Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses The components of accounts receivable are as follows: As of December 31, 2023 2022 (in thousands) Oil, gas, and NGL production revenue $ 175,334 $ 184,458 Amounts due from joint interest owners 46,289 45,997 Other 9,542 2,842 Total accounts receivable $ 231,165 $ 233,297 The components of accounts payable and accrued expenses are as follows: As of December 31, 2023 2022 (in thousands) Drilling and lease operating cost accruals $ 144,707 $ 125,570 Trade accounts payable 107,315 43,898 Revenue and severance tax payable 186,663 182,744 Property taxes 43,406 43,066 Compensation 54,819 35,799 Net derivative settlements 1,129 22,745 Interest 35,976 35,992 Dividends payable 20,834 18,290 Other 16,749 24,185 Total accounts payable and accrued expenses $ 611,598 $ 532,289 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Note 14 – Asset Retirement Obligations Please refer to Asset Retirement Obligations in Note 1 – Summary of Significant Accounting Policies for a discussion of the initial and subsequent measurements of asset retirement obligation liabilities and the significant assumptions used in the estimates. The following is a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2023, and 2022: As of December 31, 2023 2022 (in thousands) Beginning asset retirement obligations $ 115,313 $ 101,424 Liabilities incurred (1) 4,062 2,086 Liabilities settled (2) (4,489) (6,356) Accretion expense 6,330 5,344 Revision to estimated cash flows 1,938 12,815 Ending asset retirement obligations (3) $ 123,154 $ 115,313 ____________________________________________ (1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. (2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. (3) Balances as of December 31, 2023, and 2022, included $4.4 million and $7.1 million, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets. |
Suspended Well Costs
Suspended Well Costs | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
Suspended Well Costs | Note 15 – Suspended Well Costs The following table reflects the net changes in capitalized exploratory well costs during 2023, 2022, and 2021. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: For the Years Ended December 31, 2023 2022 2021 (in thousands) Beginning balance $ 49,047 $ 15,576 $ 5,698 Additions to capitalized exploratory well costs pending the determination of net proved reserves 70,762 49,047 15,576 Reclassifications based on the determination of net proved reserves (47,985) (14,721) (5,698) Capitalized exploratory well costs charged to expense (1) (455) (855) — Ending balance $ 71,369 $ 49,047 $ 15,576 ____________________________________________ (1) For the year ended December 31, 2023, amount relates to one well that experienced technical issues during the drilling phase. For the year ended December 31, 2022, amount relates to unsuccessful exploration activity outside of the Company’s core areas of operation. As of December 31, 2023, there were no material exploratory well costs that were capitalized for more than one year. |
Acquisitions, Divestitures, and
Acquisitions, Divestitures, and Assets Held for Sale | 12 Months Ended |
Dec. 31, 2023 | |
Asset Acquisition [Abstract] | |
Acquisitions, Divestitures, and Assets Held for Sale | Note 16 – Acquisitions On June 30, 2023, the Company acquired approximately 20,000 net acres of oil and gas properties in Dawson and northern Martin counties, Texas. Under authoritative accounting guidance, this transaction was considered to be an asset acquisition. Therefore, the properties were recorded based on the total consideration paid after purchase price adjustments and the transaction costs were capitalized as a component of the cost of the assets acquired. During the third quarter of 2023, the Company acquired additional working interests in certain wells. Total consideration paid for these transactions, after purchase price adjustments, was $109.9 million. Additionally, during the year ended December 31, 2023, the Company completed a non-monetary asset exchange of proved properties in Upton County, Texas. This exchange was recorded at carryover basis with no gain or loss recognized. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Basis of Presentation [Policy Text Block] | Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the accompanying consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2023, through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements. |
Use of Estimates in the Preparation of the Financial Statements [Policy Text Block] | Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of DD&A expense, impairment of proved and unproved oil and gas properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements. |
Cash and Cash Equivalents [Policy Text Block] | Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. |
Accounts Receivable [Policy Text Block] | Accounts Receivable The Company’s accounts receivable primarily consist of receivables due from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had minimal bad debts. Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. Please refer to Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses for additional disclosure. |
Concentration of Credit Risk and Major Customers [Policy Text Block] | Concentration of Credit Risk and Major Customers The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is regularly reviewed. The Company does not believe the loss of any single purchaser of its production would materially affect its operating results, as oil, gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating areas. The following major customers and entities under common control accounted for 10 percent or more of the Company’s total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2023 2022 2021 Major customer #1 24 % 24 % 27 % Major customer #2 11 % 7 % 9 % Major customer #3 6 % 8 % 15 % Group #1 of entities under common control 22 % 24 % 18 % For its commodity derivative instruments, the Company’s policy is to only enter into contracts with affiliates of the lenders under its Credit Agreement as its derivative counterparties, and each counterparty must have certain minimum investment grade senior unsecured debt ratings. The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operation. The Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment. |
Oil and Gas Producing Activities [Policy Text Block] | Proved properties . The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, property acquisition costs and development costs are capitalized when incurred. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated net proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same asset group basis; however, the units-of-production method is based on estimated total net proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. |
Oil and Gas Properties Costs [Policy Text Block] | Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated net proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same asset group basis; however, the units-of-production method is based on estimated total net proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Proved oil and gas property costs are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties . The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on an asset group basis, neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the accompanying statements of operations in the amount of such excess. |
Property, Plant and Equipment, Impairment [Policy Text Block] | Proved oil and gas property costs are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties . The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. |
Exploratory [Policy Text Block] | Exploratory . Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting for oil and gas properties, exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows. Please refer to Note 8 – Fair Value Measurements for additional information. |
Other Property and Equipment [Policy Text Block] | Other Property and Equipment Other property and equipment such as facilities, equipment inventory, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three Facilities and equipment inventory costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of facilities and equipment inventory, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. For facilities, the valuation includes consideration of the proved and unproved assets supported by the facilities, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. |
Asset Retirement Obligations [Policy Text Block] | Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, changes in inflation factors, or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 14 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2023, and 2022. |
Derivatives Financial Instruments [Policy Text Block] | Derivative Financial Instruments The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials for its expected future oil, gas, and NGL production, and the associated effect on cash flows. These instruments typically include commodity price swaps and collar arrangements, as well as, basis swaps and roll differential swaps. Commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on net derivative settlements are included within the cash flows from operating activities section of the accompanying statements of cash flows. Please refer to Note 7 – Derivative Financial Instruments for additional discussion. |
Revenue Recognition [Policy Text Block] | Revenue Recognition The Company derives revenue predominately from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. The Company uses knowledge of its properties, contractual arrangements, historical performance, NYMEX, local spot market, and OPIS prices, and other factors as the basis of these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received. Please refer to Note 2 – Revenue from Contracts with Customers for additional discussion. |
Stock-based Compensation [Policy Text Block] | Stock-Based Compensation At December 31, 2023, the Company had stock-based employee compensation plans that included RSUs and Performance Share Units (“PSU or “PSUs”) issued to employees, RSUs and restricted stock issued to non-employee directors, and an employee stock purchase plan available to eligible employees. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur. Please refer to Note 10 – Compensation Plans for additional discussion . |
Income Taxes [Policy Text Block] | Income Taxes The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the accompanying consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. The cumulative effect of enacted tax rate changes on the net balance of reported amounts of assets and liabilities is recognized in the period of enactment. The Company’s policy is to record interest related to income taxes in the interest expense line item in the accompanying statements of operations, and to record penalties related to income taxes in the other non-operating expense line item in the accompanying statements of operations. Please refer to Note 4 – Income Taxes for additional discussion. |
Earnings Per Share [Policy Text Block] | Earnings per Share The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Please refer to Note 9 – Earnings Per Share for additional discussion. |
Comprehensive Income (Loss) [Policy Text Block] | Comprehensive Income (Loss) Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that, under GAAP, are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. Please refer to Note 11 – Pension Benefits for detail on the changes in the balances of components comprising other comprehensive income. |
Fair Value of Financial Instruments [Policy Text Block] | Fair Value of Financial Instruments The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt , are recorded at cost, net of unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurements. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivative instruments. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. |
Leases [Policy Text Block] | Leases The Company accounts for leases in accordance with ASC Topic 842, Leases , (“Topic 842”), which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component. Certain leases may contain both lease and non-lease components. The Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include those to determine the discount rate and lease term. Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a right-of-use (“ROU”) asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Exercising an early termination option may result in an early termination penalty depending on the terms of the underlying agreement. The Company excludes from the balance sheet leases with terms that are less than one year. An ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of an ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance. Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. As discussed above, excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. Please refer to Note 12 – Leases for additional discussion. |
Industry Segment and Geographic Information [Policy Text Block] | Industry Segment and Geographic Information The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a single industry segment. |
Off-Balance Sheet Arrangements [Policy Text Block] | Off-Balance Sheet Arrangements The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated into the Company’s consolidated financial statements. The Company has not been involved in any unconsolidated SPE transactions during 2023 or 2022, or through the filing of this report. |
Recently Issued Accounting Standards [Policy Text Block] | Recently Issued Accounting Standards In October 2023, the FASB issued ASU No. 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative (“ASU 2023-06”). ASU 2023-06 was issued to modify the disclosure or presentation requirements of a variety of topics in the codification. The effective date for each amendment will be the date on which the SEC’s removal of the related disclosure from Regulation S-X or Regulation S-K becomes effective, with early adoption prohibited. The Company evaluated ASU 2023-06 and does not expect the adoption of the applicable amendments to have a material effect on its consolidated financial statements and related disclosures. In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ( “ASU 2023-07” ). ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a retrospective basis to all prior periods presented in the financial statements. The Company is within the scope of this ASU and is evaluating the impact of this ASU on its consolidated financial statement disclosures. In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ( “ASU 2023-09” ). ASU 2023-09 was issued to improve the disclosures related to rate reconciliations and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The guidance should be applied on a prospective basis, however, retrospective application is permitted. The Company is within the scope of this ASU and is evaluating the impact of this ASU on its consolidated financial statement disclosures. As of the filing of this report, the Company has not elected to early adopt ASU 2023-07 or ASU 2023-09. As of December 31, 2023, and through the filing of this report, no other ASUs have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s consolidated financial statements and related disclosures. |
Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block] | The Company’s accounting policy is to not offset |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block] | The Company’s accounting policy is to not offset |
Fair Value Measures and Disclos
Fair Value Measures and Disclosures (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments [Policy Text Block] | Fair Value of Financial Instruments The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt , are recorded at cost, net of unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurements. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivative instruments. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. |
Compensation Related Costs, Pos
Compensation Related Costs, Postemployment Benefits (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Postemployment Benefits [Abstract] | |
Pension Benefits [Policy Text Block] | The Company recognizes the funded status (i.e., the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment within the other comprehensive income, net of tax, line item in the accompanying consolidated statements of comprehensive income. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Schedule of Major Customers | The following major customers and entities under common control accounted for 10 percent or more of the Company’s total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2023 2022 2021 Major customer #1 24 % 24 % 27 % Major customer #2 11 % 7 % 9 % Major customer #3 6 % 8 % 15 % Group #1 of entities under common control 22 % 24 % 18 % |
Revenue from Contracts with C_2
Revenue from Contracts with Customers (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of oil, gas, and NGL production revenue | The tables below present oil, gas, and NGL production revenue by product type for each of the Company’s operating areas for the years ended December 31, 2023, 2022, and 2021: For the year ended December 31, 2023 Midland Basin South Texas Total (in thousands) Oil production revenue $ 1,347,780 $ 465,995 $ 1,813,775 Gas production revenue 175,183 152,700 327,883 NGL production revenue 687 221,544 222,231 Total $ 1,523,650 $ 840,239 $ 2,363,889 Relative percentage 64 % 36 % 100 % For the year ended December 31, 2022 Midland Basin South Texas Total (in thousands) Oil production revenue $ 1,816,597 $ 453,471 $ 2,270,068 Gas production revenue 432,831 358,049 790,880 NGL production revenue 986 283,972 284,958 Total $ 2,250,414 $ 1,095,492 $ 3,345,906 Relative percentage 67 % 33 % 100 % For the year ended December 31, 2021 Midland Basin South Texas Total (in thousands) Oil production revenue $ 1,701,915 $ 189,911 $ 1,891,826 Gas production revenue 326,115 199,364 525,479 NGL production revenue 381 180,229 180,610 Total $ 2,028,411 $ 569,504 $ 2,597,915 Relative percentage 78 % 22 % 100 % |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Schedule of Stock Repurchase Activity | The following table presents the Company’s common stock repurchase activity for the years ended December 31, 2023, and 2022: For the Years Ended December 31, 2023 2022 (in thousands, except per share data) Shares of common stock repurchased (1) 6,931 1,365 Weighted-average price per share (2) $ 32.89 $ 41.88 Cost of shares of common stock repurchased (2) (3) $ 227,966 $ 57,179 ____________________________________________ (1) All repurchased shares of the Company’s common stock were retired upon repurchase. (2) Amounts exclude excise taxes, commissions, and fees. (3) Amounts may not calculate due to rounding. |
Schedule of Warrant Activity | The following table presents activity related to warrants exercised during the periods presented: For the Years Ended December 31, 2023 2022 2021 (in thousands, except per share data) Warrants exercised 19 — 5,922 Shares of common stock issued as a result of cashless exercise of warrants 19 — 5,918 Weighted-average share price on exercise date $ 29.09 $ — $ 15.45 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule of components of provision for income taxes | The provision for income taxes consisted of the following: For the Years Ended December 31, 2023 2022 2021 (in thousands) Current portion of income tax (expense) benefit Federal $ (8,461) $ (9,230) $ — State 395 (5,531) (373) Deferred portion of income tax expense (88,256) (269,057) (9,565) Income tax expense $ (96,322) $ (283,818) $ (9,938) Effective tax rate 10.5 % 20.3 % 21.5 % |
Schedule of components of net deferred income tax liabilities | The components of the net deferred tax liabilities are as follows: As of December 31, 2023 2022 (in thousands) Deferred tax liabilities: Oil and gas properties excluding asset retirement obligation liabilities $ 450,634 $ 358,537 Derivative assets 12,319 3,416 Other 6,283 6,059 Total deferred tax liabilities 469,236 368,012 Deferred tax assets: Credit carryover, net 56,097 161 Asset retirement obligation liabilities 26,592 24,899 Lease liabilities 4,454 4,525 Federal and state tax net operating loss carryovers 3,271 28,151 Legal liabilities 2,838 — Pension 2,453 3,970 Interest carryforward 1,031 22,667 Other 4,003 4,444 Total deferred tax assets 100,739 88,817 Valuation allowance (1,406) (1,616) Net deferred tax assets 99,333 87,201 Net deferred tax liabilities $ 369,903 $ 280,811 Current federal income tax refundable (payable) $ (4,899) $ 770 Current state income tax refundable (payable) $ 1,253 $ (5,316) |
Schedule of effective income tax rate reconciliation | Income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences primarily relate to the effect of federal tax credits, state income taxes, changes in valuation allowances, excess tax benefits and deficiencies from stock-based compensation awards, tax deduction limitations on compensation of covered individuals, the cumulative impact of other smaller permanent differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balances. These differences for the years ended December 31, 2023, 2022, and 2021, are presented below: For the Years Ended December 31, 2023 2022 2021 (in thousands) Federal statutory tax expense $ (191,983) $ (293,112) $ (9,695) (Increase) decrease in tax resulting from: Net federal R&D tax credit 92,420 — — Change in valuation allowance 210 16,845 (5,073) State tax (expense) benefit, net of federal effect 5,166 (9,870) (211) Other (2,135) 2,319 5,041 Income tax expense $ (96,322) $ (283,818) $ (9,938) |
Schedule of Unrecognized Tax Benefits Roll Forward | The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2023 2022 2021 (in thousands) Beginning balance $ 446 $ 446 $ 446 Additions based on tax positions related to current year 23,713 — — Ending balance $ 24,159 $ 446 $ 446 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Debt Instrument Borrowing Base Utilization | Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement, as presented in the table below. At the Company’s election, borrowings under the Credit Agreement may be in the form of SOFR, Alternate Base Rate (“ABR”), or Swingline loans. SOFR loans accrue interest at SOFR plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid. Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% SOFR Loans 2.000 % 2.250 % 2.500 % 2.750 % 3.000 % ABR Loans or Swingline Loans 1.000 % 1.250 % 1.500 % 1.750 % 2.000 % Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 % |
Schedule of Credit Agreement Facilities | The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of February 8, 2024, December 31, 2023, and December 31, 2022: As of February 8, 2024 As of December 31, 2023 As of December 31, 2022 (in thousands) Revolving credit facility (1) $ — $ — $ — Letters of credit (2) 2,500 2,500 6,000 Available borrowing capacity 1,247,500 1,247,500 1,244,000 Total aggregate lender commitment amount $ 1,250,000 $ 1,250,000 $ 1,250,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $8.5 million and $10.8 million as of December 31, 2023, and 2022, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis. |
Schedule of Long-term Debt Instruments [Table Text Block] | The Company’s Senior Notes, net line item on the accompanying balance sheets as of December 31, 2023, and 2022, consisted of the following (collectively referred to as “Senior Notes”): As of December 31, 2023 As of December 31, 2022 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net (in thousands) 5.625% Senior Notes due 2025 $ 349,118 $ 896 $ 348,222 $ 349,118 $ 1,528 $ 347,590 6.75% Senior Notes due 2026 419,235 1,868 417,367 419,235 2,569 416,666 6.625% Senior Notes due 2027 416,791 2,395 414,396 416,791 3,172 413,619 6.5% Senior Notes due 2028 400,000 4,651 395,349 400,000 5,665 394,335 Total $ 1,585,144 $ 9,810 $ 1,575,334 $ 1,585,144 $ 12,934 $ 1,572,210 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of contractual obligation, five years [Table Text Block] | The following table presents the annual minimum payments related to these agreements for the next five years, and the total minimum payments thereafter as of December 31, 2023: For the Years Ending December 31, Amount (in thousands) 2024 $ 74,992 2025 52,175 2026 28,133 2027 13,791 2028 12,461 Thereafter 14,655 Total $ 196,207 |
Derivative Financial Instrume_2
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |
Schedule of notional amounts of outstanding derivative positions | As of December 31, 2023, the Company had commodity derivative contracts outstanding through the fourth quarter of 2025 as summarized in the table below: Contract Period First Quarter Second Quarter Third Quarter Fourth Quarter 2024 2024 2024 2024 2025 Oil Derivatives (volumes in MBbl and prices in $ per Bbl): Swaps ICE Brent Volumes 910 — — — — Weighted-Average Contract Price $ 85.50 $ — $ — $ — $ — Collars NYMEX WTI Volumes 795 1,846 1,669 556 — Weighted-Average Floor Price $ 68.21 $ 67.46 $ 68.93 $ 72.86 $ — Weighted-Average Ceiling Price $ 82.37 $ 85.53 $ 84.00 $ 79.83 $ — Basis Swaps WTI Midland-NYMEX WTI Volumes 1,199 1,193 1,235 1,230 1,807 Weighted-Average Contract Price $ 1.21 $ 1.21 $ 1.21 $ 1.21 $ 1.15 WTI Houston MEH-NYMEX WTI Volumes 256 293 332 309 729 Weighted-Average Contract Price $ 1.83 $ 1.82 $ 1.82 $ 1.82 $ 1.85 Roll Differential Swaps NYMEX WTI Volumes 1,415 1,792 1,964 1,877 — Weighted-Average Contract Price $ 0.57 $ 0.57 $ 0.57 $ 0.57 $ — Gas Derivatives (volumes in BBtu and prices in $ per MMBtu): Swaps NYMEX HH Volumes — 4,186 1,393 — 5,891 Weighted-Average Contract Price $ — $ 3.17 $ 3.39 $ — $ 4.20 Collars NYMEX HH Volumes 8,382 4,432 4,612 5,716 13,217 Weighted-Average Floor Price $ 3.57 $ 3.69 $ 3.68 $ 3.48 $ 3.44 Weighted-Average Ceiling Price $ 7.82 $ 4.00 $ 4.21 $ 5.24 $ 5.06 Basis Swaps IF Waha-NYMEX HH Volumes 5,089 5,285 5,344 5,240 20,501 Weighted-Average Contract Price $ (0.61) $ (1.09) $ (0.99) $ (0.73) $ (0.66) IF HSC-NYMEX HH Volumes 4,957 3,310 3,426 5,750 — Weighted-Average Contract Price $ (0.01) $ (0.34) $ (0.30) $ (0.38) $ — NGL Derivatives (volumes in MBbl and prices in $ per Bbl): Swaps OPIS Propane Mont Belvieu Non-TET Volumes 62 65 68 70 — Weighted-Average Contract Price $ 28.56 $ 28.56 $ 28.56 $ 28.56 $ — Commodity Derivative Contracts Entered Into Subsequent to December 31, 2023 Subsequent to December 31, 2023, and through the filing of this report, the Company entered into the following commodity derivative contracts: Contract Period First Quarter Second Quarter Third Quarter Fourth Quarter 2024 2024 2024 2024 2025 2026 Oil Derivatives (volumes in MBbl and prices in $ per Bbl): Swaps NYMEX WTI Volumes — — — 344 — — Weighted-Average Contract Price $ — $ — $ — $ 71.00 $ — $ — Collars NYMEX WTI Volumes — — 335 344 — — Weighted-Average Floor Price $ — $ — $ 65.00 $ 65.00 $ — $ — Weighted-Average Ceiling Price $ — $ — $ 78.61 $ 76.45 $ — $ — Basis Swaps WTI Midland-NYMEX WTI Volumes — — — — 941 — Weighted-Average Contract Price $ — $ — $ — $ — $ 1.15 $ — WTI Houston MEH-NYMEX WTI Volumes — — — — 684 816 Weighted-Average Contract Price $ — $ — $ — $ — $ 1.95 $ 2.10 Gas Derivatives (volumes in BBtu and prices in $ per MMBtu): Swaps NYMEX HH Volumes — — 1,530 — — — Weighted-Average Contract Price $ — $ — $ 2.99 $ — $ — $ — Collars NYMEX HH Volumes — — — 1,612 4,838 — Weighted-Average Floor Price $ — $ — $ — $ 3.00 $ 3.00 $ — Weighted-Average Ceiling Price $ — $ — $ — $ 4.02 $ 4.22 $ — Basis Swaps IF HSC-NYMEX HH Volumes — — — — 946 — Weighted-Average Contract Price $ — $ — $ — $ — $ 0.0025 $ — NGL Derivatives (volumes in MBbl and prices in $ per Bbl): Swaps OPIS Propane Mont Belvieu Non-TET Volumes 254 322 336 364 396 — Weighted-Average Contract Price $ 32.33 $ 32.57 $ 32.54 $ 32.49 $ 32.86 $ — OPIS Normal Butane Mont Belvieu Non-TET Volumes 28 44 46 49 45 — Weighted-Average Contract Price $ 39.48 $ 39.48 $ 39.48 $ 39.48 $ 39.48 $ — OPIS Isobutane Mont Belvieu Non-TET Volumes 15 24 25 28 25 — Weighted-Average Contract Price $ 41.58 $ 41.58 $ 41.58 $ 41.58 $ 41.58 $ — |
Schedule of fair value of derivatives in accompanying balance sheets | The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category: As of December 31, 2023 As of December 31, 2022 (in thousands) Derivative assets: Current assets $ 56,442 $ 48,677 Noncurrent assets 8,672 24,465 Total derivative assets $ 65,114 $ 73,142 Derivative liabilities: Current liabilities $ 6,789 $ 56,181 Noncurrent liabilities 1,273 1,142 Total derivative liabilities $ 8,062 $ 57,323 |
Schedule of the potential effects of master netting arrangements | The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts: Derivative Assets as of Derivative Liabilities as of December 31, December 31, December 31, December 31, (in thousands) Gross amounts presented in the accompanying balance sheets $ 65,114 $ 73,142 $ (8,062) $ (57,323) Amounts not offset in the accompanying balance sheets (7,362) (26,136) 7,362 26,136 Net amounts $ 57,752 $ 47,006 $ (700) $ (31,187) |
Schedule of the components of the derivative settlement (gain) loss and the net derivative (gain) loss | The following table summarizes the commodity components of the net derivative settlement (gain) loss, and the net derivative (gain) loss line items presented within the accompanying statements of cash flows and the accompanying statements of operations, respectively: For the Years Ended December 31, 2023 2022 2021 (in thousands) Net derivative settlement (gain) loss: Oil contracts $ 26,873 $ 514,641 $ 523,245 Gas contracts (49,156) 171,598 152,361 NGL contracts (4,638) 24,461 73,352 Total net derivative settlement (gain) loss: $ (26,921) $ 710,700 $ 748,958 Net derivative (gain) loss: Oil contracts $ (20,813) $ 284,863 $ 650,959 Gas contracts (42,713) 82,769 172,248 NGL contracts (4,628) 6,380 78,452 Total net derivative (gain) loss: $ (68,154) $ 374,012 $ 901,659 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy: As of December 31, 2023 As of December 31, 2022 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 65,114 $ — $ — $ 73,142 $ — Liabilities: Derivatives (1) $ — $ 8,062 $ — $ — $ 57,323 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments | The following table reflects the fair value of the Company’s Senior Notes obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2023, or 2022, as they were recorded at carrying value, net of any unamortized deferred financing costs. Please refer to Note 5 – Long-Term Debt for additional information. As of December 31, 2023 2022 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 5.625% Senior Notes due 2025 $ 349,118 $ 348,189 $ 349,118 $ 337,821 6.75% Senior Notes due 2026 $ 419,235 $ 420,660 $ 419,235 $ 409,484 6.625% Senior Notes due 2027 $ 416,791 $ 416,549 $ 416,791 $ 402,120 6.5% Senior Notes due 2028 $ 400,000 $ 401,372 $ 400,000 $ 384,520 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Schedule of calculations of basic and diluted net income (loss) per common share | The following table sets forth the calculations of basic and diluted net income per common share: For the Years Ended December 31, 2023 2022 2021 (in thousands, except per share data) Net income $ 817,880 $ 1,111,952 $ 36,229 Basic weighted-average common shares outstanding 118,678 122,351 119,043 Dilutive effect of non-vested RSUs, contingent PSUs, and other 553 1,714 2,582 Dilutive effect of Warrants 9 19 2,065 Diluted weighted-average common shares outstanding 119,240 124,084 123,690 Basic net income per common share $ 6.89 $ 9.09 $ 0.30 Diluted net income per common share $ 6.86 $ 8.96 $ 0.29 |
Compensation Plans (Tables)
Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Schedule of non-vested PSUs | A summary of activity is presented in the following table: For the Years Ended December 31, 2023 2022 2021 PSUs (1) Weighted-Average Grant-Date Fair Value (2) PSUs (1) Weighted-Average Grant-Date Fair Value (2) PSUs (1) Weighted-Average Grant-Date Fair Value (2) Non-vested at beginning of year 273,258 $ 26.67 464,483 $ 12.80 830,464 $ 17.52 Granted 256,633 $ 29.93 276,010 $ 26.67 — $ — Vested (15,950) $ 25.50 (461,387) $ 12.81 (352,395) $ 23.81 Forfeited (44,509) $ 26.45 (5,848) $ 18.24 (13,586) $ 15.46 Non-vested at end of year 469,432 $ 27.83 273,258 $ 26.67 464,483 $ 12.80 ____________________________________________ (1) The number of PSUs presented assumes a multiplier of one. The actual final number of shares of common stock to be issued at the end of the three three (2) Amounts represent price per unit. |
Schedule of shares settled, performance share units | A summary of the shares of common stock issued to settle PSUs is presented in the table below: For the Years Ended December 31, 2022 2021 Shares of common stock issued to settle PSUs (1) 1,004,410 347,742 Less: shares of common stock withheld for income and payroll taxes (349,487) (112,919) Net shares of common stock issued 654,923 234,823 Multiplier earned 2.0 1.0 ____________________________________________ (1) During the year ended December 31, 2023, there were no shares of common stock issued to settle PSUs. During the years ended December 31, 2022, and 2021, the Company settled PSUs that were granted in 2019 and 2018, respectively. The Company and all eligible recipients in 2022 and 2021 mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. |
Schedule of non-vested RSUs | A summary of activity is presented in the following table: For the Years Ended December 31, 2023 2022 2021 RSUs Weighted- Average Grant-Date Fair Value (1) RSUs Weighted- Average Grant-Date Fair Value (1) RSUs Weighted- Average Grant-Date Fair Value (1) Non-vested at beginning of year 1,375,052 $ 22.42 1,841,237 $ 13.79 2,097,860 $ 8.83 Granted 630,474 $ 32.03 526,776 $ 34.08 666,052 $ 25.52 Vested (805,205) $ 16.75 (920,927) $ 12.17 (843,098) $ 11.00 Forfeited (119,777) $ 29.26 (72,034) $ 18.24 (79,577) $ 10.64 Non-vested at end of year 1,080,544 $ 31.49 1,375,052 $ 22.42 1,841,237 $ 13.79 ____________________________________________ (1) Amounts represent price per unit. |
Schedule of shares settled, restricted stock units | A summary of the shares of common stock issued to settle RSUs is presented in the table below: For the Years Ended December 31, 2023 2022 2021 Shares of common stock issued to settle RSUs (1) 803,449 920,927 843,098 Less: shares of common stock withheld for income and payroll taxes (249,233) (284,423) (250,349) Net shares of common stock issued 554,216 636,504 592,749 ____________________________________________ (1) During the years ended December 31, 2023, 2022, and 2021, the Company issued shares of common stock to settle RSUs that related to awards granted in previous years. The Company and a majority of eligible recipients in 2023, and all eligible recipients in 2022 and 2021, mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. |
Schedule of employee stock purchase plan | The fair value of ESPP shares issued during the periods reported above were estimated using the following weighted-average assumptions: For the Years Ended December 31, 2023 2022 2021 Risk free interest rate 5.1 % 1.2 % 0.8 % Dividend yield 1.8 % 0.1 % 0.3 % Volatility factor of the expected market price of the Company’s common stock 53.6 % 69.1 % 106.1 % Expected life (in years) 0.5 0.5 0.5 |
Pension Benefits (Tables)
Pension Benefits (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | |
Schedule of net funded status | For the Years Ended December 31, 2023 2022 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 65,161 $ 75,760 Service cost 3,706 4,652 Interest cost 3,200 2,314 Actuarial (gain) loss 84 (15,567) Benefits paid (4,883) (1,998) Projected benefit obligation at end of year 67,268 65,161 Change in plan assets: Fair value of plan assets at beginning of year 36,414 35,941 Actual return on plan assets 4,161 (3,529) Employer contribution 10,000 6,000 Benefits paid (4,883) (1,998) Fair value of plan assets at end of year 45,692 36,414 Funded status at end of year $ (21,576) $ (28,747) |
Schedule of accumulated benefit obligation in excess of plan assets | Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2023 2022 (in thousands) Projected benefit obligation $ 67,268 $ 65,161 Accumulated benefit obligation $ 55,557 $ 55,712 Less: fair value of plan assets (45,692) (36,414) Underfunded accumulated benefit obligation $ 9,865 $ 19,298 |
Schedule of pension liability adjustments recognized in other comprehensive income (loss) | The pension liability adjustments recognized in other comprehensive income during 2023, 2022, and 2021, were as follows: For the Years Ended December 31, 2023 2022 2021 (in thousands) Net actuarial gain (loss) $ 1,737 $ 10,327 $ (612) Amortization of prior service cost — — 13 Amortization of net actuarial loss 68 931 1,240 Settlements — — 312 Total pension liability adjustment, pre-tax 1,805 11,258 953 Tax expense (390) (2,431) (204) Total pension liability adjustment, net $ 1,415 $ 8,827 $ 749 |
Components of net periodic benefit cost for the pension plans | Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2023 2022 2021 (in thousands) Components of net periodic benefit cost: Service cost $ 3,706 $ 4,652 $ 4,455 Interest cost 3,200 2,314 2,089 Expected return on plan assets that reduces periodic pension benefit cost (2,340) (1,711) (1,474) Amortization of prior service cost — — 13 Amortization of net actuarial loss 68 931 1,240 Net periodic benefit cost 4,634 6,186 6,323 Settlements — — 312 Total net benefit cost $ 4,634 $ 6,186 $ 6,635 |
Schedule of weighted-average pension plan assumptions | The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows: As of December 31, 2023 2022 Projected benefit obligation: Discount rate 5.0% 5.2% Rate of compensation increase 3.5% 3.5% The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows: For the Years Ended December 31, 2023 2022 2021 Net periodic benefit cost: Discount rate 5.2% 3.1% 2.9% Expected return on plan assets (1) 6.3% 3.6% 4.4% Rate of compensation increase 3.5% 4.8% 4.4% ____________________________________________ (1) There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan. |
Schedule of weighted-average asset allocation of the Qualified Pension Plan | The weighted-average asset allocation of the Qualified Pension Plan is as follows: Target As of December 31, Asset Category 2024 2023 2022 Equity securities 49.0 % 43.0 % 47.1 % Fixed income securities 26.0 % 25.5 % 21.0 % Other securities 25.0 % 31.5 % 31.9 % Total 100.0 % 100.0 % 100.0 % |
Schedule of fair values of the Qualified Pension Plan assets | The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2023, and 2022, utilizing the fair value hierarchy discussed in Note 8 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual Asset Allocation (1) Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (in thousands) As of December 31, 2023 Equity securities: Domestic (2) 20.3 % $ 9,280 $ 6,097 $ 3,183 $ — International (3) 22.7 % 10,349 10,349 — — Total equity securities 43.0 % 19,629 16,446 3,183 — Fixed income securities: Core fixed income (4) 25.5 % 11,646 11,646 — — Floating rate corporate loans (5) — % — — — — Total fixed income securities 25.5 % 11,646 11,646 — — Other securities: Real estate (6) 4.6 % 2,116 — — 2,116 Collective investment trusts (7) 13.6 % 6,206 — 6,206 — Hedge fund (8) 13.3 % 6,095 1,498 — 4,597 Total other securities 31.5 % 14,417 1,498 6,206 6,713 Total investments 100.0 % $ 45,692 $ 29,590 $ 9,389 $ 6,713 As of December 31, 2022 Equity securities: Domestic (2) 20.7 % $ 7,533 $ 5,012 $ 2,521 $ — International (3) 26.4 % 9,594 9,594 — — Total equity securities 47.1 % 17,127 14,606 2,521 — Fixed income securities: Core fixed income (4) 14.3 % 5,220 5,220 — — Floating rate corporate loans (5) 6.7 % 2,450 2,450 — — Total fixed income securities 21.0 % 7,670 7,670 — — Other securities: Real estate (6) 6.8 % 2,476 — — 2,476 Collective investment trusts (7) 1.9 % 687 — 687 — Hedge fund (8) 23.2 % 8,454 4,133 — 4,321 Total other securities 31.9 % 11,617 4,133 687 6,797 Total investments 100.0 % $ 36,414 $ 26,409 $ 3,208 $ 6,797 ____________________________________________ (1) Percentages may not calculate due to rounding. (2) Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold on demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective investment funds. (3) International equity securities consist of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets that are believed to have strong sustainable financial productivity at attractive valuations. (4) The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. (5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. (6) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. (7) Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. (8) The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. |
Schedule of changes in Level 3 plan assets | The following is a summary of the changes in Level 3 plan assets (in thousands): Balance at January 1, 2022 $ 6,195 Purchases 400 Realized gain on assets 259 Unrealized loss on assets (57) Disposition — Balance at December 31, 2022 $ 6,797 Purchases — Realized gain on assets 364 Unrealized loss on assets (448) Disposition — Balance at December 31, 2023 $ 6,713 |
Schedule of expected benefit payments | Expected benefit payments over the next 10 years are as follows: For the Years Ending December 31, Amount (in thousands) 2024 $ 6,865 2025 $ 4,455 2026 $ 7,064 2027 $ 5,026 2028 $ 5,281 2029 through 2033 $ 25,587 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Lessee Disclosure [Abstract] | |
Components of total lease cost | The following table reflects the components of the Company’s total lease costs, whether capitalized or expensed, related to operating leases, including short-term leases, and variable lease payments made for both short-term and long-term leases for the years ended December 31, 2023, and 2022. This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. For the Years Ended December 31, 2023 2022 (in thousands) Operating lease cost $ 15,625 $ 10,174 Short-term lease cost (1) 251,628 175,098 Variable lease cost (2) 11,838 7,085 Total lease cost $ 279,091 $ 192,357 ____________________________________________ (1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements. (2) Variable lease payments relate to the actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are primarily driven by the number of drilling rigs and completion crews operating. Cash paid for amounts included in the measurement of lease liabilities for the years ended December 31, 2023, and 2022, were as follows: For the Years Ended December 31, 2023 2022 (in thousands) Operating cash flows related to operating leases $ 4,181 $ 4,718 Investing cash flows related to operating leases $ 11,300 $ 5,042 |
Operating lease liability maturities | Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2023, were as follows: As of December 31, 2023 (in thousands) 2024 $ 17,208 2025 11,242 2026 4,793 2027 2,685 2028 2,054 Thereafter 6,906 Total Lease payments $ 44,888 Less: Imputed interest (1) (5,110) Total $ 39,778 ____________________________________________ (1) The weighted-average discount rate used to determine the operating lease liability as of December 31, 2023, was 6.2 percent. |
Balance sheet information related to operating leases | The following table presents supplemental accompanying balance sheet information for operating leases as of December 31, 2023, and 2022: As of December 31, 2023 2022 (in thousands, except discount rate and lease term) Balance sheet classifications of operating leases: Other noncurrent assets $ 32,264 $ 26,368 Other current liabilities $ 15,425 $ 10,114 Other noncurrent liabilities $ 24,352 $ 23,621 ROU assets obtained in exchange for operating lease liabilities $ 19,341 $ 16,186 Weighted-average discount rate 6.2% 5.8% Weighted-average remaining lease term (years) 4 5 |
Accounts Receivable and Accou_2
Accounts Receivable and Accounts Payable and Accrued Expenses (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract] | |
Schedule of Accounts Receivable | The components of accounts receivable are as follows: As of December 31, 2023 2022 (in thousands) Oil, gas, and NGL production revenue $ 175,334 $ 184,458 Amounts due from joint interest owners 46,289 45,997 Other 9,542 2,842 Total accounts receivable $ 231,165 $ 233,297 |
Schedule of Accounts Payable and Accrued Expenses | The components of accounts payable and accrued expenses are as follows: As of December 31, 2023 2022 (in thousands) Drilling and lease operating cost accruals $ 144,707 $ 125,570 Trade accounts payable 107,315 43,898 Revenue and severance tax payable 186,663 182,744 Property taxes 43,406 43,066 Compensation 54,819 35,799 Net derivative settlements 1,129 22,745 Interest 35,976 35,992 Dividends payable 20,834 18,290 Other 16,749 24,185 Total accounts payable and accrued expenses $ 611,598 $ 532,289 |
Reconciliation of Asset Retirem
Reconciliation of Asset Retirement Obligation Liability (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation [Abstract] | |
Schedule of change in asset retirement obligation liability | The following is a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2023, and 2022: As of December 31, 2023 2022 (in thousands) Beginning asset retirement obligations $ 115,313 $ 101,424 Liabilities incurred (1) 4,062 2,086 Liabilities settled (2) (4,489) (6,356) Accretion expense 6,330 5,344 Revision to estimated cash flows 1,938 12,815 Ending asset retirement obligations (3) $ 123,154 $ 115,313 ____________________________________________ (1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. (2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. (3) Balances as of December 31, 2023, and 2022, included $4.4 million and $7.1 million, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets. |
Suspended Well Costs (Tables)
Suspended Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Extractive Industries [Abstract] | |
Net changes in capitalized exploratory well costs | The following table reflects the net changes in capitalized exploratory well costs during 2023, 2022, and 2021. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: For the Years Ended December 31, 2023 2022 2021 (in thousands) Beginning balance $ 49,047 $ 15,576 $ 5,698 Additions to capitalized exploratory well costs pending the determination of net proved reserves 70,762 49,047 15,576 Reclassifications based on the determination of net proved reserves (47,985) (14,721) (5,698) Capitalized exploratory well costs charged to expense (1) (455) (855) — Ending balance $ 71,369 $ 49,047 $ 15,576 ____________________________________________ (1) For the year ended December 31, 2023, amount relates to one well that experienced technical issues during the drilling phase. For the year ended December 31, 2022, amount relates to unsuccessful exploration activity outside of the Company’s core areas of operation. |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies Other (Details) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Oil and Gas Properties | |||
Impairment of Proved, Unproved, and Other Properties [Abstract] | |||
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast | 5 years | ||
Customer Concentration Risk | Oil, gas, and NGL revenue | Major customer one | |||
Concentration of Credit Risk and Major Customers [Abstract] | |||
Entity-Wide Revenue, Major Customer, Percentage | 24% | 24% | 27% |
Customer Concentration Risk | Oil, gas, and NGL revenue | Major customer two | |||
Concentration of Credit Risk and Major Customers [Abstract] | |||
Entity-Wide Revenue, Major Customer, Percentage | 11% | 7% | 9% |
Customer Concentration Risk | Oil, gas, and NGL revenue | Major customer three | |||
Concentration of Credit Risk and Major Customers [Abstract] | |||
Entity-Wide Revenue, Major Customer, Percentage | 6% | 8% | 15% |
Customer Concentration Risk | Oil, gas, and NGL revenue | Group one of entities under common control | |||
Concentration of Credit Risk and Major Customers [Abstract] | |||
Entity-Wide Revenue, Major Customer, Percentage | 22% | 24% | 18% |
Minimum | |||
Revenues [Abstract] | |||
Revenue receipt, days after sale | 30 | ||
Minimum | Property, Plant and Equipment, Other Types | |||
Property, Plant and Equipment [Abstract] | |||
Property, Plant and Equipment, Estimated Useful Lives | 3 years | ||
Minimum | Measurement Input, Discount Rate | Fair Value, Nonrecurring | Oil and Gas Properties | |||
Impairment of Proved, Unproved, and Other Properties [Abstract] | |||
Fair value assumptions, measurement input | 0.10 | ||
Minimum | Measurement Input, Credit adjusted risk free rate | Asset Retirement Obligation Costs | |||
Impairment of Proved, Unproved, and Other Properties [Abstract] | |||
Fair value assumptions, measurement input | 0.055 | ||
Maximum | |||
Revenues [Abstract] | |||
Revenue receipt, days after sale | 90 | ||
Maximum | Property, Plant and Equipment, Other Types | |||
Property, Plant and Equipment [Abstract] | |||
Property, Plant and Equipment, Estimated Useful Lives | 30 years | ||
Maximum | Measurement Input, Discount Rate | Fair Value, Nonrecurring | Oil and Gas Properties | |||
Impairment of Proved, Unproved, and Other Properties [Abstract] | |||
Fair value assumptions, measurement input | 0.15 | ||
Maximum | Measurement Input, Credit adjusted risk free rate | Asset Retirement Obligation Costs | |||
Impairment of Proved, Unproved, and Other Properties [Abstract] | |||
Fair value assumptions, measurement input | 0.12 |
Disaggregation of oil, gas, and
Disaggregation of oil, gas, and NGL production revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | $ 2,363,889 | $ 3,345,906 | $ 2,597,915 |
Revenue, Remaining Performance Obligation, Amount | 0 | ||
Midland Basin | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 1,523,650 | 2,250,414 | 2,028,411 |
South Texas | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | $ 840,239 | $ 1,095,492 | $ 569,504 |
Revenue Benchmark | Geographic Concentration Risk | |||
Segment Reporting Information [Line Items] | |||
Relative percentage | 100% | 100% | 100% |
Revenue Benchmark | Geographic Concentration Risk | Midland Basin | |||
Segment Reporting Information [Line Items] | |||
Relative percentage | 64% | 67% | 78% |
Revenue Benchmark | Geographic Concentration Risk | South Texas | |||
Segment Reporting Information [Line Items] | |||
Relative percentage | 36% | 33% | 22% |
Oil production revenue | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | $ 1,813,775 | $ 2,270,068 | $ 1,891,826 |
Oil production revenue | Midland Basin | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 1,347,780 | 1,816,597 | 1,701,915 |
Oil production revenue | South Texas | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 465,995 | 453,471 | 189,911 |
Gas production revenue | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 327,883 | 790,880 | 525,479 |
Gas production revenue | Midland Basin | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 175,183 | 432,831 | 326,115 |
Gas production revenue | South Texas | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 152,700 | 358,049 | 199,364 |
NGL production revenue | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 222,231 | 284,958 | 180,610 |
NGL production revenue | Midland Basin | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | 687 | 986 | 381 |
NGL production revenue | South Texas | |||
Segment Reporting Information [Line Items] | |||
Revenue from Contract with Customer, Including Assessed Tax | $ 221,544 | $ 283,972 | $ 180,229 |
Accounts Receivable from Custom
Accounts Receivable from Customers (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Accrued Income Receivable | ||
Accounts Receivable | ||
Accounts Receivable, before Allowance for Credit Loss, Current | $ 175.3 | $ 184.5 |
Minimum | ||
Accounts Receivable | ||
Revenue receipt, days after sale | 30 | |
Maximum | ||
Accounts Receivable | ||
Revenue receipt, days after sale | 90 |
Stock Repurchase Program (Detai
Stock Repurchase Program (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | Feb. 21, 2024 | |
Stock Repurchase Program [Line Items] | ||||
Stock Repurchase Program, Authorized Amount | $ 500,000 | $ 500,000 | ||
Stock Repurchase Program Expiration Date | Dec. 31, 2024 | |||
Stock Repurchased and Retired During Period, Shares | 6,931 | 1,365 | ||
Stock Repurchase Program, Shares Repurchased, Weighted Average Price Per Share | $ 32.89 | $ 41.88 | ||
Stock Repurchased and Retired During Period Excluding Taxes, Commission, and Fees, Value | $ 227,966 | $ 57,179 | ||
Subsequent Event | ||||
Stock Repurchase Program [Line Items] | ||||
Stock Repurchase Program, Remaining Authorized Repurchase Amount | $ 214,900 |
Dividends (Details)
Dividends (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Dividends [Abstract] | |||
Common Stock, Dividends, Annual Rate Per Share | $ 0.72 | ||
Cash dividends declared per share | $ 0.18 | ||
Net Cash Dividends, Common Stock, Cash | $ 74,159 | $ 37,927 | $ 2,393 |
Warrants (Details)
Warrants (Details) - $ / shares | 12 Months Ended | |||||
Jan. 15, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Jun. 30, 2023 | Jun. 17, 2020 | |
Class of Warrant or Right [Line Items] | ||||||
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | 5,900,000 | |||||
Warrants Percent of Outstanding Stock | 5% | |||||
Exercise price of warrants | $ 0.01 | |||||
Class of Warrant or Right, Date from which Warrants or Rights Exercisable | Jan. 15, 2021 | |||||
Warrants and Rights Outstanding, Maturity Date | Jun. 30, 2023 | |||||
WarrantsExercised | 19,000 | 0 | 5,922,000 | |||
Weighted Average | ||||||
Class of Warrant or Right [Line Items] | ||||||
Shares Issued, Price Per Share | $ 29.09 | $ 0 | $ 15.45 | |||
Common Stock | ||||||
Class of Warrant or Right [Line Items] | ||||||
Issuance of common stock through cashless exercise of Warrants (Shares) | 19,037 | 0 | 5,918,089 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Components of the provision for income taxes | |||
Current Federal Tax Expense | $ (8,461) | $ (9,230) | $ 0 |
Current State and Local Tax Expense | 395 | (5,531) | (373) |
Deferred portion of income tax expense | (88,256) | (269,057) | (9,565) |
Income tax expense | $ (96,322) | $ (283,818) | $ (9,938) |
Effective tax rate (as a percent) | 10.50% | 20.30% | 21.50% |
Deferred income taxes [Abstract] | |||
Deferred tax liabilities, oil and gas properties | $ 450,634 | $ 358,537 | |
Deferred tax liabilities, derivative assets | 12,319 | 3,416 | |
Deferred tax liabilities, other | 6,283 | 6,059 | |
Total deferred tax liabilities | 469,236 | 368,012 | |
Deferred tax assets, credit carryover | 56,097 | 161 | |
Deferred tax assets, asset retirement obligation liabilities | 26,592 | 24,899 | |
Deferred tax assets, lease liabilities | 4,454 | 4,525 | |
Deferred tax assets, federal and state tax net operating loss carryovers | 3,271 | 28,151 | |
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Legal Settlements | 2,838 | 0 | |
Deferred tax assets, pension | 2,453 | 3,970 | |
Deferred tax assets, interest carryforward | 1,031 | 22,667 | |
Deferred tax assets, other liabilities | 4,003 | 4,444 | |
Total deferred tax assets | 100,739 | 88,817 | |
Deferred tax assets, valuation allowance | (1,406) | (1,616) | |
Net deferred tax assets | 99,333 | 87,201 | |
Total net deferred tax liabilities | 369,903 | 280,811 | |
Reconciliation of unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits, Beginning balance | 446 | 446 | $ 446 |
Unrecognized tax benefits, Ending balance | 24,159 | 446 | 446 |
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 23,713 | 0 | $ 0 |
Research and development tax credit carryforward | |||
Deferred income taxes [Abstract] | |||
Tax credit carryforwards | 56,100 | ||
State and local jurisdiction | |||
Deferred income taxes [Abstract] | |||
Income Taxes Receivable, Current | 1,253 | ||
Current income tax payable | (5,316) | ||
Net operating loss carryforwards | 74,000 | ||
Internal Revenue Service (IRS) | Domestic tax authority | |||
Deferred income taxes [Abstract] | |||
Income Taxes Receivable, Current | $ 770 | ||
Current income tax payable | $ (4,899) |
Income Taxes Reconciliation of
Income Taxes Reconciliation of Tax Expense (Benefit) and Other (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, (Expense) Benefit | $ (191,983) | $ (293,112) | $ (9,695) |
Effective Income Tax Rate Reconciliation, Tax Credit, Amount | 92,420 | 0 | 0 |
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance | 210 | 16,845 | (5,073) |
Effective Income Tax Rate Reconciliation, State tax (expense) benefit (net of federal benefit) | 5,166 | (9,870) | (211) |
Effective Income Tax Rate Reconciliation, Other | (2,135) | 2,319 | 5,041 |
Income tax expense | $ (96,322) | $ (283,818) | $ (9,938) |
Credit Agreement (Details)
Credit Agreement (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2023 | Feb. 08, 2024 | Dec. 31, 2022 | |
Line of Credit Facility [Line Items] | ||||
Revolving credit facility | $ 0 | $ 0 | $ 0 | |
Borrowing Base Utilization of 25 Percent | Line of Credit | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, unused capacity, commitment fee rate | 0.375% | |||
Borrowing Base Utilization of 25 Percent | Line of Credit | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 2% | |||
Borrowing Base Utilization of 25 Percent | Line of Credit | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 1% | |||
Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent | Line of Credit | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, unused capacity, commitment fee rate | 0.375% | |||
Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent | Line of Credit | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 2.25% | |||
Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent | Line of Credit | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 1.25% | |||
Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent | Line of Credit | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, unused capacity, commitment fee rate | 0.50% | |||
Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent | Line of Credit | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 2.50% | |||
Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent | Line of Credit | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 1.50% | |||
Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent | Line of Credit | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, unused capacity, commitment fee rate | 0.50% | |||
Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent | Line of Credit | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 2.75% | |||
Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent | Line of Credit | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 1.75% | |||
Borrowing Base Utilization Of 90 Percent Or More | Line of Credit | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, unused capacity, commitment fee rate | 0.50% | |||
Borrowing Base Utilization Of 90 Percent Or More | Line of Credit | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 3% | |||
Borrowing Base Utilization Of 90 Percent Or More | Line of Credit | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans | ||||
Debt Instrument Borrowing Base Utilization [Line Items] | ||||
Revolving credit facility, basis spread on variable rate | 2% | |||
Revolving Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Revolving credit facility, maximum loan amount | 3,000,000 | $ 3,000,000 | ||
Revolving credit facility, current borrowing base | 2,500,000 | 2,500,000 | ||
Revolving credit facility, aggregate lender commitment amount | $ 1,250,000 | 1,250,000 | 1,250,000 | |
Debt Instrument, Maturity Date | Aug. 02, 2027 | |||
Revolving credit facility | $ 0 | 0 | 0 | |
Letters of credit | 2,500 | 2,500 | 6,000 | |
Available borrowing capacity | 1,247,500 | 1,247,500 | 1,244,000 | |
Revolving credit facility, unamortized deferred financing costs | $ 8,500 | $ 8,500 | $ 10,800 | |
Revolving Credit Facility | Subsequent Event | ||||
Line of Credit Facility [Line Items] | ||||
Revolving credit facility, aggregate lender commitment amount | $ 1,250,000 | |||
Revolving credit facility | 0 | |||
Letters of credit | 2,500 | |||
Available borrowing capacity | $ 1,247,500 |
Senior Notes (Details)
Senior Notes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||||||
Feb. 14, 2022 | Jun. 23, 2021 | Aug. 20, 2018 | Sep. 12, 2016 | May 21, 2015 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Jun. 30, 2021 | |
Long-Term Debt [Line Items] | |||||||||
Senior Notes | $ 1,575,334 | $ 1,572,210 | |||||||
Net loss on extinguishment of debt | $ 0 | $ (67,605) | $ (2,139) | ||||||
5.625% Senior Unsecured Notes Due 2025 | |||||||||
Long-Term Debt [Line Items] | |||||||||
Senior Notes, interest rate, stated percentage | 5.625% | 5.625% | 5.625% | ||||||
Senior Notes, Principal amount | $ 500,000 | $ 349,118 | $ 349,118 | ||||||
Senior Notes, unamortized deferred financing costs | 896 | 1,528 | |||||||
Unsecured Long-term Debt, Noncurrent | $ 348,222 | $ 347,590 | |||||||
Proceeds from Debt, Net of Issuance Costs | 491,000 | ||||||||
Senior Notes Debt Issuance Costs | $ 9,000 | ||||||||
6.75% Senior Unsecured Notes Due 2026 | |||||||||
Long-Term Debt [Line Items] | |||||||||
Senior Notes, interest rate, stated percentage | 6.75% | 6.75% | 6.75% | ||||||
Senior Notes, Principal amount | $ 500,000 | $ 419,235 | $ 419,235 | ||||||
Senior Notes, unamortized deferred financing costs | 1,868 | 2,569 | |||||||
Unsecured Long-term Debt, Noncurrent | $ 417,367 | $ 416,666 | |||||||
Proceeds from Debt, Net of Issuance Costs | 491,600 | ||||||||
Senior Notes Debt Issuance Costs | $ 8,400 | ||||||||
6.625% Senior Unsecured Notes Due 2027 | |||||||||
Long-Term Debt [Line Items] | |||||||||
Senior Notes, interest rate, stated percentage | 6.625% | 6.625% | 6.625% | ||||||
Senior Notes, Principal amount | $ 500,000 | $ 416,791 | $ 416,791 | ||||||
Senior Notes, unamortized deferred financing costs | 2,395 | 3,172 | |||||||
Unsecured Long-term Debt, Noncurrent | $ 414,396 | $ 413,619 | |||||||
Proceeds from Debt, Net of Issuance Costs | 492,100 | ||||||||
Senior Notes Debt Issuance Costs | $ 7,900 | ||||||||
6.5% Senior Unsecured Notes Due 2028 | |||||||||
Long-Term Debt [Line Items] | |||||||||
Senior Notes, interest rate, stated percentage | 6.50% | 6.50% | 6.50% | ||||||
Senior Notes, Principal amount | $ 400,000 | $ 400,000 | $ 400,000 | ||||||
Senior Notes, unamortized deferred financing costs | 4,651 | 5,665 | |||||||
Unsecured Long-term Debt, Noncurrent | 395,349 | 394,335 | |||||||
Proceeds from Debt, Net of Issuance Costs | 392,800 | ||||||||
Senior Notes Debt Issuance Costs | $ 7,200 | ||||||||
Senior Notes [Member] | |||||||||
Long-Term Debt [Line Items] | |||||||||
Senior Notes, Principal amount | 1,585,144 | 1,585,144 | |||||||
Senior Notes, unamortized deferred financing costs | $ 9,810 | $ 12,934 | |||||||
5.0% Senior Unsecured Notes Due 2024 | |||||||||
Long-Term Debt [Line Items] | |||||||||
Senior Notes, interest rate, stated percentage | 5% | 5% | |||||||
Senior Notes, repurchased, retired or redeemed face amount | $ 104,800 | $ 172,300 | |||||||
Senior Unsecured Notes, Redemption Price, Percentage | 100% | ||||||||
6.125% Senior Unsecured Notes Due 2022 | |||||||||
Long-Term Debt [Line Items] | |||||||||
Senior Notes, interest rate, stated percentage | 6.125% | 6.125% | |||||||
Senior Notes, repurchased, retired or redeemed face amount | $ 193,100 | $ 19,300 | |||||||
6.125% Senior Unsecured Notes Due 2022 and 5.0% Senior Unsecured Notes Due 2024 | |||||||||
Long-Term Debt [Line Items] | |||||||||
Senior Unsecured Notes, Settlement Amount | 385,300 | ||||||||
Net loss on extinguishment of debt | (2,100) | ||||||||
Debt Instrument, Repurchase Premium | 600 | ||||||||
6.125% Senior Unsecured Notes Due 2022 and 5.0% Senior Unsecured Notes Due 2024 | Accelerated Unamortized Deferred Financing Costs | |||||||||
Long-Term Debt [Line Items] | |||||||||
Write off of Deferred Debt Issuance Cost | $ 1,500 |
Senior Secured Notes (Details)
Senior Secured Notes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Jun. 17, 2022 | Jul. 01, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Long-Term Debt [Line Items] | |||||
Net loss on extinguishment of debt | $ 0 | $ (67,605) | $ (2,139) | ||
10.0% Senior Secured Notes due 2025 | |||||
Long-Term Debt [Line Items] | |||||
Senior Notes, repurchased, retired or redeemed face amount | $ 446,700 | ||||
Senior Notes, interest rate, stated percentage | 10% | ||||
Senior Unsecured Notes, Redemption Price, Percentage | 107.50% | ||||
Net loss on extinguishment of debt | $ (67,200) | ||||
Debt Instrument, Repurchase Premium | 33,500 | ||||
10.0% Senior Secured Notes due 2025 | Accelerated Unamortized Deferred Financing Costs | |||||
Long-Term Debt [Line Items] | |||||
Write off of Deferred Debt Issuance Cost | 7,400 | ||||
10.0% Senior Secured Notes due 2025 | Accelerated Unamortized Debt Discount | |||||
Long-Term Debt [Line Items] | |||||
Write off of Deferred Debt Issuance Cost | $ 26,300 | ||||
1.50% Senior Secured Convertible Notes Due 2021 | |||||
Long-Term Debt [Line Items] | |||||
Senior Notes, interest rate, stated percentage | 1.50% | 1.50% | |||
Repayments of Convertible Debt | $ 65,500 |
Long-term Debt (Details)
Long-term Debt (Details) - USD ($) $ in Millions | 2 Months Ended | 12 Months Ended | |||
Dec. 31, 2023 | Feb. 21, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Long-Term Debt [Line Items] | |||||
Debt Instrument, Covenant Description | (a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 3.50 to 1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.00 to 1.00 as of the last day of any fiscal quarter. | ||||
Debt Instrument, Covenant Compliance | The Company was in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes as of December 31, 2023, and through the filing of this report. | ||||
Capitalized interest costs | $ 20.4 | $ 17.6 | $ 15 | ||
Subsequent Event | |||||
Long-Term Debt [Line Items] | |||||
Debt Instrument, Covenant Compliance | The Company was in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes as of December 31, 2023, and through the filing of this report. |
Commitments (Details)
Commitments (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 USD ($) MMBbls | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Feb. 21, 2024 USD ($) | |
Commitments and Contingencies | ||||
Contractual obligation, due in year 1 | $ 74,992 | |||
Contractual obligation, due in year 2 | 52,175 | |||
Contractual obligation, due in year 3 | 28,133 | |||
Contractual obligation, due in year 4 | 13,791 | |||
Contractual obligation, due in year 5 | 12,461 | |||
Contractual obligation, due thereafter | 14,655 | |||
Contractual obligation | $ 196,207 | |||
Crude oil pipeline commitment | ||||
Commitments and Contingencies | ||||
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls | 5 | |||
Crude Oil Pipeline Commitment Excluded from Remaining Deficiency Payment Amount | ||||
Commitments and Contingencies | ||||
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls | 1 | |||
Drilling Rig Leasing Contracts | ||||
Commitments and Contingencies | ||||
Contractual obligation | $ 19,100 | |||
Early Termination Penalty for Rig Contract Cancellation | 12,300 | |||
Early Termination Penalty Incurred for Rig Contract Cancellation | $ 0 | |||
Drilling Rig Leasing Contracts | Subsequent Event | ||||
Commitments and Contingencies | ||||
Contractual obligation | $ 14,500 | |||
Early Termination Penalty for Rig Contract Cancellation | $ 8,900 | |||
Water pipeline commitment | ||||
Commitments and Contingencies | ||||
Water delivery commitments, remaining minimum contractual volumes | MMBbls | 11 | |||
Pipeline Commitments | ||||
Commitments and Contingencies | ||||
Contractual obligation | $ 11,500 | |||
Office Space Leases | ||||
Commitments and Contingencies | ||||
Contractual obligation | 33,300 | |||
Operating Lease, Expense | 2,500 | $ 3,500 | $ 4,800 | |
Electricity Purchase Agreement | ||||
Commitments and Contingencies | ||||
Contractual obligation | 41,800 | |||
Sand Sourcing Commitment | ||||
Commitments and Contingencies | ||||
Contractual obligation | 46,800 | |||
Potential Penalty for not Meeting Minimum Sand Sourcing Requirements | 10,000 | |||
Compressor Service Contract | ||||
Commitments and Contingencies | ||||
Contractual obligation | 19,500 | |||
Other miscellaneous contracts and leases | ||||
Commitments and Contingencies | ||||
Contractual obligation | 24,200 | |||
Minimum | ||||
Commitments and Contingencies | ||||
Potential Penalty for not Meeting Minimum Drilling and Completion Requirements | 0 | |||
Maximum | ||||
Commitments and Contingencies | ||||
Potential Penalty for not Meeting Minimum Drilling and Completion Requirements | $ 8,300 |
Derivative Financial Instrume_3
Derivative Financial Instruments (Details) bbl in Thousands, BTU in Billions | 2 Months Ended | |
Dec. 31, 2023 BTU $ / Barrels $ / EnergyContent bbl | Feb. 21, 2024 BTU $ / EnergyContent $ / Barrels bbl | |
ICE Brent Oil Swap Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 910 | |
Derivative, Swap Type, Weighted-Average Contract Price | 85.50 | |
ICE Brent Oil Swap Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
ICE Brent Oil Swap Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
ICE Brent Oil Swap Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
ICE Brent Oil Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
NYMEX Oil Collar Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 795 | |
Derivative, Weighted-Average Floor Price | 68.21 | |
Derivative, Weighted-Average Ceiling Price | 82.37 | |
NYMEX Oil Collar Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,846 | |
Derivative, Weighted-Average Floor Price | 67.46 | |
Derivative, Weighted-Average Ceiling Price | 85.53 | |
NYMEX Oil Collar Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,669 | |
Derivative, Weighted-Average Floor Price | 68.93 | |
Derivative, Weighted-Average Ceiling Price | 84 | |
NYMEX Oil Collar Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 556 | |
Derivative, Weighted-Average Floor Price | 72.86 | |
Derivative, Weighted-Average Ceiling Price | 79.83 | |
NYMEX Oil Collar Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Weighted-Average Floor Price | 0 | |
Derivative, Weighted-Average Ceiling Price | 0 | |
NYMEX Oil Calendar Month Average Roll Differential Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,415 | |
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | 0.57 | |
NYMEX Oil Calendar Month Average Roll Differential Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,792 | |
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | 0.57 | |
NYMEX Oil Calendar Month Average Roll Differential Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,964 | |
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | 0.57 | |
NYMEX Oil Calendar Month Average Roll Differential Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,877 | |
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | 0.57 | |
NYMEX Oil Calendar Month Average Roll Differential Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | 0 | |
WTI Midland NYMEX WTI | Oil Basis Swap Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,199 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.21 | |
WTI Midland NYMEX WTI | Oil Basis Swap Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,193 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.21 | |
WTI Midland NYMEX WTI | Oil Basis Swap Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,235 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.21 | |
WTI Midland NYMEX WTI | Oil Basis Swap Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,230 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.21 | |
WTI Midland NYMEX WTI | Oil Basis Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 1,807 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.15 | |
WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 256 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.83 | |
WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 293 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.82 | |
WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 332 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.82 | |
WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 309 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.82 | |
WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 729 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.85 | |
NYMEX HH | Gas Swaps Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
NYMEX HH | Gas Swaps Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 4,186 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 3.17 | |
NYMEX HH | Gas Swaps Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 1,393 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 3.39 | |
NYMEX HH | Gas Swaps Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
NYMEX HH | Gas Swaps Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 5,891 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 4.20 | |
NYMEX HH | Gas Collar Contract, First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 8,382 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 3.57 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 7.82 | |
NYMEX HH | Gas Collar Contract, Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 4,432 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 3.69 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 4 | |
NYMEX HH | Gas Collar Contract, Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 4,612 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 3.68 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 4.21 | |
NYMEX HH | Gas Collar Contract, Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 5,716 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 3.48 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 5.24 | |
NYMEX HH | Gas Collar Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 13,217 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 3.44 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 5.06 | |
IF WAHA NYMEX HH | Gas Basis Swap Contract, First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 5,089 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (0.61) | |
IF WAHA NYMEX HH | Gas Basis Swap Contract, Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 5,285 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (1.09) | |
IF WAHA NYMEX HH | Gas Basis Swap Contract, Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 5,344 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (0.99) | |
IF WAHA NYMEX HH | Gas Basis Swap Contract, Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 5,240 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (0.73) | |
IF WAHA NYMEX HH | Gas Basis Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 20,501 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (0.66) | |
IF HSC NYMEX HH | Gas Basis Swap Contract, First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 4,957 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (0.01) | |
IF HSC NYMEX HH | Gas Basis Swap Contract, Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 3,310 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (0.34) | |
IF HSC NYMEX HH | Gas Basis Swap Contract, Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 3,426 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (0.30) | |
IF HSC NYMEX HH | Gas Basis Swap Contract, Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 5,750 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | (0.38) | |
IF HSC NYMEX HH | Gas Basis Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Gas Basis Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 62 | |
Derivative, Swap Type, Weighted-Average Contract Price | 28.56 | |
OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 65 | |
Derivative, Swap Type, Weighted-Average Contract Price | 28.56 | |
OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 68 | |
Derivative, Swap Type, Weighted-Average Contract Price | 28.56 | |
OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 70 | |
Derivative, Swap Type, Weighted-Average Contract Price | 28.56 | |
OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
Subsequent Event | NYMEX Oil Swap Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
Subsequent Event | NYMEX Oil Swap Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
Subsequent Event | NYMEX Oil Swap Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
Subsequent Event | NYMEX Oil Swap Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 344 | |
Derivative, Swap Type, Weighted-Average Contract Price | 71 | |
Subsequent Event | NYMEX Oil Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
Subsequent Event | NYMEX Oil Swap Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
Subsequent Event | NYMEX Oil Collar Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Weighted-Average Floor Price | 0 | |
Derivative, Weighted-Average Ceiling Price | 0 | |
Subsequent Event | NYMEX Oil Collar Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Weighted-Average Floor Price | 0 | |
Derivative, Weighted-Average Ceiling Price | 0 | |
Subsequent Event | NYMEX Oil Collar Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 335 | |
Derivative, Weighted-Average Floor Price | 65 | |
Derivative, Weighted-Average Ceiling Price | 78.61 | |
Subsequent Event | NYMEX Oil Collar Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 344 | |
Derivative, Weighted-Average Floor Price | 65 | |
Derivative, Weighted-Average Ceiling Price | 76.45 | |
Subsequent Event | NYMEX Oil Collar Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Weighted-Average Floor Price | 0 | |
Derivative, Weighted-Average Ceiling Price | 0 | |
Subsequent Event | NYMEX Oil Collar Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Weighted-Average Floor Price | 0 | |
Derivative, Weighted-Average Ceiling Price | 0 | |
Subsequent Event | WTI Midland NYMEX WTI | Oil Basis Swap Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Midland NYMEX WTI | Oil Basis Swap Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Midland NYMEX WTI | Oil Basis Swap Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Midland NYMEX WTI | Oil Basis Swap Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Midland NYMEX WTI | Oil Basis Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 941 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.15 | |
Subsequent Event | WTI Midland NYMEX WTI | Oil Basis Swap Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 0 | |
Subsequent Event | WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 684 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 1.95 | |
Subsequent Event | WTI Houston MEH NYMEX WTI | Oil Basis Swap Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 816 | |
Derivative, Oil Basis Swap, Weighted-Average Contract Price | 2.10 | |
Subsequent Event | NYMEX HH | Gas Swaps Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | NYMEX HH | Gas Swaps Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | NYMEX HH | Gas Swaps Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 1,530 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 2.99 | |
Subsequent Event | NYMEX HH | Gas Swaps Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | NYMEX HH | Gas Swaps Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | NYMEX HH | Gas Swaps Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | NYMEX HH | Gas Collar Contract, First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 0 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 0 | |
Subsequent Event | NYMEX HH | Gas Collar Contract, Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 0 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 0 | |
Subsequent Event | NYMEX HH | Gas Collar Contract, Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 0 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 0 | |
Subsequent Event | NYMEX HH | Gas Collar Contract, Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 1,612 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 3 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 4.02 | |
Subsequent Event | NYMEX HH | Gas Collar Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 4,838 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 3 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 4.22 | |
Subsequent Event | NYMEX HH | Gas Collar Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Weighted-Average Floor Price | $ / EnergyContent | 0 | |
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent | 0 | |
Subsequent Event | IF HSC NYMEX HH | Gas Basis Swap Contract, First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | IF HSC NYMEX HH | Gas Basis Swap Contract, Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | IF HSC NYMEX HH | Gas Basis Swap Contract, Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | IF HSC NYMEX HH | Gas Basis Swap Contract, Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | IF HSC NYMEX HH | Gas Basis Swap Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 946 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0.0025 | |
Subsequent Event | IF HSC NYMEX HH | Gas Basis Swap Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | $ / EnergyContent | 0 | |
Subsequent Event | OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 254 | |
Derivative, Swap Type, Weighted-Average Contract Price | 32.33 | |
Subsequent Event | OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 322 | |
Derivative, Swap Type, Weighted-Average Contract Price | 32.57 | |
Subsequent Event | OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 336 | |
Derivative, Swap Type, Weighted-Average Contract Price | 32.54 | |
Subsequent Event | OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 364 | |
Derivative, Swap Type, Weighted-Average Contract Price | 32.49 | |
Subsequent Event | OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 396 | |
Derivative, Swap Type, Weighted-Average Contract Price | 32.86 | |
Subsequent Event | OPIS Propane Mont Belvieu Non-TET | NGL Swaps Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
Subsequent Event | OPIS Normal Butane Mont Belvieu Non-TET | NGL Swaps Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 28 | |
Derivative, Swap Type, Weighted-Average Contract Price | 39.48 | |
Subsequent Event | OPIS Normal Butane Mont Belvieu Non-TET | NGL Swaps Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 44 | |
Derivative, Swap Type, Weighted-Average Contract Price | 39.48 | |
Subsequent Event | OPIS Normal Butane Mont Belvieu Non-TET | NGL Swaps Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 46 | |
Derivative, Swap Type, Weighted-Average Contract Price | 39.48 | |
Subsequent Event | OPIS Normal Butane Mont Belvieu Non-TET | NGL Swaps Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 49 | |
Derivative, Swap Type, Weighted-Average Contract Price | 39.48 | |
Subsequent Event | OPIS Normal Butane Mont Belvieu Non-TET | NGL Swaps Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 45 | |
Derivative, Swap Type, Weighted-Average Contract Price | 39.48 | |
Subsequent Event | OPIS Normal Butane Mont Belvieu Non-TET | NGL Swaps Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 | |
Subsequent Event | OPIS Isobutane Mont Belvieu Non-TET | NGL Swaps Contract First Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 15 | |
Derivative, Swap Type, Weighted-Average Contract Price | 41.58 | |
Subsequent Event | OPIS Isobutane Mont Belvieu Non-TET | NGL Swaps Contract Second Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 24 | |
Derivative, Swap Type, Weighted-Average Contract Price | 41.58 | |
Subsequent Event | OPIS Isobutane Mont Belvieu Non-TET | NGL Swaps Contract Third Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 25 | |
Derivative, Swap Type, Weighted-Average Contract Price | 41.58 | |
Subsequent Event | OPIS Isobutane Mont Belvieu Non-TET | NGL Swaps Contract Fourth Quarter, Year 1 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 28 | |
Derivative, Swap Type, Weighted-Average Contract Price | 41.58 | |
Subsequent Event | OPIS Isobutane Mont Belvieu Non-TET | NGL Swaps Contract, Year 2 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 25 | |
Derivative, Swap Type, Weighted-Average Contract Price | 41.58 | |
Subsequent Event | OPIS Isobutane Mont Belvieu Non-TET | NGL Swaps Contract, Year 3 | ||
Derivative Financial Instruments | ||
Derivative, Nonmonetary Notional Amount, Volume | bbl | 0 | |
Derivative, Swap Type, Weighted-Average Contract Price | 0 |
Derivative Financial Instrume_4
Derivative Financial Instruments Fair Value (Details) $ in Thousands | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 |
Fair value of derivative assets and liabilities | |||
Derivative, fair value, net | $ 57,100 | $ 15,800 | |
Derivative assets, current | 56,442 | 48,677 | |
Derivative assets, noncurrent | 8,672 | 24,465 | |
Total derivative assets | 65,114 | 73,142 | |
Derivative liabilities, current | 6,789 | 56,181 | |
Derivative liabilities, noncurrent | 1,273 | 1,142 | |
Total derivative liabilities | (8,062) | (57,323) | |
Derivative asset, amounts not offset in the accompanying balance sheets | (7,362) | (26,136) | |
Derivative liabilities, amounts not offset in the accompanying balance sheets | 7,362 | 26,136 | |
Derivative asset, fair value, net amounts | 57,752 | 47,006 | |
Derivative liabilities, fair value, net amounts | (700) | (31,187) | |
Not Designated as Hedging Instrument | |||
Fair value of derivative assets and liabilities | |||
Derivative assets, current | 56,442 | 48,677 | |
Derivative assets, noncurrent | 8,672 | 24,465 | |
Derivative liabilities, current | 6,789 | 56,181 | |
Derivative liabilities, noncurrent | $ 1,273 | $ 1,142 | |
Designated as Hedging Instrument | |||
Fair value of derivative assets and liabilities | |||
Derivative, number of instruments held | 0 | 0 | 0 |
Fair Value, Recurring | Fair Value, Inputs, Level 2 | Not Designated as Hedging Instrument | |||
Fair value of derivative assets and liabilities | |||
Total derivative assets | $ 65,114 | $ 73,142 | |
Total derivative liabilities | $ 8,062 | $ 57,323 |
Derivative Financial Instrume_5
Derivative Financial Instruments Gains and Losses (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Derivative Instruments, (Gain) Loss [Line Items] | |||
Net derivative settlement (gain) loss | $ (26,921) | $ 710,700 | $ 748,958 |
Net derivative (gain) loss | (68,154) | 374,012 | 901,659 |
Oil Contracts | |||
Derivative Instruments, (Gain) Loss [Line Items] | |||
Net derivative settlement (gain) loss | 26,873 | 514,641 | 523,245 |
Net derivative (gain) loss | (20,813) | 284,863 | 650,959 |
Gas Contracts | |||
Derivative Instruments, (Gain) Loss [Line Items] | |||
Net derivative settlement (gain) loss | (49,156) | 171,598 | 152,361 |
Net derivative (gain) loss | (42,713) | 82,769 | 172,248 |
NGL Contracts | |||
Derivative Instruments, (Gain) Loss [Line Items] | |||
Net derivative settlement (gain) loss | (4,638) | 24,461 | 73,352 |
Net derivative (gain) loss | $ (4,628) | $ 6,380 | $ 78,452 |
Derivative Financial Instrume_6
Derivative Financial Instruments Credit Facility (Details) | Dec. 31, 2023 |
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |
Percentage of proved property secured for credit facility borrowing | 85% |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Jun. 23, 2021 | Aug. 20, 2018 | Sep. 12, 2016 | May 21, 2015 | |
Assets: | |||||||
Derivative Assets, Fair Value, Gross Asset | $ 65,114 | $ 73,142 | |||||
Liabilities: | |||||||
Derivative Liability, Fair Value, Gross Liability | (8,062) | (57,323) | |||||
Oil and Gas Properties | |||||||
Property, Plant, and Equipment, Fair Value Disclosure | 0 | 0 | |||||
Impairment | $ 0 | $ 7,468 | $ 35,000 | ||||
5.625% Senior Unsecured Notes Due 2025 | |||||||
Debt Instrument, Fair Value Disclosure [Abstract] | |||||||
Senior Notes, interest rate, stated percentage | 5.625% | 5.625% | 5.625% | ||||
Senior Notes, Principal amount | $ 349,118 | $ 349,118 | $ 500,000 | ||||
Fair value | $ 348,189 | $ 337,821 | |||||
6.75% Senior Unsecured Notes Due 2026 | |||||||
Debt Instrument, Fair Value Disclosure [Abstract] | |||||||
Senior Notes, interest rate, stated percentage | 6.75% | 6.75% | 6.75% | ||||
Senior Notes, Principal amount | $ 419,235 | $ 419,235 | $ 500,000 | ||||
Fair value | $ 420,660 | $ 409,484 | |||||
6.625% Senior Unsecured Notes Due 2027 | |||||||
Debt Instrument, Fair Value Disclosure [Abstract] | |||||||
Senior Notes, interest rate, stated percentage | 6.625% | 6.625% | 6.625% | ||||
Senior Notes, Principal amount | $ 416,791 | $ 416,791 | $ 500,000 | ||||
Fair value | $ 416,549 | $ 402,120 | |||||
6.5% Senior Unsecured Notes Due 2028 | |||||||
Debt Instrument, Fair Value Disclosure [Abstract] | |||||||
Senior Notes, interest rate, stated percentage | 6.50% | 6.50% | 6.50% | ||||
Senior Notes, Principal amount | $ 400,000 | $ 400,000 | $ 400,000 | ||||
Fair value | 401,372 | 384,520 | |||||
Not Designated as Hedging Instrument | Fair Value, Recurring | Fair Value, Inputs, Level 1 | |||||||
Assets: | |||||||
Derivative Assets, Fair Value, Gross Asset | 0 | 0 | |||||
Liabilities: | |||||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||||
Not Designated as Hedging Instrument | Fair Value, Recurring | Fair Value, Inputs, Level 2 | |||||||
Assets: | |||||||
Derivative Assets, Fair Value, Gross Asset | 65,114 | 73,142 | |||||
Liabilities: | |||||||
Derivative Liability, Fair Value, Gross Liability | 8,062 | 57,323 | |||||
Not Designated as Hedging Instrument | Fair Value, Recurring | Fair Value, Inputs, Level 3 | |||||||
Assets: | |||||||
Derivative Assets, Fair Value, Gross Asset | 0 | 0 | |||||
Liabilities: | |||||||
Derivative Liability, Fair Value, Gross Liability | $ 0 | $ 0 |
Earnings Per Share (Details)
Earnings Per Share (Details) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||||
Jan. 15, 2021 | Dec. 31, 2023 USD ($) $ / shares shares | Dec. 31, 2022 USD ($) $ / shares shares | Dec. 31, 2021 USD ($) $ / shares shares | Jun. 30, 2023 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Class of Warrant or Right, Date from which Warrants or Rights Exercisable | Jan. 15, 2021 | ||||
Earnings Per Share Reconciliation [Abstract] | |||||
Net income | $ | $ 817,880 | $ 1,111,952 | $ 36,229 | ||
Basic weighted-average common shares outstanding | 118,678 | 122,351 | 119,043 | ||
Dilutive effect of non-vested RSUs, contingent PSUs, and other | 553 | 1,714 | 2,582 | ||
Dilutive effect of Warrants | 9 | 19 | 2,065 | ||
Diluted weighted-average common shares outstanding | 119,240 | 124,084 | 123,690 | ||
Basic net income per common share | $ / shares | $ 6.89 | $ 9.09 | $ 0.30 | ||
Diluted net income per common share | $ / shares | $ 6.86 | $ 8.96 | $ 0.29 | ||
Warrants and Rights Outstanding, Maturity Date | Jun. 30, 2023 | ||||
Performance Shares (PSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting period | 3 years | ||||
Multiplier applied to PSU awards at settlement | 2 | 1 | |||
Minimum | Performance Shares (PSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Multiplier applied to PSU awards at settlement | 0 | ||||
Maximum | Performance Shares (PSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Multiplier applied to PSU awards at settlement | 2 |
Compensation Plans_ Stock Based
Compensation Plans: Stock Based (Details) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 USD ($) shares $ / shares | Dec. 31, 2022 USD ($) shares $ / shares | Dec. 31, 2021 USD ($) shares $ / shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares available for grant | 2,800,000 | ||
Impact outright issuance of one share has on number of available shares | 1 | ||
Performance Shares (PSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum impact of issuance of one performance share award on available shares under the equity incentive plan | 2 | ||
Multiplier applied to PSU awards at settlement | 2 | 1 | |
Stock-based compensation expense | $ | $ 2.8 | $ 2.6 | $ 6 |
Unrecognized stock based compensation expense | $ | 8.6 | ||
Fair value of PSUs/RSUs granted in period | $ | $ 7.7 | $ 7.4 | |
Award vesting period | 3 years | ||
Non-vested at beginning of year (in shares) | 273,258 | 464,483 | 830,464 |
Non-vested outstanding at beginning of year grant date fair value ($/share) | $ / shares | $ 26.67 | $ 12.80 | $ 17.52 |
Granted (in shares) | 256,633 | 276,010 | 0 |
Granted grant date fair value ($/share) | $ / shares | $ 29.93 | $ 26.67 | $ 0 |
Vested (in shares) | (15,950) | (461,387) | (352,395) |
Vested grant date fair value ($/share) | $ / shares | $ 25.50 | $ 12.81 | $ 23.81 |
Forfeited (in shares) | (44,509) | (5,848) | (13,586) |
Forfeited grant date fair value ($/share) | $ / shares | $ 26.45 | $ 18.24 | $ 15.46 |
Non-vested at end of year (in shares) | 469,432 | 273,258 | 464,483 |
Non-vested outstanding at end of year grant date fair value ($/share) | $ / shares | $ 27.83 | $ 26.67 | $ 12.80 |
Performance share units, shares settled gross of shares for tax withholdings | 1,004,410 | 347,742 | |
Shares held for settlement of income and payroll tax obligations (in shares) | (349,487) | (112,919) | |
Shares Issued in Period | 0 | 654,923 | 234,823 |
Fair value of PSUs/RSUs Vested in Period | $ | $ 12.3 | $ 8.4 | |
Multiplier assumed | 1 | 1 | 1 |
Performance Shares (PSUs) | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Multiplier applied to PSU awards at settlement | 0 | ||
Performance Shares (PSUs) | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Multiplier applied to PSU awards at settlement | 2 | ||
Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Retirement vesting Increment | 6 months | ||
Retirement increment vesting period | 6 months | ||
Stock-based compensation expense | $ | $ 14.8 | $ 13.5 | $ 10.2 |
Unrecognized stock based compensation expense | $ | 25.7 | ||
Fair value of PSUs/RSUs granted in period | $ | $ 20.2 | $ 18 | $ 17 |
Non-vested at beginning of year (in shares) | 1,375,052 | 1,841,237 | 2,097,860 |
Non-vested outstanding at beginning of year grant date fair value ($/share) | $ / shares | $ 22.42 | $ 13.79 | $ 8.83 |
Granted (in shares) | 630,474 | 526,776 | 666,052 |
Granted grant date fair value ($/share) | $ / shares | $ 32.03 | $ 34.08 | $ 25.52 |
Vested (in shares) | (805,205) | (920,927) | (843,098) |
Vested grant date fair value ($/share) | $ / shares | $ 16.75 | $ 12.17 | $ 11 |
Forfeited (in shares) | (119,777) | (72,034) | (79,577) |
Forfeited grant date fair value ($/share) | $ / shares | $ 29.26 | $ 18.24 | $ 10.64 |
Non-vested at end of year (in shares) | 1,080,544 | 1,375,052 | 1,841,237 |
Non-vested outstanding at end of year grant date fair value ($/share) | $ / shares | $ 31.49 | $ 22.42 | $ 13.79 |
Performance share units, shares settled gross of shares for tax withholdings | 803,449 | 920,927 | 843,098 |
Shares held for settlement of income and payroll tax obligations (in shares) | (249,233) | (284,423) | (250,349) |
Shares Issued in Period | 554,216 | 636,504 | 592,749 |
Number of Shares Represented by Each RSU | 1 | ||
Fair value of PSUs/RSUs Vested in Period | $ | $ 13.5 | $ 11.2 | $ 9.3 |
Director Shares (Details)
Director Shares (Details) - Director - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares issued to directors | 56,872 | 29,471 | 60,510 |
Stock-based compensation expense | $ 1.6 | $ 1.5 | $ 1.2 |
Employee Stock Purchase Plan (D
Employee Stock Purchase Plan (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares available for grant | 2,800,000 | ||
Employee Stock Purchase Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum employee subscription rate | 15% | ||
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares Per Employee | 2,500 | ||
Maximum employee subscription | $ 25,000 | ||
Purchase price of common stock, percent | 85% | ||
Issuance of common stock under Employee Stock Purchase Plan (Shares) | 114,427 | 113,785 | 313,773 |
Proceeds from issuance of shares under incentive and share-based compensation plans, excluding stock options | $ 3,100,000 | $ 3,000,000 | $ 2,600,000 |
Shares available for grant | 3,300,000 | ||
Stock-based compensation expense | $ 1,100,000 | $ 1,200,000 | $ 1,400,000 |
Risk free interest rate | 5.10% | 1.20% | 0.80% |
Dividend yield | 1.80% | 0.10% | 0.30% |
Volatility factor of the expected market price of the Company's common stock | 53.60% | 69.10% | 106.10% |
Expected life (in years) | 6 months | 6 months | 6 months |
401(k) Plan (Details)
401(k) Plan (Details) - 401K Plan - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Defined Contribution Plan, maximum annual contributions per employee, percent | 60% | ||
Defined Contribution Plan, employer matching contribution, percent of employees' gross pay | 6% | ||
Defined Contribution Plan, matching contributions | $ 5.7 | $ 5.5 | $ 3.9 |
Prior to 2014 | |||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Defined Contribution Plan, employer matching contribution, percent of match | 100% | ||
After 2014 | |||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Defined Contribution Plan, employer matching contribution, percent of match | 150% |
Pension Benefits (Details)
Pension Benefits (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||
Defined Benefit Plan, service cost | $ 3,706,000 | $ 4,652,000 | $ 4,455,000 | |
Defined Benefit Plan, interest cost | 3,200,000 | 2,314,000 | 2,089,000 | |
Defined Benefit Plan, actuarial (gain) loss | 84,000 | (15,567,000) | ||
Defined Benefit Plan, benefits paid | (4,883,000) | (1,998,000) | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Defined Benefit Plan, fair value of plan assets at beginning of year | 36,414,000 | 35,941,000 | ||
Defined Benefit Plan, actual return on plan assets | 4,161,000 | (3,529,000) | ||
Defined Benefit Plan, employer contribution | 10,000,000 | 6,000,000 | 6,600,000 | |
Defined Benefit Plan, Plan Assets, Benefits Paid | (4,883,000) | (1,998,000) | (6,300,000) | |
Defined Benefit Plan, fair value of plan assets at end of year | 45,692,000 | 36,414,000 | 35,941,000 | |
Defined Benefit Plan, funded status at end of year | (21,576,000) | (28,747,000) | ||
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract] | ||||
Defined Benefit Plan, projected benefit obligation | 67,268,000 | 65,161,000 | 75,760,000 | |
Defined Benefit Plan, accumulated benefit obligation | 55,557,000 | 55,712,000 | ||
Defined Benefit Plan, underfunded accumulated benefit obligation | $ 9,865,000 | 19,298,000 | ||
Defined Benefit Plan, unrecognized net gain (loss) amortization threshold | 10% | |||
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income [Abstract] | ||||
Defined Benefit Plan, unrecognized actuarial losses | $ 3,300,000 | 5,100,000 | ||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||
Other Comprehensive Income (Loss), Defined Benefit Plan, net actuarial gain (loss) | 1,737,000 | 10,327,000 | (612,000) | |
Other Comprehensive Income (Loss), Defined Benefit Plan, amortization of prior service cost | 0 | 0 | 13,000 | |
Other Comprehensive Income (Loss), Defined Benefit Plan, amortization of net actuarial loss | 68,000 | 931,000 | 1,240,000 | |
Other Comprehensive Income (Loss), Defined Benefit Plan, settlements | 0 | 0 | 312,000 | |
Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, pre-tax | 1,805,000 | 11,258,000 | 953,000 | |
Other Comprehensive Income (Loss), Defined Benefit Plan, tax (expense) benefit | (390,000) | (2,431,000) | (204,000) | |
Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, net | [1] | 1,415,000 | 8,827,000 | 749,000 |
Components of Net Periodic Benefit Costs for Both Pension Plans | ||||
Defined Benefit Plan, service cost | 3,706,000 | 4,652,000 | 4,455,000 | |
Defined Benefit Plan, interest cost | 3,200,000 | 2,314,000 | 2,089,000 | |
Defined Benefit Plan, expected return on plan assets that reduces periodic pension benefit cost | (2,340,000) | (1,711,000) | (1,474,000) | |
Defined Benefit Plan, amortization of prior service cost | 0 | 0 | 13,000 | |
Defined Benefit Plan, amortization of net actuarial loss | 68,000 | 931,000 | 1,240,000 | |
Defined Benefit Plan, net periodic benefit cost | 4,634,000 | 6,186,000 | 6,323,000 | |
Defined Benefit Plan, settlements | 0 | 0 | 312,000 | |
Defined Benefit Plan, Total Net Benefit Cost | $ 4,634,000 | $ 6,186,000 | $ 6,635,000 | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, discount rate | 5% | 5.20% | ||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, rate of compensation increase | 3.50% | 3.50% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, discount rate | 5.20% | 3.10% | 2.90% | |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, expected return on plan assets | 6.30% | 3.60% | 4.40% | |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, rate of compensation increase | 3.50% | 4.80% | 4.40% | |
Defined Benefit Plan, Expected Future Employer Contributions [Abstract] | ||||
Defined Benefit Plan, Expected Future Contributions in Next Fiscal Year | $ 10,600,000 | |||
Future Benefit Payments | ||||
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 6,865,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 4,455,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 7,064,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 5,026,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 5,281,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | $ 25,587,000 | |||
Fair Value Recurring Basis Unobservable Input Reconciliation Asset Gain Loss Statement Of Other Comprehensive Income Extensible List Not Disclosed Flag | Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, net | Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, net | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Interest Cost, Statement of Income or Comprehensive Income [Extensible Enumeration] | General and administrative | General and administrative | General and administrative | |
Defined Benefit Plan, Net Periodic Benefit (Cost) Credit, Expected Return (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | General and administrative | General and administrative | General and administrative | |
Defined Benefit Plan, Net Periodic Benefit (Cost) Credit, Amortization of Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | General and administrative | General and administrative | General and administrative | |
Defined Benefit Plan, Net Periodic Benefit (Cost) Credit, Settlement Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | General and administrative | General and administrative | General and administrative | |
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | General and administrative | General and administrative | ||
Nonqualified Plan | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Defined Benefit Plan, fair value of plan assets at beginning of year | $ 0 | $ 0 | ||
Defined Benefit Plan, fair value of plan assets at end of year | $ 0 | $ 0 | $ 0 | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, expected return on plan assets | 0% | 0% | 0% | |
Defined Benefit Plan, Equity Securities | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Defined Benefit Plan, fair value of plan assets at beginning of year | $ 17,127,000 | |||
Defined Benefit Plan, fair value of plan assets at end of year | 19,629,000 | $ 17,127,000 | ||
Fixed Income Securities | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Defined Benefit Plan, fair value of plan assets at beginning of year | 7,670,000 | |||
Defined Benefit Plan, fair value of plan assets at end of year | 11,646,000 | 7,670,000 | ||
Other Securities | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Defined Benefit Plan, fair value of plan assets at beginning of year | 11,617,000 | |||
Defined Benefit Plan, fair value of plan assets at end of year | $ 14,417,000 | $ 11,617,000 | ||
[1] Please refer to Note 11 – Pension Benefits for additional discussion of the pension liability adjustment. |
Pension Benefits Fair Value of
Pension Benefits Fair Value of Plan Assets in Heirarchy (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 100% | ||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 100% | 100% | |
Defined Benefit Plan, Plan Assets, Amount | $ 45,692,000 | $ 36,414,000 | $ 35,941,000 |
Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 29,590,000 | 26,409,000 | |
Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 9,389,000 | 3,208,000 | |
Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 6,713,000 | 6,797,000 | 6,195,000 |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases | 0 | 400,000 | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Realized Gain on Assets | 364,000 | 259,000 | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Unrealized Loss on Assets | (448,000) | (57,000) | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Disposition | $ 0 | $ 0 | |
Defined Benefit Plan, Equity Securities, US | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 20.30% | 20.70% | |
Defined Benefit Plan, Plan Assets, Amount | $ 9,280,000 | $ 7,533,000 | |
Defined Benefit Plan, Equity Securities, US | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 6,097,000 | 5,012,000 | |
Defined Benefit Plan, Equity Securities, US | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 3,183,000 | 2,521,000 | |
Defined Benefit Plan, Equity Securities, US | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | |
Defined Benefit Plan, Equity Securities, Non-US | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 22.70% | 26.40% | |
Defined Benefit Plan, Plan Assets, Amount | $ 10,349,000 | $ 9,594,000 | |
Defined Benefit Plan, Equity Securities, Non-US | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 10,349,000 | 9,594,000 | |
Defined Benefit Plan, Equity Securities, Non-US | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Defined Benefit Plan, Equity Securities, Non-US | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | |
Defined Benefit Plan, Equity Securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 49% | ||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 43% | 47.10% | |
Defined Benefit Plan, Plan Assets, Amount | $ 19,629,000 | $ 17,127,000 | |
Defined Benefit Plan, Equity Securities | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 16,446,000 | 14,606,000 | |
Defined Benefit Plan, Equity Securities | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 3,183,000 | 2,521,000 | |
Defined Benefit Plan, Equity Securities | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | |
Core fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 25.50% | 14.30% | |
Defined Benefit Plan, Plan Assets, Amount | $ 11,646,000 | $ 5,220,000 | |
Core fixed income | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 11,646,000 | 5,220,000 | |
Core fixed income | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Core fixed income | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | |
Corporate Debt Securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 0% | 6.70% | |
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 2,450,000 | |
Corporate Debt Securities | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 2,450,000 | |
Corporate Debt Securities | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Corporate Debt Securities | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | |
Total fixed income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 26% | ||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 25.50% | 21% | |
Defined Benefit Plan, Plan Assets, Amount | $ 11,646,000 | $ 7,670,000 | |
Total fixed income securities | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 11,646,000 | 7,670,000 | |
Total fixed income securities | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Total fixed income securities | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | |
Defined Benefit Plan, Real Estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 4.60% | 6.80% | |
Defined Benefit Plan, Plan Assets, Amount | $ 2,116,000 | $ 2,476,000 | |
Defined Benefit Plan, Real Estate | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Defined Benefit Plan, Real Estate | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Defined Benefit Plan, Real Estate | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 2,116,000 | $ 2,476,000 | |
Defined Benefit Plan, Common Collective Trust | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 13.60% | 1.90% | |
Defined Benefit Plan, Plan Assets, Amount | $ 6,206,000 | $ 687,000 | |
Defined Benefit Plan, Common Collective Trust | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Defined Benefit Plan, Common Collective Trust | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 6,206,000 | 687,000 | |
Defined Benefit Plan, Common Collective Trust | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | |
Hedge fund | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 13.30% | 23.20% | |
Defined Benefit Plan, Plan Assets, Amount | $ 6,095,000 | $ 8,454,000 | |
Hedge fund | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1,498,000 | 4,133,000 | |
Hedge fund | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Hedge fund | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 4,597,000 | $ 4,321,000 | |
Total other securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 25% | ||
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage | 31.50% | 31.90% | |
Defined Benefit Plan, Plan Assets, Amount | $ 14,417,000 | $ 11,617,000 | |
Total other securities | Fair Value, Inputs, Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1,498,000 | 4,133,000 | |
Total other securities | Fair Value, Inputs, Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 6,206,000 | 687,000 | |
Total other securities | Fair Value, Inputs, Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 6,713,000 | 6,797,000 | |
Nonqualified Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | $ 0 |
Leases Lease Parameter (Details
Leases Lease Parameter (Details) | Dec. 31, 2023 |
Lessee, Lease, Description [Line Items] | |
Optional extension period | 10 years |
Minimum | |
Lessee, Lease, Description [Line Items] | |
Remaining lease term | 1 year |
Maximum | |
Lessee, Lease, Description [Line Items] | |
Remaining lease term | 9 years |
Components of total lease cost
Components of total lease cost (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Lessee Disclosure [Abstract] | ||
Operating lease cost | $ 15,625 | $ 10,174 |
Short-term lease cost (1) | 251,628 | 175,098 |
Variable lease cost (2) | 11,838 | 7,085 |
Total lease cost | 279,091 | 192,357 |
Operating cash flows related to operating leases | 4,181 | 4,718 |
Investing cash flows related to operating leases | $ 11,300 | $ 5,042 |
Operating lease liability matur
Operating lease liability maturities (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
Lessee Disclosure [Abstract] | |
Operating lease liability payments, Year One | $ 17,208 |
Operating lease liability payments, Year Two | 11,242 |
Operating lease liability payments, Year Three | 4,793 |
Operating lease liability payments, Year Four | 2,685 |
Operating lease liability payments, Year Five | 2,054 |
Operating lease liability payments, due thereafter | 6,906 |
Total Lease payments | 44,888 |
Imputed interest | (5,110) |
Total operating lease liability | $ 39,778 |
Balance Sheet information relat
Balance Sheet information related to operating leases (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Lessee Disclosure [Abstract] | ||
Other noncurrent assets | $ 32,264 | $ 26,368 |
Other current liabilities | 15,425 | 10,114 |
Other noncurrent liabilities | 24,352 | 23,621 |
Right-of-use assets obtained in exchange for new operating lease liabilities | $ 19,341 | $ 16,186 |
Weighted-average discount rate | 6.20% | 5.80% |
Weighted average remaining lease term | 4 years | 5 years |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other noncurrent assets | Other noncurrent assets |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | Other current liabilities | Other current liabilities |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | Other noncurrent liabilities | Other noncurrent liabilities |
Accounts Receivable (Details)
Accounts Receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Accounts Receivable | ||
Accounts receivable from contracts with customers | $ 231,165 | $ 233,297 |
Oil, gas, and NGL production revenue | ||
Accounts Receivable | ||
Accounts receivable from contracts with customers | 175,334 | 184,458 |
Amounts due from joint interest owners | ||
Accounts Receivable | ||
Accounts receivable from contracts with customers | 46,289 | 45,997 |
Other | ||
Accounts Receivable | ||
Accounts receivable from contracts with customers | $ 9,542 | $ 2,842 |
Accounts Payable and Accrued Ex
Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Accounts Payable and Accrued Liabilities, Current [Abstract] | ||
Drilling and lease operating cost accruals | $ 144,707 | $ 125,570 |
Trade accounts payable | 107,315 | 43,898 |
Revenue and severance tax payable | 186,663 | 182,744 |
Property taxes | 43,406 | 43,066 |
Compensation | 54,819 | 35,799 |
Net derivative settlements | 1,129 | 22,745 |
Interest | 35,976 | 35,992 |
Dividends Payable, Current | 20,834 | 18,290 |
Other | 16,749 | 24,185 |
Total accounts payable and accrued expenses | $ 611,598 | $ 532,289 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning asset retirement obligations | $ 115,313 | $ 101,424 |
Liabilities incurred (1) | 4,062 | 2,086 |
Liabilities settled (2) | (4,489) | (6,356) |
Accretion expense | 6,330 | 5,344 |
Revision to estimated cash flows | 1,938 | 12,815 |
Ending asset retirement obligations (3) | 123,154 | 115,313 |
Current asset retirement obligation liability | $ 4,400 | $ 7,100 |
Suspended Well Costs (Details)
Suspended Well Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Net changes in capitalized exploratory well costs | |||
Beginning balance | $ 49,047 | $ 15,576 | $ 5,698 |
Additions to capitalized exploratory well costs pending the determination of net proved reserves | 70,762 | 49,047 | 15,576 |
Reclassifications based on the determination of net proved reserves | (47,985) | (14,721) | (5,698) |
Capitalized exploratory well costs charged to expense (1) | (455) | (855) | 0 |
Ending balance | 71,369 | $ 49,047 | $ 15,576 |
Exploratory well costs capitalized for more than one year | $ 0 |
Acquisitions (Details)
Acquisitions (Details) $ in Millions | 12 Months Ended | |
Jun. 30, 2023 a | Dec. 31, 2023 USD ($) | |
Asset Acquisition [Line Items] | ||
Net Acres Acquired | a | 20,000 | |
Asset Acquisition, Consideration Transferred | $ | $ (109.9) | |
Q2 2023 Dawson and Martin County Asset Acquisition | ||
Asset Acquisition [Line Items] | ||
Asset Acquisition, Effective Date of Acquisition | Jun. 30, 2023 |
Nonmonetary Transactions (Detai
Nonmonetary Transactions (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Nonmonetary Transaction [Line Items] | |
Basis of Accounting for Assets Transferred | carryover basis |
Gain (Loss) Recognized on Transfer | $ 0 |