Range Resources Corp: Form 10-Q for the period ended Jun 30, 2025

Overview of Our Business

We are an independent natural gas, natural gas liquids and oil company engaged in the exploration, development and acquisition of natural gas and liquids properties in the Appalachian region of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on a geographical or an area-by-area basis.

Our overarching business objective is to build stockholder value through returns-focused development of properties. Our strategy to achieve our business objective is to generate consistent cash flows from reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and divestitures. Currently, our investment portfolio is focused on high-quality natural gas and NGLs assets in the Commonwealth of Pennsylvania. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs and oil and on our ability to economically find, develop, acquire and produce these reserves.

Commodity prices have been and are expected to remain volatile. We believe we are well-positioned to manage challenges that could occur during price variations and that we can endure the continued fluctuations in current and future commodity prices by:

• exercising discipline in our capital investments;
• maintaining a competitive cost structure;
• diversifying sales outlets;
• managing price risk through the partial hedging of our production;
• managing a strong balance sheet; and
• optimizing drilling, completion and operational efficiencies.

Prices for natural gas, NGLs and oil fluctuate widely and affect:

• our revenues, profitability and cash flow;
• the amount of cash flow available to us for reinvestment or return to our stockholders;
• the quantity of natural gas, NGLs and oil that we can economically produce;
• the quantity of natural gas, NGLs and oil shown as proved reserves; and
• our ability to borrow and raise additional capital, if needed.

We prepare our financial statements in conformity with U.S. GAAP, which requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities. The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.

Market Conditions

We believe we are positioned for sustainable long-term success. We continue to monitor the impact of the actions of OPEC and other large hydrocarbon producing nations, the Russia-Ukraine conflict, hostilities in the Middle East, global inventories of natural gas, NGLs and oil, future monetary and fiscal policy, potential tariffs and their impacts on global trade and energy demands and governmental policies aimed at transitioning towards lower carbon energy. We expect prices for the commodities we produce to remain volatile given the complex dynamics of supply and demand that exist in the global energy markets. In first six months 2025, natural gas prices increased primarily due to winter weather and larger exports from new U.S. LNG export facilities. Longer term natural gas futures prices remain constructive based on market expectations of continued LNG expansion, increasing power demand, and associated gas-related activity in oil basins and dry gas basin activity, which are expected to show modest rates of growth due to infrastructure constraints, moderated reinvestment rates and inventory exhaustion. In addition, the global energy crisis experienced in recent years further highlighted the low cost and low emissions shale gas resource base in North America, supporting continued strong structural demand growth for U.S LNG exports, domestic industrial gas demand and power generation. Other factors such as geopolitical disruptions, supply chain disruptions, cost inflation, concerns over a potential economic recession and the pace of changes in global monetary policy may impact global demand for natural gas, NGLs and oil. We continue to assess and monitor the impact of these factors on our business.

Benchmarks for natural gas and NGLs increased in second quarter 2025 and first six months 2025 compared to the same periods of 2024. As a result, we experienced increases in our price realizations for all periods in 2025. With these increasing prices, we continue to focus on creating long-term value for our stockholders along with positioning ourselves to be a responsible and reliable supplier of natural gas and NGLs.

The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the three and six months ended June 30, 2025 and 2024:

(a) Based on weighted average of bid week prompt month prices on the New York Mercantile Exchange ("NYMEX").

(b) Based on our estimated NGLs product composition per barrel.

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Our price realizations (not including the impact of our derivatives) may differ from these benchmarks for many reasons, including quality, location or production being sold at different indices.

Consolidated Results of Operations

Overview of Second Quarter 2025 Results

In second quarter 2025, we experienced an increase in revenue from the sale of natural gas, NGLs and oil when compared to the same quarter of 2024, due to an increase of 19% in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) and a 2% increase in total production.

During second quarter 2025, we recognized net income of $237.6 million, or $0.99 per diluted common share compared to net income of $28.7 million, or $0.12 per diluted common share during second quarter 2024. The higher net income in second quarter 2025 compared to second quarter 2024 is primarily due to increased realized prices combined with a higher unrealized derivative fair value gain.

Our second quarter 2025 financial and operating performance included the following results:

• revenue from the sale of natural gas, NGLs and oil increased 39% from the same period of 2024 due to a 36% increase in average realized prices (before cash settlements on our derivatives) combined with a 2% increase in production volumes;
• revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) increased 15% from the same period of 2024;
• direct operating expense per mcfe decreased to $0.11 during second quarter 2025 compared to $0.12 in the same period of 2024 due to an increase in production;
• transportation, gathering, processing and compression per mcfe was $1.52 in second quarter 2025 compared to $1.44 in the same period of 2024, primarily due to an increase in NGLs volumes and electricity costs;
• general and administrative expense per mcfe was $0.21 in second quarter 2025 compared to $0.20 in the same period of 2024 due largely to timing of expenses; and
• interest expense per mcfe decreased 13% from the same period of 2024 due to lower debt balances.

Second quarter 2025 also included the following highlights to enhance our balance sheet and return capital to investors:

• repurchased $52.9 million (1.5 million shares) of our common stock;
• paid $21.5 million of dividends, increasing per share dividend by 12.5% to $0.09 per share compared to $0.08 per share in the same period of 2024;
• paid off the remaining principal balance of $606.5 million of our 4.875% senior notes due 2025 at par by utilizing cash on hand and borrowing on our credit facility; and
• maintained substantial liquidity with $1.2 billion available under our credit facility.

We generated $336.2 million of cash from operating activities in second quarter 2025, an increase of $187.4 million from second quarter 2024, which reflects the impact of higher realized prices.

Overview of First Six Months 2025 Results

In first six months 2025, we experienced an increase in revenue from the sale of natural gas, NGLs and oil when compared to the same period of 2024, due to an increase of 20% in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) and a 2% increase in total production.

During first six months 2025, we recognized net income of $334.6 million, or $1.39 per diluted common share compared to net income of $120.8 million, or $0.49 per diluted common share during the same period 2024. The higher net income in first six months 2025 compared to first six months 2024 is primarily due to increased realized prices.

Our first six months 2025 financial and operating performance included the following results:

• revenue from the sale of natural gas, NGLs and oil increased 40% from the same period of 2024 due to a 37% increase in average realized prices (before cash settlements on our derivatives) combined with a 2% increase in production volumes;
• revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) increased 15% from the same period of 2024;
• direct operating expense per mcfe increased to $0.12 in first six months 2025 compared to $0.11 in the same period of 2024 due to an increase in water hauling and pumping costs;
• transportation, gathering, processing and compression per mcfe was $1.53 in first six months 2025 compared to $1.47 in the same period of 2024, primarily due to an increase in NGLs volumes and electricity costs;
• general and administrative expense per mcfe was $0.21 in first six months 2025 compared to $0.22 in the same period of 2024 due largely to timing of expenses; and
• interest expense per mcfe decreased 7% from the same period of 2024 due to lower debt balances.

First six months 2025 also included the following highlights to enhance our balance sheet and return capital to investors:

• repurchased $120.4 million (3.3 million shares) of our common stock;
• paid $43.1 million of dividends, increasing per share dividend by 12.5% to $0.18 per share compared to $0.16 per share in the same period of 2024;
• repurchased in the open market $2.2 million principal amount of our 4.875% senior notes due 2025 at a discount and paid off the remaining principal balance of the $606.5 million of our 4.875% senior notes due 2025 at par by utilizing cash on hand and borrowing on our credit facility; and
• maintained substantial liquidity with $1.2 billion available under our credit facility.

We generated $666.3 million of cash from operating activities in first six months 2025, an increase of $185.6 million from first six months 2024, which reflects the impact of higher realized prices.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary primarily as a result of changes in realized commodity prices and production volumes. Our revenues are generally recognized when control of the product is transferred to the customer and collectability is reasonably assured. The following table illustrates the primary components of natural gas, NGLs and oil sales for the three and six months ended June 30, 2025 and 2024 (in thousands):

20

Production is maintained through drilling success as new wells are placed in production, which is partially offset by the natural decline in production through existing wells. Our production for the three and six months ended June 30, 2025 and 2024 is set forth in the following table:

(a) Represents volumes sold regardless of when produced.

(b) Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Our average realized price received (including all derivative settlements and third-party transportation costs) during second quarter 2025 was $1.97 per mcfe compared to $1.66 per mcfe in second quarter 2024. Our average realized price received (including all derivative settlements and third-party transportation costs) during first six months 2025 was $2.22 per mcfe compared to $1.85 per mcfe in first six months 2024. We believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense. Our average realized prices (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives. Our average realized prices (excluding derivative settlements) do not include derivative settlements or third-party transportation costs which are reported in transportation, gathering, processing and compression expense in the accompanying consolidated statements of income. Our average realized prices (including derivative settlements) do include transportation costs where we receive net revenue proceeds from purchasers. Our average realized price calculations for three and six months ended June 30, 2025 and 2024 are shown below:

(a) Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Realized prices include the impact of basis differentials and gains or losses realized from our basis hedging. The prices we receive for our natural gas can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors. The following table provides this impact on a per mcf basis:

The following tables reflect our production and average sales prices (excluding derivative settlements and third-party transportation costs paid by Range) (in thousands, except prices):

22

Transportation, gathering, processing and compression expense was $304.7 million in second quarter 2025 compared to $281.5 million in second quarter 2024. These third-party costs are higher in second quarter 2025 when compared to second quarter 2024 primarily due to an increase in NGLs volumes and electricity cost.

Transportation, gathering, processing and compression expense was $610.8 million in first six months 2025 compared to $572.4 million in first six months 2024. These third-party costs are higher in first six months 2025 when compared to first six months 2024 primarily due to an increase in NGLs volumes and electricity cost. Gas transportation expense increased due to an increase in fuel cost caused by higher prices. We have included these costs in the calculation of average realized prices (including all derivative settlements and third-party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the three and six months ended June 30, 2025 and 2024 on a per mcf and per barrel basis (in thousands, except for costs per unit):

Derivative fair value income was $154.7 million in second quarter 2025 compared to income of $16.8 million in second quarter 2024. Derivative fair value loss was $4.2 million in first six months 2025 compared to income of $63.4 million in first six months 2024. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment can result in more volatility of our revenues as the change in the fair value of our commodity derivative positions is included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate potentially lower wellhead revenues in the future while losses indicate potentially higher future wellhead revenues. The following table summarizes the impact of our commodity derivatives for the three and six months ended June 30, 2025 and 2024 (in thousands):

(a) Non-cash fair value adjustments on commodity derivatives is a non-U.S. GAAP measure. Non-cash fair value adjustments on commodity derivatives only represent the net change between periods of the fair market values of commodity derivative positions and exclude the impact of settlements on commodity derivatives during the period. We believe that non-cash fair value adjustments on commodity derivatives is a useful supplemental disclosure to differentiate non-cash fair market value adjustments from settlements on commodity derivatives during the period. Non-cash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under U.S. GAAP, nor should it be considered a substitute for derivative fair value income or loss as reported in our consolidated statements of income.

Brokered natural gas and marketing revenue was $33.0 million in second quarter 2025 compared to $31.4 million in second quarter 2024, which is the result of higher broker sales price slightly offset by lower broker sales volumes (volumes not related to our production). Brokered natural gas and marketing revenue was $87.4 million in first six months 2025 compared to $60.2 million in first six months 2024, which is the result of higher broker sales price slightly offset by lower broker sales volumes (volumes not related to our production). We continue to optimize our transportation portfolio using these volumes. See also Brokered natural gas and marketing expense below for more information on our net brokered margin.

Other income was $1.9 million in second quarter 2025 compared to $3.5 million in second quarter 2024. This includes $1.8 million of interest income and a $78,000 gain on sale of assets in 2025 compared to $3.4 million of interest income and a $55,000 gain on sale of assets in 2024. Other income was $5.1 million in first six months 2025 compared to $6.5 million in first six months 2024. This includes $4.8 million of interest income and a $136,000 gain on sale of assets in 2025 compared to $6.3 million of interest income and a $126,000 gain on sale of assets in 2024. Interest income is lower in 2025 due to the use of cash to repay senior notes. In the 2024 interim periods, interest income was included within brokered natural gas and marketing revenue and other and gain on sale of assets was its own discrete line in prior interim financial statements. In 2025 and for the comparable interim periods presented, we reclassified both of these items into other income in the accompanying consolidated statements of income.

Operating Costs per Mcfe

We believe some of our expense fluctuations are best analyzed on a unit-of-production or per mcfe basis. The following table presents information about certain of our expenses on a per mcfe basis for the three and six months ended June 30, 2025 and 2024:

Direct operating expense was $23.1 million in second quarter 2025 compared to $22.8 million in second quarter 2024. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workover costs and repair-related expenses. Our direct operating costs increased in second quarter 2025 primarily due to higher workovers and maintenance costs. We incurred $803,000 of workover costs in second quarter 2025 compared to $644,000 in second quarter 2024.

Direct operating expense was $48.5 million in first six months 2025 compared to $44.9 million in first six months 2024. Our direct operating costs increased in first six months 2025 primarily due to higher water hauling, pumping and maintenance costs. We incurred $1.6 million workover costs in first six months 2025 compared to $1.5 million in first six months 2024. The following table summarizes direct operating expense per mcfe for the three and six months ended June 30, 2025 and 2024:

Taxes other than income expense is predominately comprised of the Pennsylvania impact fee which functions as a tax on unconventional natural gas and oil production from the Marcellus Shale in Pennsylvania. This impact fee was $7.4 million in second quarter 2025 compared to $4.6 million in second quarter 2024 and $14.3 million in first six months 2025 compared to $10.4 million in first six months 2024. The impact fee is based on drilling activities and is adjusted based on prevailing natural gas prices, which are both higher than prior year. This category also includes franchise, real estate and other applicable taxes. The following table summarizes taxes other than income per mcfe for the three and six months ended June 30, 2025 and 2024:

24

General and administrative (G&A) expense was $42.1 million in second quarter 2025 compared to $40.1 million in second quarter 2024. The second quarter 2025 increase of $2.0 million when compared to the same period of 2024 is primarily due to timing of expenses.

G&A expense was $83.8 million in first six months 2025 compared to $84.1 million in first six months 2024. The decrease of $245,000 is primarily due to lower consulting fees and timing of expenses, mostly offset by higher employee related costs. The following table summarizes G&A expenses on a per mcfe basis for the three and six months ended June 30, 2025 and 2024:

Interest expense was $26.8 million in second quarter 2025 compared to $29.7 million in second quarter 2024. Interest expense was $56.0 million in first six months 2025 compared to $60.2 million in first six months 2024. The following table presents information about interest expense per mcfe for the three and six months ended June 30, 2025 and 2024:

(a) Includes commitment fees.

(b) Excludes deferred financing costs.

The decrease in interest expense for second quarter and six months 2025 compared to the same periods of 2024 was primarily due to lower average outstanding debt balances. In May 2025, we paid off the remaining principal balance of $606.5 million of our 4.875% senior notes due 2025 by utilizing cash on hand and borrowing on our credit facility. We had $125.0 million outstanding on the bank credit facility as of June 30, 2025 compared to no bank debt outstanding for the same period of 2024.

Depletion, depreciation and amortization (DD&A) expense was $91.5 million in second quarter 2025 compared to $87.6 million in second quarter 2024, and was $182.1 million in first six months 2025 compared to $174.7 million in first six months 2024. This increase in both periods is due to a higher depletion rate combined with higher production volumes. Depletion expense, the largest component of DD&A expense, was $0.45 per mcfe in second quarter 2025 and first six months 2025 compared to $0.44 per mcfe in the same periods of 2024. We have historically 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. The following table summarizes DD&A expense per mcfe for the three and six months ended June 30, 2025 and 2024:

25

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, brokered natural gas and marketing expense, exploration expense, abandonment and impairment of unproved properties, exit costs, deferred compensation plan expense and gain on early extinguishment of debt. Stock-based compensation includes the amortization of restricted stock grants and performance units. See Note 9 to our consolidated financial statements for more information on allocation of stock-based compensation by functional expense categories.

Brokered natural gas and marketing expense was $35.0 million in second quarter 2025 compared to $34.1 million in second quarter 2024 due to higher commodity prices slightly offset by lower broker purchase volumes (volumes not related to our production). Brokered natural gas and marketing expense was $93.2 million in first six months 2025 compared to $65.7 million in first six months 2024 due to higher commodity prices slightly offset by lower broker purchase volumes (volumes not related to our production). The following table details our brokered natural gas and marketing net margin for the three and six months ended June 30, 2025 and 2024 (in thousands):

Exploration expense was $7.9 million in second quarter 2025 compared to $6.7 million in second quarter 2024 mainly due to higher delay rentals. Exploration expense was $14.3 million in first six months 2025 compared to $11.2 million in first six months 2024 mainly due to higher delay rentals. The following table details our exploration expense for the three and six months ended June 30, 2025 and 2024 (in thousands):

Abandonment and impairment of unproved properties expense was $6.8 million in second quarter 2025 compared to $1.5 million in second quarter 2024. Abandonment and impairment of unproved properties expense was $11.4 million in first six months 2025 compared to $3.9 million in first six months 2024. Abandonment and impairment of unproved properties for second quarter 2025 and first six months 2025 increased when compared to the same periods of 2024 due to higher expected lease expirations in Pennsylvania. When we do not intend to drill on a property prior to expiration, we have allowed acreage to expire. We also expect to strategically allow expirations in the future, as we believe certain acreage needed for our future development plans can be efficiently leased again prior to development.

Exit costs were $8.5 million in second quarter 2025 compared to $10.1 million in second quarter 2024. Exit costs were $17.4 million in first six months 2025 compared to $20.4 million in first six months 2024. These costs are associated with normal accretion expense primarily related to retained liabilities for certain gathering, transportation and processing obligations extending through 2030.

Deferred compensation plan had a gain of $88,000 in second quarter 2025 compared to expense of $1.2 million in second quarter 2024. Deferred compensation plan expense was $2.8 million in first six months 2025 compared to $7.6 million in first six months 2024. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense based on the number of vested shares in the plan at the time. The reduction in both periods is related to fewer shares being held within the deferred compensation plan. The deferred compensation plan held 265,000 shares (256,000 vested shares) of Range common stock at June 30, 2025 compared to 811,000 shares (758,000 vested shares) at June 30, 2024.

Income tax expense was $64.5 million in second quarter 2025 compared to a benefit of $18.7 million in second quarter 2024. Income tax expense was $77.1 million in first six months 2025 compared to a benefit of $490,000 in first six months 2024. The 2025 and 2024 effective tax rates were different than the statutory tax rates due to tax credits, state income taxes and equity compensation.

Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity

Commodity prices are the most significant factor impacting our revenues, net income, operating cash flows, the amount of capital we invest in our business, payment of dividends and funding of share or debt repurchases. Commodity prices have been and are expected to remain volatile. Our top priorities for using cash provided by operations are to fund our capital program, return capital to stockholders and reduce debt further over time. We currently believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future and across a wide range of commodity price scenarios. We continue to manage the duration and level of our drilling and completion commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

Cash Flows

The following table presents sources and uses of cash and cash equivalents for the six months ended June 30, 2025 and 2024 (in thousands):

Sources of Cash and Cash Equivalents

Cash flows provided from operating activities in first six months 2025 were $666.3 million compared to $480.7 million in first six months 2024. Cash provided from operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. As of June 30, 2025, we have hedged more than 30% of our projected natural gas production for the remainder of 2025. Changes in working capital (as reflected in our consolidated statements of cash flows) for first six months 2025 was a negative $18.0 million compared to a negative $53.0 million for first six months 2024.

Borrowing on credit facility in first six months 2025 was $447.0 million which was utilized for the payoff of principal of our 4.875% senior notes due 2025 at its maturity date. Borrowings net of repayments on the credit facility for the first six months 2025 brought the credit facility balance to $125.0 million as of June 30, 2025.

Uses of Cash and Cash Equivalents

Additions to natural gas properties for first six months 2025 were consistent with expectations relative to our announced 2025 capital budget.

Repayment of senior notes for first six months 2025 includes the payoff of principal of our 4.875% senior notes due 2025 at its maturity date through utilization of cash and borrowing on our credit facility.

Treasury stock purchases for first six months 2025 include the repurchase and settlement of 3.3 million shares for a total of $120.4 million (excluding cost of 1% excise tax) as part of our previously announced stock repurchase program.

Liquidity and Capital Resources

Our main sources of liquidity are cash on hand, internally generated cash flow from operations, our bank credit facility and capital market transactions. At June 30, 2025, we had approximately $1.2 billion of liquidity consisting of $134,000 of cash on hand and $1.2 billion of availability under our bank credit facility. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties or financing activities. We may draw on our bank credit facility to meet short-term cash requirements.

We expect our 2025 capital program to be funded by cash flows from operations. During the six months ended June 30, 2025, we generated $666.3 million of cash flows from operating activities.

Bank Credit Facility

Our bank credit facility is secured by substantially all of our assets. As of June 30, 2025, we had a balance of $125.0 million on our credit facility and we maintained a borrowing base of $3.0 billion and aggregate lender commitments of $1.5 billion. We have undrawn letters of credit of $164.1 million as of June 30, 2025, which reduce our borrowing capacity under our bank credit facility.

The borrowing base is subject to regular, semi-annual re-determinations and is dependent on a number of factors but primarily the lenders' assessment of our future cash flows. Our scheduled borrowing base re-determination was completed in March 2025 with our borrowing base and lender commitments reaffirmed. We currently must comply with certain financial and non-financial covenants, including limiting dividend payments, debt incurrence and requirements that we maintain certain financial ratios (as defined in our bank credit facility agreement). We were in compliance with all such covenants at June 30, 2025.

Capital Requirements

We use cash for the development, exploration and acquisition of natural gas properties and for the payment of gathering, transportation and processing costs, operating, general and administrative costs, taxes and debt obligations, including interest, dividends and share repurchases. Expenditures for the development, exploration and acquisition of natural gas properties are the primary use of our capital resources. During first six months 2025, we used operating cash flows to fund $317.5 million of capital expenditures as reported in our consolidated statement of cash flows within investing activities. The amount of our future capital expenditures will depend upon a number of factors including our cash flows from operating, investing and financing activities, infrastructure availability, supply and demand fundamentals and our ability to execute our development program. In addition, the impact of commodity prices on investment opportunities, the availability of capital and the timing and results of our development activities may lead to changes in funding requirements for future development. We periodically review our budget to assess changes in current and projected cash flows, debt requirements and other factors.

We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities or a combination of both. Such repurchases or redemptions may be made in open market transactions and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Cash Dividend Payments

On May 30, 2025, our board of directors announced the approval of a dividend of $0.09 per share payable on June 27, 2025, to stockholders of record at the close of business on June 13, 2025. 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 primarily depends on cash flow, capital expenditures, debt covenants and various other factors.

Stock Repurchase Program

Our total remaining share repurchase authorization was approximately $895.7 million at June 30, 2025.

Other Sources of Liquidity

We have a universal shelf registration statement filed with the SEC under which we, as a well-known seasoned issuer for purposes of SEC rules, have the future ability to sell an indeterminate amount of various types of debt and equity securities.

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations and transportation, processing and gathering commitments including the divestiture contractual commitment that we incurred in conjunction with the sale of our North Louisiana assets. See Note 13 to our unaudited consolidated financial statements entitled "Commitments and

Contingencies" for more information on commitments.

Interest Rates

At June 30, 2025, we had approximately $1.2 billion of debt outstanding which bore interest at fixed rates averaging 6.7%. Bank debt totaling $125.0 million bears interest at a floating rate, which was 6.7% at June 30, 2025.

Off-Balance Sheet Arrangements

We do not currently utilize any significant off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments, some of which are described above under Cash Contractual Obligations.

Changes in Prices and Costs

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Certain of our costs and expenses are affected by general inflation and tariffs. We expect costs for the remainder of 2025 to continue to be a function of supply and demand.

Forward-Looking Statements

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as "anticipates," "believes," "expects," "targets," "plans," "estimates," "predicts," "may," "should," "would" or similar words indicating that future outcomes are uncertain. In accordance with "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our current forecasts for our existing operations and do not include the potential impact of any future events. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. For additional risk factors affecting our business, see Item 1A. Risk Factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2024, as filed with the SEC on February 25, 2025.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated. These risks have not materially changed and should be read in conjunction with Item 7A Quantitative and Qualitative Disclosures about Market Risk as presented in the Form 10-K.

Market Risk

We are exposed to market risks related to natural gas, NGLs and oil prices, which are difficult to predict. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivative instruments apply to a varying portion of our production and provide partial price protection. These arrangements can limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized prices are influenced by the complex dynamics of supply and demand that exist in the global energy markets. Changes in natural gas prices affect us more than changes in oil prices because approximately 64% of our December 31, 2024 proved reserves are natural gas and 1% of proved reserves are oil. In addition, a portion of our NGLs, which are 35% of proved reserves, are also impacted by changes in oil and natural gas prices. At times, we are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, 2024 to June 30, 2025.

We believe NGLs prices are somewhat seasonal, particularly for propane. Therefore, the relationship of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional U.S markets, some of which are exported to international markets by other parties. If we are not able to sell or store NGLs, we may be required to curtail production or shift our drilling activities to dry gas areas.

The Appalachian region has finite local demand and infrastructure to accommodate ethane. We have agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area. We cannot ensure these facilities will remain available. If we are not able to sell ethane under at least one of these agreements, we may be required to curtail production or, as we have done in the past, purchase or divert natural gas to blend with our residue gas.

Commodity Price Risk

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. At times, certain of our derivatives are swaps where we receive a fixed price (or a fixed percentage of a price) for our production and pay market prices to the counterparty. Our derivatives program can also include collars, which establish a minimum floor price and a predetermined ceiling price. Our program may also include a three-way collar which is a combination of three options. 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). At June 30, 2025, our derivative program includes swaps, collars, three-way collars and swaptions. The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation based on a comparison of the contract price and a reference price, generally NYMEX for natural gas and oil or Mont Belvieu for NGLs, approximated a net unrealized gain of $5.6 million as of June 30, 2025. These contracts expire monthly through December 2027. For additional information over our derivative contracts, see Note 7 to the accompanying consolidated financial statements.

Other Commodity Risk

We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. Therefore, in addition to the swaps, collars, three-way collars and swaptions discussed above, we have entered into natural gas basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX Henry Hub price because of basis adjustments, relative quality and other factors. Basis swap agreements effectively fix the basis adjustments. The fair value of the natural gas basis swaps was a gain of $19.9 million at June 30, 2025, and they settle through December 2029.

Commodity Sensitivity Analysis

The following table shows the fair value of our derivatives and the hypothetical changes in fair value that would result from a 10% and a 25% change in commodity prices at June 30, 2025. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):

Our commodity-based derivative contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified primarily among major investment grade financial institutions and we have master netting agreements with our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At June 30, 2025, our derivative counterparties include fourteen financial institutions, of which ten are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are primarily major investment grade financial institutions, the fair value of our derivative contracts has been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial.

Interest Rate Risk

At June 30, 2025, we had total debt of approximately $1.2 billion. Our outstanding debt includes $1.1 billion senior notes based on fixed interest rates. As this represents approximately 90% of our total debt balance, we do not have significant exposure to movements in market interest rates. Our bank credit facility provides for variable interest rate borrowings, which had a balance of $125.0 million as of June 30, 2025 and incurred interest at a rate of 6.7% at June 30, 2025. The 30-day SOFR rate at June 30, 2025 was approximately 4.3%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on June 30, 2025 would result in approximately $1.3 million in additional annual interest expense.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2025 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the three months ended June 30, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, 2024.