SM Energy Co

To the Stockholders and the Board of Directors of SM Energy Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 22, 2024 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or is required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Depletion, Depreciation and Amortization (“DD&A”) of Proved Oil and Gas Properties

/s/Ernst & Young LLP

We have served as the Company’s auditor since 2012.

Denver, Colorado

February 22, 2024

(in thousands, except share data)

(in thousands, except per share data)

(in thousands)

(1)Please refer to Note 11 – Pension Benefits for additional discussion of the pension liability adjustment.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands, except share data and dividends per share)

(in thousands)

(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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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 Measurementsfor 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 to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the Company’s accounts.

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 Instrumentsfor 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 Taxesfor 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.

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:

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 areno 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.

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:

(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:

Note 4 – Income Taxes

The provision for income taxes consisted of the following:

The components of the net deferred tax liabilities are as follows:

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:

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:

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.

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:

(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”):

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 Incurredin Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report for additional information.

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:

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.

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:

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:

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:

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:

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 hadno 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:

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.

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:

(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 Policiesfor 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 Instrumentsfor more information regarding the Company’s derivative instruments.

Oil and Gas Properties and Other Property and Equipment

The Company hadno 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 Policiesfor 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.

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 thethree-year performance period, a number of shares of the Company’s common stock that may range from zero totwo times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to 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:

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 asone share against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count astwo 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 totwo times the number of PSUs awarded and is determined based on certain criteria over athree-year performance period. PSUs generally vest on the third anniversary of the grant date 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, on the grant date of a PSU award vest in pro-rata increments on a daily basis over thethree-year performance period beginning at the grant date, and any non-vested portions of a PSU award will be forfeited if the employee leaves the Company.

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 thethree-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the path the stock price may take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three-year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers.

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 thethree-year performance period: the Company’s Total Shareholder Return (“TSR”) relative to the TSR of certain peer companies, the Company’s absolute TSR, free cash flow (“FCF”) generation, and the achievement of certain ESG targets, in each case as defined by the award agreement. The relative and absolute TSR portions of the fair value of the PSUs granted in 2023 and 2022, were measured on the grant date using the GBM Model. The portion of the awards associated with FCF generation and ESG performance conditions assumes that target amounts will be met at the end of the performance period. As a portion of these awards depends on performance-based settlement criteria, compensation expense may be adjusted in future periods as the expected number of shares of the Company’s common stock issued to settle the units increases or decreases based on the Company’s expected FCF generation and achievement of certain ESG targets.

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:

(1)The number of PSUs presented assumes a multiplier ofone. The actual final number of shares of common stock to be issued at the end of thethree-year performance period will range from zero totwo times the number of PSUs awarded depending on thethree-year performance multiplier.

(2)Amounts represent price per unit.

A summary of the shares of common stock issued to settle PSUs is presented in the table below:

(1)During the year ended December 31, 2023, there wereno 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 receiveone 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 insix-month increments over the applicable vesting period beginning at the grant date. Retirement eligible employees must stay with the Company through the entiresix-month vesting period to receive that increment of vesting and any non-vested portions of an RSU award will be forfeited when the employee leaves the Company.

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:

(1)Amounts represent price per unit.

A summary of the shares of common stock issued to settle RSUs is presented in the table below:

(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:

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 tosix 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.

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.

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 areno plan assets in the Nonqualified Pension Plan.

Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans

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:

Components of Net Periodic Benefit Cost for the Pension Plans

Pension Plan Assumptions

The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows:

The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows:

(1)There isno assumed expected return on plan assets for the Nonqualified Pension Plan because there areno 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:

There is no asset allocation of the Nonqualified Pension Plan since there areno 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:

(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):

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:

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 thanone 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.

(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:

Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2023, were as follows:

(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:

Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses

The components of accounts receivable are as follows:

The components of accounts payable and accrued expenses are as follows:

Note 14 – Asset Retirement Obligations

Please refer to Asset Retirement Obligations in Note 1 – Summary of Significant Accounting Policiesfor 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:

(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.

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:

(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 wereno material exploratory well costs that were capitalized for more than one year.

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 atcarryover basis withno gain or loss recognized.

Supplemental Oil and Gas Information (unaudited)

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:

(1)Includes facility costs of $24.1 million, $30.0 million, and $18.2 million for the years ended December 31, 2023, 2022, and 2021, respectively.

(2)Includes amounts related to leasing activity and acquiring surface rights outside of acquisitions of proved and unproved properties totaling $18.1 million, $4.2 million, and $5.8 million for the years ended December 31, 2023, 2022, and 2021, respectively.

(3)Includes amounts related to estimated asset retirement obligations of $6.0 million, $15.1 million, and $12.8 million for the years ended December 31, 2023, 2022, and 2021, respectively.

(4)Includes capitalized interest of $20.4 million, $17.6 million, and $15.0 million for the years ended December 31, 2023, 2022, and 2021, respectively.

Oil and Gas Reserve Quantities

The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting of reserve estimation and disclosure.

Proved reserves are the estimated quantities of oil, gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of the Company’s estimated net proved reserves are located in the United States.

The tables below present a summary of changes in the Company’s estimated net proved reserves for each of the years ended December 31, 2023, 2022, and 2021. The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the Company’s total calculated proved reserve PV-10 for each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

•113.9 MMBOE of infill reserves;

•65.3 MMBOE of positive performance revisions resulting from changes to decline curve estimates based on reservoir engineering analysis;

•28.0 MMBOE of negative performance revisions related to well performance;

•30.8 MMBOE of estimated net proved undeveloped reserves reclassified to unproved reserves categories resulting from revising certain aspects of the Company’s future development plans, and due to certain lease obligations; and

•28.4 MMBOE of negative price revisions resulting primarily from decreases in gas and NGL prices.

Please refer to Areas of Operation in Part I, Items 1 and 2 of this report, and to Oil and Gas Reserve Quantities in Critical Accounting Estimatesin Part II, Item 7 of this report for additional information.

•103.2 MMBOE of infill reserves;

•9.5 MMBOE of positive price revisions;

•19.9 MMBOE of estimated net proved undeveloped reserves reclassified to unproved reserves categories resulting from revising certain aspects of the Company’s future development plans; and

•11.1 MMBOE of negative performance revisions.

•74.4 MMBOE of infill reserves;

•37.2 MMBOE and 3.4 MMBOE of positive price and performance revisions, respectively; and

•40.6 MMBOE of estimated net proved undeveloped reserves reclassified to unproved reserves categories resulting from revising certain aspects of the Company’s future development plans.

Standardized Measure of Discounted Future Net Cash Flows

The Company computes a standardized measure of discounted future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual discount factor.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the estimated proved reserves in place at the end of the period using year end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities and estimated abandonment costs.

The assumptions used to compute the standardized measure of discounted future net cash flows are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure of discounted future net cash flows computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure of discounted future net cash flows:

The following summary sets forth the Company’s future net cash flows relating to proved oil, gas, and NGL reserves based on the standardized measure of discounted future net cash flows:

The principal sources of changes in the standardized measure of discounted future net cash flows were: