RANGE RESOURCES CORP

Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements, including the notes, have been prepared in accordance with generally accepted accounting principles ("U.S. GAAP") and include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period's presentation. These reclassifications have no impact on previously reported stockholders' equity, net income or cash flows.

Use of Estimates

The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods.

Estimated quantities of natural gas, NGLs and oil reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, NGLs and oil. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs and oil reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of natural gas, NGLs and oil that are ultimately recovered. See Note 16 for further detail.

Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, valuation of certain derivative instruments, exit cost liabilities and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Business Segment Information

We have evaluated how we are organized and managed and have identified only one operating segment. We consider our gathering, processing and marketing functions as integral to our natural gas, NGLs and oil producing activities. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. Our Chief Executive Officer is the Chief Operating Decision Maker ("CODM"). We measure financial performance as a single enterprise and not on an area-by-area basis. Our exploration and production operations are limited to onshore United States and all of our sales transfer title and control in the onshore United States. Income before income taxes as presented in the consolidated statements of income is the primary measure of segment profit and loss used by the CODM in assessing business performance and making capital allocation decisions by comparing actual amounts to historical results and previously forecasted financial information.

Revenue Recognition and Accounts Receivable

Natural gas, NGLs and oil sales revenues are recognized when control of the product is transferred to the customer and collectability is reasonably assured. See below for a more detailed summary of our product types.

Natural Gas and NGLs Sales. Under some of our gas processing contracts, we deliver natural gas to a midstream processing entity for processing. The midstream processing entity processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction. For those contracts that we have concluded that we are the principal, the ultimate third party is our customer, and we recognize revenue on a gross basis, with gathering, compression, processing and transportation fees presented as an expense. Alternatively, for those contracts that we have concluded that we are the agent, the midstream processing entity is our customer, and we recognize revenue based on the net amount of the proceeds received from the midstream processing entity.

In other natural gas processing agreements, we may elect to take our residue gas and/or NGLs in kind at the tailgate of the midstream entity’s processing plant and subsequently market the product on our own. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index-driven price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index-driven price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense.

Oil Sales. Our oil sales contracts are generally structured in one of the following ways:

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We sell oil production at the wellhead and collect an agreed-upon index-driven price, net of transportation incurred by the purchaser (that is, a netback arrangement). In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

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We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index-driven price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as transportation, gathering, processing and compression expense.

Brokered Natural Gas and Marketing. We realize brokered margins as a result of buying natural gas or NGLs utilizing separate purchase transactions, generally with separate counterparties, and subsequently selling that natural gas or NGLs under our existing contracts to fill our contract commitments or use existing infrastructure contracts to economically utilize available capacity. In these arrangements, we take control of the natural gas or NGLs purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas or NGLs are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Proceeds generated from the sale of excess firm transportation to third parties is also included here when we are determined to no longer be the primary obligor of such arrangement. Our net brokered margin was a loss of$7.5 million in 2024 compared to income of$3.7 million in 2023 and loss of $7.3 million in 2022.

The recognition of gains or losses on derivative instruments is not considered revenue from contracts with customers. We may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales or in limited cases may use them for contracts we intend to physically settle but that do not meet all of the criteria to be treated as normal sales.

Accounts Receivable. Our accounts receivable consist mainly of receivables from oil and gas purchasers and joint interest owners on properties we operate. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. However, this concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. Each reporting period, we assess the recoverability of material receivables using historical data and current market conditions. The loss given default method is used when, based on management’s judgment, an allowance for expected credit losses is accrued on material receivables to reflect the net amount to be collected. In certain instances, we require purchasers to post stand-by letters of credit. For receivables from joint interest owners, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We regularly review collectability and establish or adjust our allowance as necessary. We have allowances for doubtful accounts relating to exploration and production receivables of$255,000 at December 31, 2024 compared to$308,000 at December 31, 2023. We recorded bad debt expense of$50,000 in the year ended December 31, 2024, no bad debt expense in the year ended December 31, 2023 and a reduction of$250,000 in the year ended December 31, 2022.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as a financing activity on the consolidated statements of cash flows. Interest earned on cash equivalents is included in other income.

Natural Gas and Oil Properties

Property Acquisition Costs. We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to acquire mineral interests in natural gas and oil properties, to drill exploratory wells that find proved reserves and to drill development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of proved properties, including other property and equipment such as gathering lines related to natural gas, NGLs and oil producing activities, is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs.

Impairments. Our proved natural gas and oil properties are reviewed for impairment of value whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying value of the asset, an impairment loss is recognized based on the fair value of the asset. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. Natural gas and oil properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. There were no proved property impairment charges for the three-year period ended December 31, 2024.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management which could impact the number of locations we intend to drill. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Information such as reservoir performance or future plans to develop acreage is also considered. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of$819.7 million as of December 31, 2024 compared to$789.9 million in 2023. We have recorded abandonment and impairment expense related to unproved properties of$8.4 million in the year ended December 31, 2024 compared to$46.4 million in 2023 and$28.6 million in 2022.

Dispositions. Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets. Gain or loss recognized on dispositions is included in other income.

Other Property and Equipment

Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, internal-use software, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three toten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $1.4 million in the year ended December 31, 2024 compared to $1.5 million in the year ended December 31, 2023 and $2.2 million in the year ended December 31, 2022.

Leases

We determine if an arrangement is a lease at the inception of the arrangement. We lease certain drilling or completion equipment, office space, field equipment, vehicles and other equipment under cancelable and non-cancelable leases to support our operations. Certain of our lease agreements include lease and non-lease components. We account for these components as a single lease. Lease costs associated with drilling and completion equipment are capitalized as part of well costs.

Lease right-of-use ("ROU")assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of our lease contracts do not provide an implicit discount rate, we use our incremental borrowing rate which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at our discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with a term of 12 months or less are not recorded as a right-of-use asset and liability. The majority of our leases are classified as either short-term or long-term operating leases.

Our leased assets may be used in joint oil and gas operations with other working interest owners. We recognize lease liabilities and ROU assets only when we are the signatory to a contract as an operator of joint properties. Such lease liabilities and ROU assets are determined and disclosed based on gross contractual obligations. Our lease costs are also presented on a gross contractual basis. For additional information regarding our leases, see Note 13.

Other Assets

Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds include equity securities and money market instruments and are reported in other assets in the accompanying consolidated balance sheets.

Other assets at December 31, 2024 include $61.0 million of marketable securities held in our deferred compensation plan, $5.0 million of deferred financing costs related to our bank credit facility, $7.6 million of investments in surface acreage, $4.0 million of deferred tax assets and $2.0 million of other. Other assets at December 31, 2023 include $72.0 million of marketable securities held in our deferred compensation plan, $7.3 million of deferred financing costs related to our bank credit facility and $7.7 million of investments in surface acreage and $1.9 million of other.

Stock-based Compensation Arrangements

We account for stock-based compensation under the fair value method of accounting. We grant various types of stock-based awards including restricted stock and performance-based awards. The fair value of our restricted stock awards and our performance-based awards (where the performance condition is based on internal performance metrics) is based on the market value of our common stock on the date of grant. The fair value of our performance-based awards where the performance condition is based on market conditions is estimated using a Monte Carlo simulation method.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 10.

Derivative Financial Instruments

We enter into financial commodity derivative contracts to manage exposure to price fluctuations on a portion of anticipated production volumes. We do not enter into these arrangements for speculative or trading purposes. All unsettled commodity derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm when they are governed by master netting agreements which, in an event of default, allows us to offset payables to and receivables from the defaulting counterparty. Changes in a derivative’s fair value are recognized in earnings. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

All realized and unrealized gains and losses on derivative instruments are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value income (loss) in the accompanying consolidated statements of income. Certain of our commodity derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We have collars which establish a minimum floor price and a predetermined ceiling price. Our program may also include three-way collars which are a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the ceiling price while the purchased put establishes the floor price until the market price for the commodity falls below the sold put price at which time the value of the purchased put is effectively capped. We have also entered into natural gas derivative instruments containing a fixed price swap and a sold option (which we refer to as a swaption). The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location ("basis"), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. For additional information regarding our derivative instruments, see Note 8.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, we utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The fair value standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. The hierarchy gives the highest priority to the unadjusted quoted prices in the active markets ("Level 1" measurements) and the lowest priority to unobservable inputs ("Level 3" measurements). The three levels of the fair value hierarchy are as follows:

• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

• Level 3 – Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments using standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. When transfers between levels occur, it is our policy to assume the transfer occurred at the date of the event or change in circumstances that caused the transfer. We value trading securities in the deferred compensation plan and derivative assets and liabilities at fair value on a recurring basis. Certain assets are measured at fair value on a non-recurring basis. For example, our proved natural gas properties and other property and equipment are assessed for impairment periodically as events or changes in circumstances indicate the carrying amount may not be recoverable. There wereno property impairment charges for the three-year period ended December 31, 2024. For additional information regarding the use of fair value, see Note 8 and Note 9.

Concentrations of Credit Risk

As of December 31, 2024, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. The nature of our customers’ businesses may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. To manage risks of collecting accounts receivable, we monitor our counterparties’ financial strength and/or credit ratings and where we deem necessary, we obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. We may also limit the level of exposure with any single counterparty. We do not anticipate a material impact on our financial results due to non-performance by third parties.

For the year ended December 31, 2024, we hadtwo customers that accounted for 10% or more of natural gas, NGLs and oil sales compared toone such customer for the year ended December 31, 2023 andno such customers for the year ended December 31, 2022. Customer A represented 15% of sales in 2024 and 13% in 2023. Customer B represented 10% of sales in 2024. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production.

We have executed International Swap Dealers Association Master Agreements ("ISDA Agreements") with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set-off receivables owed under all derivative contracts against payables from other agreements with that counterparty. None of our derivative contracts have a margin requirement or collateral provision that would require us to fund or post additional collateral prior to the scheduled cash settlement date.

At December 31, 2024, our derivative counterparties included fifteen financial institutions and commodity traders, of which all butfive are secured lenders in our bank credit facility. At December 31, 2024, our net derivative asset includes a payable to thefive counterpartiesnot included in our bank credit facility totaling $11.5 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set-off, as well as pricing of credit default swaps for the counterparty. Historically, we have not experienced any issues of non-performance by derivative counterparties. Net derivative liabilities are determined in part by using our market-based credit spread to incorporate our theoretical risk of non-performance.

Asset Retirement Obligations

The fair value of asset retirement obligations ("ARO") is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing properties and include costs to dismantle and relocate or dispose of production platforms, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future, federal and state regulatory requirements, inflation rates and credit-adjusted-risk-free interest rates. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 7 for additional information.

Exit Costs

We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions. Fair value estimates are based on future discounted cash outflows required to satisfy the obligation. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, are recognized as an adjustment to the liability in the period of the change utilizing the initial discount rate. These costs, including associated accretion expense, are included in exit costs in the accompanying consolidated statements of income. See Note 14 for additional information.

Contingencies

We are subject to legal proceedings, claims, and liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 13 for a more detailed discussion regarding our contingencies.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed.

Deferred Taxes

Deferred tax assets and liabilities, measured by the enacted tax rates, are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors may include whether we are in a cumulative loss position in recent years, our reversal of temporary differences and our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. All deferred taxes are classified as long-term in the accompanying consolidated balance sheets. See Note 4 for a more detailed discussion regarding our income taxes.

Treasury Stock

Treasury stock purchases are recorded at cost. Upon re-issuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. See Note 11 for a more detailed discussion regarding our treasury stock.

Recently Adopted Accounting Standards

In November 2023, the Financial Accounting Standards Board ("FASB") issued accounting standards update ("ASU") No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. 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. This update 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 has adopted ASU 2023-07 and updated our consolidated financial statement disclosures accordingly.

Accounting Standards Not Yet Adopted

In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures to improve its income tax disclosure requirements. Under this ASU, public business entities must annually (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. This ASU is effective for fiscal years beginning after December 15, 2024, and early adoption is permitted. The Company does not expect adoption of ASU 2023-09 to have a material impact on its financial statements and related disclosures.

In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) to improve its expense disclosure requirements. Under this ASU, public business entities at interim and annual reporting periods must (1) disclose the amounts for specific categories of expenses within relevant expense captions, (2) include certain amounts that are already required to be disclosed under current GAAP in the same disclosure as the other disaggregation requirements, (3) disclose a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively and (4) disclose the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. This ASU is effective for annual reporting periods beginning after December 15, 2026, and for interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is evaluating the impact that ASU 2024-03 will have on the consolidated financial statements and its plans for adoption, including the adoption date.

There are no other accounting standards applicable to us that would have a material effect on our consolidated financial statements and disclosures that have been issued but not yet adopted by us as of December 31, 2024, and through the filing date of this report.

(3)Revenues from Contracts with Customers

Disaggregation of Revenue

We have identified three material revenue streams in our business: natural gas sales, NGLs sales and oil sales. Brokered revenue attributable to each product sales type is included here because the volume of product that we purchase is subsequently sold to separate counterparties in accordance with existing sales contracts under which we also sell our production. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):

Performance Obligations and Contract Balance

A significant number of our product sales are short-term in nature with a contract term of one year or less. We typically satisfy our performance obligation upon transfer of control and record revenue in the month production is delivered to the purchaser. Settlement statements for certain gas and NGLs sales may be received 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. We have internal controls in place for our estimation process and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three years ended December 31, 2024, 2023 and 2022, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $291.5 millionat December 31, 2024 compared to $263.9 million at December 31, 2023.

(4)Income Taxes

Our income tax benefit was$15.7 million for the year ended December 31, 2024 compared to an expense of$229.2 million in 2023 and an expense of$230.5 million in 2022. The effective income tax rate is influenced by a variety of factors including geographic sources and relative magnitude of these sources of income as well as a reduction in our valuation allowances related to a change in the realizability of our federal and Pennsylvania deferred tax assets. Additionally, in the current year we recorded a tax benefit related to credits generated in the current year and as part of a look-back study. The state tax reconciling item includes tax expense related to a tax rate change in Louisiana which is equally offset by a change in the Louisiana valuation allowance included on the valuation allowance line. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:

Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands):

At December 31, 2024, deferred tax liabilities exceeded deferred tax assets by$537.4 million. We continue to evaluate the realizability of our federal and state deferred tax assets. As of December 31, 2024, we have a state valuation allowance of $125.0 million related to state tax attributes in Louisiana, Oklahoma, Texas and West Virginia. As of December 31, 2024, we haveno remaining federal or Pennsylvania valuation allowances. The net change in our deferred tax asset valuation allowances was a decrease of $70.4 million for the year ended December 31, 2024 compared to an increase of $2.7 million in 2023 and a decrease of $78.3 million in 2022. The current year decrease in the valuation allowance was a result of our ability to demonstrate strong pre-tax earnings in recent history which resulted in a release of all federal and Pennsylvania valuation allowances.

At December 31, 2024, we have federal NOL carryforwards of $1.4 billion, all of which were generated after 2017 that do not expire. We have state NOL carryforwards in Pennsylvania of $773.2 million that expire between 2031 and 2042 and in Louisiana, we have state NOL carryforwards of $1.7 billion that do not expire. We file a consolidated tax return in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana and Pennsylvania and file consolidated or unitary state income tax returns in Oklahoma, Texas and West Virginia. We are subject to U.S. federal income tax examinations for the years 2021 and after, and we are subject to various state tax examinations for years 2019 and after. We have not extended the statute of limitation period in any income tax jurisdiction. Our policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We donot have any material accrued interest or penalties related to tax amounts as of December 31, 2024 or December 31, 2023. Throughout 2024, 2023 and 2022, our unrecognized tax benefits were not material.

On July 12, 2022, the Commonwealth of Pennsylvania enacted legislation to reduce the corporate net income tax rate from 9.99% to 8.99% in 2023, further reducing by 0.5% per year beginning in 2024, and becoming 4.99% in 2031 and each year thereafter.

Significant components of deferred tax assets and liabilities are as follows (in thousands):

(5)Net Income per Common Share

Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss attributable to common stockholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Diluted net income or loss per share is calculated under both the two class method and the treasury stock method and the more dilutive of the two calculations is presented. The following table sets forth a reconciliation of net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts):

The following table details basic weighted average common shares outstanding and diluted weighted average common shares outstanding (in thousands):

Weighted average common shares outstanding – basic excludes 1.2 million shares of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant) for the period ended December 31, 2024 compared to 4.1 million shares for the period ended December 31, 2023 and 6.1 million shares for the period ended December 31, 2022. Equity grants of 3,000 shares for the year ended December 31, 2023 and 5,000 shares for the year ended December 31, 2022 were outstanding but not included in the computation of diluted net income because the grant prices were greater than the average market price of the common shares and would be anti-dilutive to the computations.

(6)Indebtedness

We had the following debt outstanding as of the dates shown below. The expenses of issuing debt are generally capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. For December 31, 2024, deferred financing costs for our bank credit facility are included in other assets in the accompanying consolidated balance sheet. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized in the three-year period ended December 31, 2024. The components of our debt outstanding, including the effects of debt issuance costs, are as follows (in thousands):

Bank Debt

In April 2022, we entered into an amended and restated revolving bank facility (which we refer to as our bank debt or our bank credit facility) which is secured by substantially all of our assets and has a maturity date of April 14, 2027. The bank credit facility provides for a maximum facility amount of$4.0 billion and an initial borrowing base of$3.0 billion. The bank credit facility provides for a borrowing base subject to re-determinations and for event-driven unscheduled re-determinations. Our current bank group is composed ofseventeen financial institutions. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. Borrowings under the bank facility can either be at the alternate base rate ("ABR," as defined in the bank credit agreement) plus a spread ranging from 0.75% to 1.75% or at the secured overnight financing rate ("SOFR", as defined in the bank credit agreement) plus a spread ranging from 1.75% to 2.75%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our SOFR loans to ABR loans or to convert all or any part of our ABR loans to SOFR loans. There wasno debt outstanding on our bank facility for the year ended December 31, 2024. The weighted average interest rate was 8.4% for the year ended December 31, 2023 and 4.1% for the year ended December 31, 2022. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2024, the commitment fee was 0.375% and the interest rate margin was 0.75% on our ABR loans and 1.75% on our SOFR loans.

On December 31, 2024, bank commitments totaled$1.5 billion and we hadno outstanding borrowings under our bank credit facility. We had$165.3 million of undrawn letters of credit leaving$1.3 billion of committed borrowing capacity available under the facility. As part of our re-determination completed in October 2024, our borrowing base was reaffirmed for$3.0 billion and our bank commitments were also reaffirmed at$1.5 billion.

Senior Note Redemptions

If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior notes at 101% of the principal amount plus accrued and unpaid interest, if any. We currently intend to retire our outstanding long-term debt as it matures, is callable or when market conditions are favorable to repurchase in the open market.

During 2024, we repurchased in the open market $79.7 million aggregate principal amount of our 4.875% senior notes due 2025 at a discount. We recognized again on early extinguishment of debt of$257,000, net of the remaining deferred financing costs on the repurchased debt.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our wholly-owned subsidiaries, which are directly or indirectly owned by Range, of our senior notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. The assets, liabilities and results of operations of Range and our guarantor subsidiaries are not materially different than our consolidated financial statements. A subsidiary guarantor may be released from its obligations under the guarantee:

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in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or

•

if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture.

Debt Covenants and Maturity

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. We are required to maintain a ratio of debt-to-EBITDAX (as defined in the credit agreement) of less than 3.75 x and a minimum current ratio (as defined in the credit agreement) of 1.0 x. We were in compliance with applicable covenants under the bank credit facility at December 31, 2024. The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2024 (in thousands):

(7)Asset Retirement Obligations

ARO primarily represents the present value of the estimated amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well lives. The inputs are calculated based on historical data as well as current estimated costs. The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2024 and 2023 (in thousands):

Accretion expense is recognized within depreciation, depletion and amortization expense in the accompanying consolidated statements of income.

(8)Derivative Activities

The following table sets forth the derivative volumes and fair values by expiration year as of December 31, 2024, excluding our basis swaps which are discussed separately below. All fair values presented in the table utilize Level 2 inputs, except where noted:

Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. Derivatives in Level 3 use the same approach, but will also utilize unobservable pricing inputs that are significant to overall value.

Basis Swap Contracts

In addition to the commodity derivatives described above, at December 31, 2024, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts settle monthly through December 2028 and include a total volume of 266,640,000 Mmbtu. The fair value of these contracts, which utilizes Level 2 inputs, was a net derivative liability of $29.2 million as of December 31, 2024.

Derivative Assets and Liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2024 and 2023 is summarized below (in thousands). The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements.

Derivative Fair Value Income

The effects of our derivatives on our consolidated statements of income for the last three years are summarized below (in thousands):

(9)Fair Value Measurements

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. As of December 31, 2024, a portion of our natural gas instruments contain swaptions (Level 3 inputs) where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a pre-determined date. If exercised, the swaption contract becomes a swap treated consistently with our fixed-price swaps. At December 31, 2024, we used a weighted average implied volatility of 24% for our swaptions. The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2024 and 2023 (in thousands):

(a)Fair values for commodity derivatives utilize Level 2 inputs with the exception of swaptions, which utilize Level 3 inputs. Fair value of swaption contracts as of December 31, 2024 was a net derivative liability of $13.2 million.

(b)Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges, which is a Level 1 input.

(c)The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes is based on end of period market quotes. Debt is presented on the balance sheet at carrying value.

(d)The fair value of our deferred compensation plan is updated to the closing price on the balance sheet date, which is a Level 1 input.

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical incurrence of and expected future insignificance of bad debt expense. Non-financial liabilities initially measured at fair value include asset retirement obligations, operating lease liabilities and the divestiture contract obligation that we incurred in conjunction with the sale of our North Louisiana assets. See Note 8 for information regarding the fair value of derivative instruments and Note 10 for information regarding the fair value of stock-based compensation awards.

(10)Stock-Based Compensation Plans

Description of the Plans

We havetwo active equity-based stock compensation plans, our Amended and Restated 2005 Equity-Based Compensation Plan and the Amended and Restated 2019 Equity-Based Compensation Plan. Under these plans, various awards may be issued to non-employee directors and employees pursuant to decisions of the Compensation Committee, which is composed of only non-employee, independent directors. We currently award time-based and performance-based stock awards.

Time-Based Stock Awards

We grant time-based restricted stock awards to employees and non-employee directors. These awards generally vest ratably over athree-year period or at the end of thethree-year period for certain employees. The vesting of these awards are typically contingent on the recipient’s continued employment with us. Awards made to non-employee directors vest at the end of aone-year period and the vesting is typically contingent on the recipient's continued service as a non-employee director.

These time-based stock awards can have two different types of accounting treatment, depending on whether they are placed into our deferred compensation plan (see further discussion below on the deferred compensation plan). Restricted stock awards that are placed into the deferred compensation plan upon grant are referred to as Liability Awards. Upon vesting, withdrawals are allowed in either cash or stock. Restricted stock awards that are accounted for using equity-classified award accounting are referred to as Equity Awards. Upon vesting, these awards will settle in stock only.

Awards granted to employees are accounted for using equity-classified award accounting, as these awards are not placed into the deferred compensation plan. Prior to 2023, employee executives (VPs and above) were awarded time-based awards that were contributed to the deferred compensation plan and were accounted for using liability-classified award accounting. Subsequent annual grants made to employee executives were not contributed to the deferred compensation plan and were accounted for using equity-classified award accounting. Directors can elect to contribute their time-based stock awards to the deferred compensation plan at the time of grant. Awards that are elected to be contributed to the deferred compensation plan are accounted for using liability-classified award accounting.

Equity Awards. Equity Awards are expensed ratably over the service period associated with the award based on the fair value of the awards. The grant date fair value of all Equity Awards is based on prevailing market prices on the date of grant. Equity Awards made to employee executives typically earn dividends prior to vesting that are payable in cash upon vesting. These dividends are forfeited and not paid if the associated shares do not vest.

We recorded compensation expense for the restricted stock Equity Awards of $34.9 million in the year ended December 31, 2024 compared to $31.6 million in 2023 and $21.0 million in 2022. The vesting date fair value of restricted stock Equity Awards which vested during 2024, 2023 and 2022 was $35.7 million, $31.9 million and $20.3 million, respectively. As of December 31, 2024, there was $34.4 million of unrecognized compensation related to restricted stock Equity Awards expected to be recognized over a weighted average period of 1.7 years. These awards are not issued until such time as they are vested and the grantees do not have the option to receive cash.

Liability Awards. Liability Awards are recognized ratably over the service period associated with the award based on the fair value of the awards on the date of grant. The grant date fair value of Liability Awards is based on prevailing market prices at the time of the grant. Prior to vesting, restricted stock Liability Awards recipients have the right to receive dividends thereon. These restricted stock Liability Awards are classified as a liability and are re-measured at fair value each reporting period. This mark-to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of income (see additional discussion below).

We recorded compensation expense for these outstanding restricted stock Liability Awards of $1.4 million in the year ended December 31, 2024 compared to $4.0 million in 2023 and $13.6 million in 2022. The vesting date fair value of these restricted stock Liability Awards vested during 2024, 2023 and 2022 was $2.1 million, $4.3 million and $13.2 million, respectively. As of December 31, 2024, there was $228,000 of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of less thanone year.

Performance-Based Stock Awards

We have grantedtwo types of performance share awards ("performance units"): one based on performance conditions measured against internal performance metrics andone based on market conditions measured related to Range’s performance relative to a predetermined peer group ("TSR Awards"). These awards typically vest at the end of thethree-year performance period.

Each unit granted representsone share of our common stock. These units are settled in stock and the amount of the payout is based on the vesting percentage, which can range from zero to 200%, and (1) for our internal metric awards, the internal performance metrics achieved, which is determined by the Compensation Committee and (2) for our TSR Awards, the value of our common stock on the performance period ending date compared to our peers. Dividend equivalents accrue during the performance period and are paid in stock at the end of the performance period. The performance period isthree years.

Internal Performance Metric Awards. The performance metrics are set by the Compensation Committee. If the performance metric for the applicable period is not met, that portion is considered forfeited and an adjustment to expense recorded.

Internal performance metric awards granted in 2023 and 2022 are earned based on:

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Net debt (total debt less cash on hand balance); and

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GHG emissions intensity.

Range made significant progress towards long-term net debt and GHG emissions intensity targets in 2022 and 2023, so these internal performance metric awards were not utilized in 2024. We recorded compensation expense for the prior grants of these awards of $3.3 million in the year ended December 31, 2024 compared to $2.2 million in the year ended December 31, 2023 and $6.2 million in the year ended December 31, 2022. As of December 31, 2024, there was $780,000 of unrecognized compensation related to these internal performance metric awards to be recognized over a weighted average period of 1.2 years.

TSR awards. These awards are earned, or not earned, based on the comparative performance of Range’s common stock measured against a predetermined group of companies in the peer group over athree-year performance period. The fair value of the TSR awards is estimated on the date of grant using a Monte Carlo simulation model which utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The fair value is recognized as stock-based compensation expense over the three-year performance period. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. The risk-free interest rate was based on the United States Treasury note rate for a term commensurate with the life of the grant. The following assumptions were used to estimate the fair value of the TSR awards granted during the years ended December 31, 2024, 2023 and 2022:

In 2024, we granted 254,000 TSR awards as compensation to employees which vest at the end of athree-year period compared to 64,000 in 2023 and 112,000 in 2022. We recorded TSR award compensation expense of $3.9 million in the year ended December 31, 2024 compared to $1.7 million in 2023 and $3.2 million in 2022. As of December 31, 2024, there was $5.4 million of unrecognized compensation related to these TSR awards to be recognized over a weighted average period of 1.9 years.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock and performance units. The following details the allocation of stock-based compensation to functional expense categories for each of the years in the three-year period ended December 31, 2024 (in thousands):

The mark-to-market adjustment of the liability related to the vested restricted stock Liability Awards held in our deferred compensation plan is directly tied to the change in our stock price and is not related to functional expenses and, therefore, is not allocated to the functional categories above.

Stock Awards Summary

The following is a summary of the activity for our time-based and performance-based restricted stock awards for the two years ended December 31, 2024 and 2023:

In 2024, we recorded an additional tax benefit of an estimated $5.2 million for the tax effect of financial accounting expense compared to the corporate income tax deduction for equity compensation that vested during the year compared to additional tax benefit of $10.6 million in 2023 and additional tax benefit of $7.2 million in 2022.

401(k) Plan

We maintain a 401(k) benefit plan that allows employees to contribute up to 75% of their salary and bonus on an annual basis (subject to Internal Revenue Service limitations) on a pretax basis. We match, dollar for dollar, in cash up to 6% of each participant's contribution and vesting of those contributions is immediate. In 2024, we contributed $5.5 million to the 401(k) Plan compared to $5.2 million in 2023 and $4.8 million in 2022. Employees have a variety of investment options in the 401(k) benefit plan including investing in Range stock.

Deferred Compensation Plan

Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock (as described above under Liability Awards) or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests at the end ofthree years and can be made in either cash or stock. Any stock contributed through the salary or bonus deferral match are treated as Liability Awards as described above. The assets of the plans are held in trading securities or as stock in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency.

Our trading securities held in the deferred compensation plan are exchange traded and are accounted for using the mark-to-market accounting method valued at fair value each reporting period utilizing Level 1 inputs. They are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains or losses are included in deferred compensation plan expense in the accompanying consolidated statements of income. For the year ended December 31, 2024, interest and dividends were $1.3 million and mark-to-market was a gain of $4.5 million. For the year ended December 31, 2023, interest and dividends were $1.6 million and mark-to-market was a gain of $7.8 million. For the year ended December 31, 2022, interest and dividends were $1.1 million and mark-to-market was a loss of $14.2 million.

Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of income. We recorded a mark-to-market loss of$9.6 million in 2024 compared to a loss of$26.6 million in 2023 and a loss of$61.9 million in 2022. The Rabbi Trust held 742,000 shares (724,000 vested shares) of Range stock at December 31, 2024 compared to 1.6 million (1.5 million of vested shares) at December 31, 2023 and 5.6 million (5.3 million vested shares) at December 31, 2022. The proceeds received from the sale of stock held in our deferred compensation plan were$20.1 million in 2024 compared to$75.2 million in 2023 and$22.2 million in 2022.

(11) Capital Stock

We have authorized capital stock of 485.0 million shares, which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2023:

Common Stock Dividends

The payment of dividends is subject to the formal declaration by the board of directors. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the board of directors and will depend on our financial condition, earnings, capital requirements, levels of indebtedness, our future business prospects and other matters our board of directors deems relevant. Our bank credit facility allows for the payment of common dividends, with certain limitations, as described in the facility agreement.

Stock Repurchase Program

In October 2019, the board of directors approved a stock repurchase program which was increased in size in 2022. Under this program, we may repurchase shares of our common stock in open market transactions, from time to time, in accordance with applicable SEC rules and federal securities laws. In 2024, we repurchased 2,050,000 shares at an aggregate value of $65.3 million. As of December 31, 2024, we have approximately$1.0 billion of remaining authorization under this program. The following is a schedule of the change in treasury shares since the beginning of 2023:

(12) Supplemental Cash Flow Information

(13)Commitments and Contingencies

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions and administrative proceedings or investigations arising in the ordinary course of our business including, but not limited to, royalty claims, contract claims and environmental claims. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations.

When deemed necessary, we establish reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible we could incur additional losses with respect to those matters in which reserves have been established. We will continue to evaluate our litigation on a quarterly basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

We have incurred and will continue to incur capital, operating and remediation expenditures as a result of environmental laws and regulations. As of December 31, 2024 and 2023, liabilities for remediation were not material. We are not aware of any environmental claims existing as of December 31, 2024 that have not been provided for or would otherwise have a material impact on our financial position or results of operations. Environmental liabilities normally involve estimates that are subject to revision until final resolution, settlement or remediation occurs. We believe that substantially all of our competitors must comply with similar environmental laws and regulations.

Obligations Following Divestitures

Certain contractual obligations were retained by us after our divestiture of our North Louisiana assets in 2020. These obligations are primarily related to gathering, processing and transportation agreements including certain minimum volume commitments. For additional information see Note 14.

Lease Commitments

The components of our total lease expense for the two years ended December 31, 2024, the majority of which is included as part of natural gas and oil properties on our consolidated balance sheets, are as follows (in thousands):

Supplemental cash flow information related to our operating leases is included in the table below (in thousands):

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):

Transportation, Gathering and Processing Contracts

We have entered into firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production. Under these contracts, we are obligated to transport or gather minimum daily natural gas volumes or pay for any deficiencies at a specified reservation fee rate. Our production committed to these pipelines is currently expected to exceed the minimum daily volumes provided in the contracts. However, if in the future we fail to deliver the committed volumes, we would recognize a deficiency payment in the period in which the under-delivery takes place and the related liability has been incurred. In the information below we have not considered any potential future renewals, although at times we will renew these agreements. As of December 31, 2024, future minimum transportation and gathering fees under our commitments are as follows (in thousands):

We have also entered into amendments that are not in the above table, but modify existing contracts and are contingent on additional facility construction which is expected to be complete in 2026. The amendments will expand gathering and processing capacity by 300,000 mcf/day and transportation capacity by 250,000 Mmbtu/day. We will have a contingent related commitment for the de-ethanization capacity associated with this processing expansion. Beginning on the in-service date this capacity will total 40,000 bbl/day, increasing by 5,000 bbls/day after one year of service, and continues through the end of the agreement. We also entered into a new contract for propane export terminal capacity that is contingent on the construction of the relevant facilities and is expected to be in service in 2026. This capacity will be 10,000 bbls/day for the first year and increases to 20,000 bbls/day for the remainder of the term.

Delivery Commitments

We have various volume delivery commitments that we expect to be able to fulfill from our own production; however, we may purchase third-party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. In the information below we have not considered any potential future renewals, although at times we will renew these agreements. As of December 31, 2024, our delivery commitments through 2037 were as follows:

Other

We have lease acreage that is generally subject to expiration if initial wells are not drilled within a specified period, generally between three andfive years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to besignificant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs. We also regularly provide letters of credit in the normal course of business under certain contracts that may be drawn if we fail to perform under those contracts.

(14) Exit Costs

In August 2020, we sold our North Louisiana assets and retained certain gathering, transportation and processing obligations which extend into 2030. These are contracts where we will not realize any future benefit. The estimated obligations are included in current and long-term divestiture contract obligation in our consolidated balance sheets. In the year ended December 31, 2024, we recorded accretion expense of $39.2 million compared to $41.9 million in 2023 and $43.6 million in 2022. In 2024, we recorded a net adjustment of $2.1 million to decrease the obligation mainly due to a decrease in forecasted electricity costs. In 2023, we recorded net adjustments of $57.7 million to increase this obligation primarily for higher rates due to inflation and to increase the obligation for a change to our forecasted drilling plans of the buyer. The present value of our estimated obligations related to these assets was initially recorded in 2020 as an exit cost at a total of $479.8 million. There are inherent uncertainties surrounding the retained obligation and, as a result, the determination of the accrued obligation required judgment and estimation. The actual settlement amount and timing may differ from our estimates. The estimated discounted value for this divestiture contract obligation was $344.3 million at December 31, 2024, of which $87.0 million is classified as short-term.

In second quarter 2020, we negotiated capacity releases on certain transportation pipelines in Pennsylvania effective May 31, 2020 and extending through the remainder of the contract. As a result of these releases, we recorded exit costs of $10.4 million in 2020 which represented the discounted present value of our remaining obligations to the third party. As of December 31, 2024, this obligation is complete and hasno remaining carrying value.

The following summarizes our exit costs for the three years ended December 31, 2024, 2023 and 2022 (in thousands):

The following details the accrued exit cost liability activity for the years ended December 31, 2024 and 2023 (in thousands):

As of December 31, 2024, our estimated settlement of the remaining divestiture contract obligation based on a discounted value is as follows (in thousands):

(15) Suspended Exploratory Well Costs

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of income. There wereno capitalized exploratory well costs in 2022 or 2023. The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2024 (in thousands):

(16) Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)

Our natural gas and oil producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization(a)

Costs Incurred for Property Acquisition, Exploration and Development(a)

Reserves Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2024, Netherland, Sewell & Associates, Inc., an independent petroleum consultant, conducted an audit of our 2024 reserves in Appalachia. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. The proved reserve audits performed for 2024, 2023 and 2022, in the aggregate, represented 96% for each of the three years. The reserve audits performed for 2024, 2023 and 2022, in the aggregate, represented 99%,99% and 96%, respectively, of our 2024, 2023, and 2022 associated pre-tax present value of proved reserves discounted atten percent. A copy of the reserve summary report prepared by the independent petroleum consultant is included as an exhibit to this Annual Report on Form 10-K. The technical person at our independent petroleum consulting firm responsible for reviewing the reserves estimates presented herein meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished during the reserves audit process. Throughout the year, our technical team meets periodically with representatives of our independent petroleum consultant to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any significant changes to our proved reserves. Additionally, on an annual basis the board of directors approves the development plan. We provide historical information to our consultant for our largest producing properties such as ownership interest, natural gas, NGLs and oil production, well test data, commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering and Economics. In some cases, additional meetings are held to review identified reserve differences. The reserve auditor estimates of proved reserves and the pretax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared lease-by-lease, field-by-field or area-by-area, some of our estimates may be greater and some may be less than the estimates of our reserve auditor. When such differences do not exceed 10% in the aggregate, our reserve auditor is satisfied that the proved reserves and pretax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analysis.

Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum consultants have been approximately 5%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has more than forty years of engineering experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

Estimated Quantities of Proved Natural Gas, NGLs and Oil Reserves

Reserves of natural gas, NGLs, and oil are estimated by our petroleum engineering staff and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, production taxes and other economic factors.

The SEC defines proved reserves as those volumes of natural gas, NGLs, and oil that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. The term "reasonable certainty" implies a high degree of confidence that the quantities of natural gas, NGLs and oil actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal technical staff employs technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, decline curve analysis, well logs, geologic maps and available downhole and production data, seismic data, well test data, reservoir simulation modeling and implementation and application of enhanced data analytics.

Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated when such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locationscan be classified as having undeveloped reserves only if a development plan has been adopted indicating each location isscheduled to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer time.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2024, NGLs represented approximately 35% of our total proved reserves on an mcf equivalent basis. NGLs are products priced by the gallon (and sold by the barrel) to our customers. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels. Prices for a barrel of NGLs in 2024 averaged approximately 34% of the average price for equivalent volumes of oil. We report all production information related to natural gas net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs. We currently include ethane in our proved reserves which match volumes to be delivered under our existing long-term, extendable ethane contracts.

The average realized prices used at December 31, 2024 to estimate reserve information were $63.39 per barrel of oil, $24.40 per barrel of NGLs and $1.74 per mcf for gas using a benchmark (NYMEX) of $74.88 per barreland $2.13 per Mmbtu. The average realized prices used at December 31, 2023 to estimate reserve information were $68.32 per barrel of oil, $24.91 per barrel of NGLs and $2.20 per mcf for gas using a benchmark of $78.10 per barrel and $2.62 per Mmbtu. The average realized prices used at December 31, 2022 to estimate reserve information were $87.14 per barrel of oil, $38.35 per barrel of NGLs and $6.08 per mcf for gas using a benchmark of $94.13 per barrel and $6.36 per Mmbtu.

During 2024, revisions of previous estimates of a positive 75.8 Bcfe includes a positive revision of 457.2 Bcfe for previously undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan and positive performance revisions of 391.4 Bcfe due to improved well performance and longer lateral lengths partially offset by negative pricing revisions of 1.3 Bcfe and 771.5 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. We added 749.4 Bcfe of proved reserves from drilling activities and evaluation of proved areas in Pennsylvania. Our ethane reserves are intended to match volumes delivered under our existing long-term, extendable contracts along with meeting pipeline specificat ions.

During 2023, revisions of previous estimates of a positive 608.8 Bcfe include a positive revision of 280.2 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan and positive performance revisions of 701.4 Bcfe due to improved well performance and longer lateral lengths partially offset by negative pricing revisions of 2.2 Bcfe and 370.6 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. We added approximately 207.3 Bcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale.

During 2022, we added approximately 1.7 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 77% of the 2022 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 592.0 Bcfe included a positive revision of 716.2 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan, positive performance revisions of 72.8 Bcfe and positive pricing revisions of 0.9 Bcfe more than offset by 1,381.9 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. These wells were removed due to the out-performance of existing wells which resulted in a higher utilization of in-field gathering capacity and a reallocation of capital due to the drilling of longer laterals on existing locations.

The following details the changes in proved undeveloped reserves for 2024 (Mmcfe):

During 2024, wespent $512.1 million on develo pment costs related to proved undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $2.3 billion. As of December 31, 2024, we haveno proved undeveloped reserves that have been reported for more than five years from their original date of booking. All of our recorded proved undeveloped drilling locations are scheduled to be drilled within five years of initial disclosure.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following summarizes the policies we used in the preparation of the accompanying natural gas, NGLs and oil reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas, NGLs and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas, NGLs, and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.

For the years ended 2024, 2023 and 2022, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities of those reserves produced in each future year.

Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the natural gas, NGLs and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves.

The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas, NGLs and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, and oil reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective reporting dates. Future cash inflowsare net of third-party transportation, gathering and compression expense.

The following table summarizes changes in the standardized measure of discounted future net cash flows.