subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. Borrowings under the bank credit facility can either be at the alternate base rate (ABR, as defined in the bank credit facility agreement) plus a spread ranging from 0.75% to 1.75% or at the secured overnight financing rate (SOFR, as defined in such bank credit facility 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 base rate loans or to convert all or any part of the base rate loans to SOFR loans. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. As of March 31, 2026, 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. Our weighted average interest rate on the bank credit facility was 5.66% for the three months ended March 31, 2026. There was no debt outstanding on our bank credit facility as of March 31, 2025.
As part of our re-determination completed in March 2026, our borrowing base was reaffirmed at $3.0 billion and our bank commitment was also reaffirmed at $2.0 billion. As of March 31, 2026, bank commitments totaled $2.0 billion and we had $334.0 million outstanding on our bank credit facility. Additionally, on March 31, 2026 we had $165.1 million of undrawn letters of credit, leaving approximately $1.5 billion of committed borrowing capacity available under the facility.
Senior Notes
In January 2026, we fully redeemed the principal balance of our 8.25% senior notes due 2029 at 101.375% of par by borrowing on our bank credit facility. We recognized a loss on early extinguishment of debt of $12.3 million including the expense of the remaining unamortized debt issuance costs on the 8.25% senior notes.
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 aggregate principal amount plus accrued and unpaid interest, if any.
Guarantees
Range is a holding company that owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our 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:
•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.
(6) ASSET RETIREMENT OBLIGATIONS
Activity related to our liability for plugging and abandonment costs for the three months ended March 31, 2026 and the year ended December 31, 2025 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, 2026 |
|
|
Year Ended
December 31, 2025 |
|
Beginning of period |
$ |
148,952 |
|
|
$ |
133,767 |
|
Liabilities incurred |
|
778 |
|
|
|
3,778 |
|
Liabilities settled |
|
(30 |
) |
|
|
(865 |
) |
Accretion expense |
|
2,077 |
|
|
|
7,683 |
|
Change in estimate |
|
— |
|
|
|
4,589 |
|
End of period |
|
151,777 |
|
|
|
148,952 |
|
Less current portion |
|
(1,173 |
) |
|
|
(1,173 |
) |
Long-term asset retirement obligations |
$ |
150,604 |
|
|
$ |
147,779 |
|
Certain assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Our proved natural gas and oil properties are reviewed for impairment periodically as events or changes in circumstances indicate the carrying amount may not be recoverable. There were no proved property impairment charges for three months ended March 31, 2026 or 2025.
Concentrations of Credit Risk
As of March 31, 2026, our primary concentrations of credit risk are the risks of not collecting accounts receivable and the risk of a counterparty’s failure to perform under derivative obligations. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and/or credit ratings. 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. As of March 31, 2026, our derivative counterparties included fifteen financial institutions, of which ten were secured lenders in our bank credit facility. As of March 31, 2026, our net derivative position includes an aggregate net payable of $9.0 million to three counterparties not included in our bank credit facility and a net receivable of $982,000 from two counterparties not included in our bank credit facility.
(9) STOCK-BASED COMPENSATION PLANS
Total Stock-Based Compensation Expense
Refer to Note 10 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of stock-based compensation awards, their valuations and their award terms. Stock-based compensation represents amortization of time-based restricted stock and performance-based awards. The following details the allocation of stock-based compensation to functional expense categories (in thousands):
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
Direct operating expense |
$ |
546 |
|
|
$ |
537 |
|
Brokered natural gas and marketing expense |
|
884 |
|
|
|
840 |
|
Exploration expense |
|
334 |
|
|
|
347 |
|
General and administrative expense |
|
10,625 |
|
|
|
10,111 |
|
Total stock-based compensation expense |
$ |
12,389 |
|
|
$ |
11,835 |
|
The mark-to-market adjustment of the liability related to the restricted stock Liability Awards held in our deferred compensation plan as recorded in deferred compensation plan expense on our consolidated statements of income, is directly tied to the change in our stock price and not directly related to functional expenses and, therefore, is not allocated to the functional categories above.
Time-based - Equity Awards. These awards ("Equity Awards") are expensed ratably over the service period associated with the awards based on fair value. Fair value is based on prevailing market price on the date of grant and is expensed over a service period up to three years. We recorded compensation expense for these outstanding Equity Awards of $10.3 million in first three months 2026 compared to $10.1 million in the same period of 2025.
Time-based - Liability Awards. There have been no significant ("Liability Awards") grants since 2022, and we have no compensation expense recorded for these awards in 2026. Liability Awards were historically contributed into the deferred compensation plan (see further discussion below).
Performance-based TSR Awards ("TSRs" or "TSR Awards"). 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. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant.
Beginning in 2026, we granted performance awards that include (i) "relative" TSR units that will have payouts determined based on our total shareholder return relative to a peer group at the end of the performance period, which are similar to TSR grants made historically and (ii) "absolute" TSR units that will have payouts determined based on total shareholder return targets of our common stock for the performance period. We recorded compensation expense for TSR awards of $1.9 million in first three months 2026 compared to $1.3 million in the same period of 2025. Fair value is amortized over the performance period with no adjustment to the expense recorded for
actual targets achieved. The following assumptions were used to estimate the fair value of the TSR Awards granted during first three months 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2026 |
|
|
2025 |
|
Risk-free interest rate |
|
|
3.5 |
% |
|
|
4.2 |
% |
Expected annual volatility |
|
|
35 |
% |
|
|
46 |
% |
Grant date fair value per unit - relative TSR units |
|
$ |
40.46 |
|
|
$ |
44.39 |
|
Grant date fair value per unit - absolute TSR units |
|
$ |
38.47 |
|
|
$ |
— |
|
Equity Award Summary
The following is a summary of the activity for our time-based and performance-based stock awards for the three months ended March 31, 2026:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time-Based
Equity Awards |
|
|
Performance-Based
Stock Awards |
|
|
Shares |
|
|
Weighted
Average Grant
Date Fair Value |
|
|
Number
of Units (a) |
|
|
Weighted
Average Grant
Date Fair Value |
|
Outstanding at December 31, 2025 |
|
1,104,628 |
|
|
$ |
36.37 |
|
|
|
620,208 |
|
|
$ |
35.13 |
|
Granted |
|
1,140,576 |
|
|
|
35.81 |
|
|
|
236,122 |
|
|
|
39.79 |
|
Vested |
|
(297,722 |
) |
|
|
34.59 |
|
|
|
(145,747 |
) |
|
|
26.86 |
|
Forfeited |
|
(2,794 |
) |
|
|
36.22 |
|
|
|
— |
|
|
|
— |
|
Outstanding at March 31, 2026 |
|
1,944,688 |
|
|
$ |
36.31 |
|
|
|
710,583 |
|
|
$ |
38.37 |
|
(a)Amounts granted reflect performance units initially granted. The actual payout will be between zero and 200% depending on achievement of either total stockholder return ranking compared to our peers over the performance period or our absolute shareholder return ranking.
Deferred Compensation Plan
The assets of our deferred compensation plan are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our general creditors in the event of bankruptcy or insolvency. Our common stock held in the Rabbi Trust is accounted for as Liability Awards 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 $2.5 million in first quarter 2026 compared to a mark-to-market loss of $2.9 million in first quarter 2025. The Rabbi Trust held 248,000 shares (237,000 vested shares) of Range common stock as of March 31, 2026 compared to 266,000 shares (258,000 vested shares) as of December 31, 2025.
Trading securities. Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and 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 the changes in our deferred compensation assets and liabilities on the accompanying consolidated balance sheets. For first quarter 2026, interest and dividends were $106,000 and the mark-to-market loss was $1.8 million compared to interest and dividends of $133,000 and a mark-to-market loss of $928,000 in first quarter 2025.
(10) CAPITAL STOCK
Treasury Stock
In February 2026, our Board of Directors approved an increase to our existing stock repurchase program to an aggregate $1.5 billion. Our total remaining share repurchase authorization was $1.5 billion as of March 31, 2026. In first quarter 2026, we repurchased 800,000 shares at an aggregate investment of $27.1 million. The following is a schedule of the change in treasury shares based on settlement date for the three months ended March 31, 2026:
|
|
|
|
|
Three Months Ended
March 31, 2026 |
|
Beginning balance |
|
33,115,000 |
|
Shares repurchased |
|
800,000 |
|
Ending balance |
|
33,915,000 |
|
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, NGLs and oil 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, produce and sell 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;
•maintaining 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 war, military action in the Middle East and flows of energy commodities through the Strait of Hormuz; global inventories of natural gas, NGLs and oil; future U.S. infrastructure investment; future monetary and fiscal policy, tariffs and their impacts on global trade and energy demand; and governmental policies aimed at the energy sector, including those focused on 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 three months 2026, average natural gas prices increased primarily due to increased demand from winter weather and LNG export growth. Longer term natural gas futures prices remain constructive based on market expectations of continued LNG export expansion and increasing global power demand, while associated gas-related activity in oil basins and dry gas basin activity are expected to show modest rates of growth due to infrastructure constraints, moderated reinvestment rates and inventory exhaustion. In addition, the global energy shortage experienced in recent years and geopolitical disruptions of energy flows from key producing regions further highlighted the need for affordable and reliable fuel sources, supporting continued strong structural demand growth for U.S. LNG exports, as well as domestic electricity generation. Other factors such as 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 and operations.
Benchmarks for natural gas and oil increased in first quarter 2026 and NGLs decreased in first quarter 2026 compared to the same period of 2025.
The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the three months ended March 31, 2026 and 2025:
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
Benchmarks: |
|
|
|
|
|
Average NYMEX prices (a) |
|
|
|
|
|
Natural gas (per mcf) |
$ |
4.97 |
|
|
$ |
3.66 |
|
Oil (per bbl) |
|
73.98 |
|
|
|
71.40 |
|
Mont Belvieu NGLs composite (per gallon) (b) |
|
0.53 |
|
|
|
0.64 |
|
(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 First Quarter 2026 Results
In first quarter 2026, we experienced an increase in revenue from the sale of natural gas, NGLs and oil when compared to the same quarter of 2025, due to a 29% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) and a slight increase in total production.
During first quarter 2026, we recognized net income of $341.6 million, or $1.44 per diluted common share compared to net income of $97.1 million, or $0.40 per diluted common share during first quarter 2025. The higher net income in first quarter 2026 compared to first quarter 2025 is primarily due to increased realized prices.
Our first quarter 2026 financial and operating performance included the following results:
•revenue from the sale of natural gas, NGLs and oil increased 28% from the same period of 2025 due to a 27% increase in average realized prices (before cash settlements on our derivatives) combined with a slight increase in production volumes;
•revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) increased 21% from the same period of 2025;
•direct operating expense per mcfe increased to $0.14 in first quarter 2026 compared to $0.13 in the same period of 2025 due to an increase in winter operations and water hauling costs;
•transportation, gathering, processing and compression per mcfe increased to $1.63 in first quarter 2026 compared to $1.55 in the same period of 2025, primarily due to an increase in electricity rates and fuel prices;
•general and administrative expense per mcfe increased to $0.23 in first quarter 2026 compared to $0.21 in the same period of 2025 due to higher employee related costs; and
•interest expense per mcfe decreased 33% from the same period of 2025 due to lower debt balances and lower interest rates.
First quarter 2026 also included the following returns of capital and balance sheet highlights:
•repurchased $27.1 million (800,000 shares) of our common stock;
•paid $23.8 million of dividends, an 11% higher dividend of $0.10 per share compared to $0.09 per share in the same period of 2025; and
•reduced our higher interest rate debt by paying off the $600 million principal balance of our 8.25% senior notes due 2029 by utilizing borrowings under the credit facility, while retaining $1.5 billion in available liquidity under our credit facility.
We generated $619.1 million of cash from operating activities in first quarter 2026, an increase of $289.1 million from first quarter 2025, 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 months ended March 31, 2026 and 2025 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Natural gas, NGLs and oil sales |
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
$ |
704,081 |
|
|
$ |
490,377 |
|
|
$ |
213,704 |
|
|
|
44 |
% |
NGLs |
|
259,232 |
|
|
|
275,654 |
|
|
|
(16,422 |
) |
|
|
(6 |
)% |
Oil |
|
46,939 |
|
|
|
25,889 |
|
|
|
21,050 |
|
|
|
81 |
% |
Total natural gas, NGLs and oil sales |
$ |
1,010,252 |
|
|
$ |
791,920 |
|
|
$ |
218,332 |
|
|
|
28 |
% |
Production growth is generated 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 months ended March 31, 2026 and 2025 is set forth in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Production (a) |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
135,795,771 |
|
|
|
135,963,430 |
|
|
|
(167,659 |
) |
|
|
— |
% |
NGLs (bbls) |
|
9,737,382 |
|
|
|
9,919,989 |
|
|
|
(182,607 |
) |
|
|
(2 |
)% |
Oil (bbls) |
|
741,524 |
|
|
|
423,579 |
|
|
|
317,945 |
|
|
|
75 |
% |
Total (mcfe) (b) |
|
198,669,207 |
|
|
|
198,024,838 |
|
|
|
644,369 |
|
|
|
— |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production (a) |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mcf) |
|
1,508,842 |
|
|
|
1,510,705 |
|
|
|
(1,863 |
) |
|
|
— |
% |
NGLs (bbls) |
|
108,193 |
|
|
|
110,222 |
|
|
|
(2,029 |
) |
|
|
(2 |
)% |
Oil (bbls) |
|
8,239 |
|
|
|
4,706 |
|
|
|
3,533 |
|
|
|
75 |
% |
Total (mcfe) (b) |
|
2,207,436 |
|
|
|
2,200,276 |
|
|
|
7,160 |
|
|
|
— |
% |
(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 first quarter 2026 was $3.21 per mcfe compared to $2.48 per mcfe in first quarter 2025. 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 prices (including derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives. We believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense. Our average realized price calculations for three months ended March 31, 2026 and 2025 are shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Average Prices |
|
|
|
|
|
|
|
|
|
|
|
Average realized prices (excluding derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
$ |
5.18 |
|
|
$ |
3.61 |
|
|
$ |
1.57 |
|
|
|
43 |
% |
NGLs (per bbl) |
|
26.62 |
|
|
|
27.79 |
|
|
|
(1.17 |
) |
|
|
(4 |
)% |
Oil (per bbl) |
|
63.30 |
|
|
|
61.12 |
|
|
|
2.18 |
|
|
|
4 |
% |
Total (per mcfe) (a) |
|
5.09 |
|
|
|
4.00 |
|
|
|
1.09 |
|
|
|
27 |
% |
Average realized prices (including derivative settlements): |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
$ |
4.85 |
|
|
$ |
3.64 |
|
|
$ |
1.21 |
|
|
|
33 |
% |
NGLs (per bbl) |
|
26.62 |
|
|
|
27.75 |
|
|
|
(1.13 |
) |
|
|
(4 |
)% |
Oil (per bbl) |
|
58.41 |
|
|
|
61.72 |
|
|
|
(3.31 |
) |
|
|
(5 |
)% |
Total (per mcfe) (a) |
|
4.84 |
|
|
|
4.02 |
|
|
|
0.82 |
|
|
|
20 |
% |
Average realized prices (including derivative settlements and third-party transportation costs paid by Range): |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
$ |
3.60 |
|
|
$ |
2.48 |
|
|
$ |
1.12 |
|
|
|
45 |
% |
NGLs (per bbl) |
|
10.87 |
|
|
|
12.84 |
|
|
|
(1.97 |
) |
|
|
(15 |
)% |
Oil (per bbl) |
|
57.36 |
|
|
|
59.95 |
|
|
|
(2.59 |
) |
|
|
(4 |
)% |
Total (per mcfe) (a) |
|
3.21 |
|
|
|
2.48 |
|
|
|
0.73 |
|
|
|
29 |
% |
(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:
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, |
|
|
2026 |
|
|
2025 |
|
Average natural gas differentials above (below) NYMEX |
$ |
0.21 |
|
|
$ |
(0.05 |
) |
Realized (losses) on basis hedging |
$ |
(0.03 |
) |
|
$ |
(0.10 |
) |
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2025 |
|
|
Price
Variance |
|
|
Volume
Variance |
|
|
2026 |
|
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
Price (per mcf) |
$ |
3.61 |
|
|
$ |
1.57 |
|
|
$ |
— |
|
|
$ |
5.18 |
|
Production (Mmcf) |
|
135,963 |
|
|
|
— |
|
|
|
(167 |
) |
|
|
135,796 |
|
Natural gas sales |
$ |
490,377 |
|
|
$ |
214,309 |
|
|
$ |
(605 |
) |
|
$ |
704,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2025 |
|
|
Price
Variance |
|
|
Volume
Variance |
|
|
2026 |
|
NGLs |
|
|
|
|
|
|
|
|
|
|
|
Price (per bbl) |
$ |
27.79 |
|
|
$ |
(1.17 |
) |
|
$ |
— |
|
|
$ |
26.62 |
|
Production (Mbbls) |
|
9,920 |
|
|
|
— |
|
|
|
(183 |
) |
|
|
9,737 |
|
NGLs sales |
$ |
275,654 |
|
|
$ |
(11,348 |
) |
|
$ |
(5,074 |
) |
|
$ |
259,232 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2025 |
|
|
Price
Variance |
|
|
Volume
Variance |
|
|
2026 |
|
Oil |
|
|
|
|
|
|
|
|
|
|
|
Price (per bbl) |
$ |
61.12 |
|
|
$ |
2.18 |
|
|
$ |
— |
|
|
$ |
63.30 |
|
Production (Mbbls) |
|
424 |
|
|
|
— |
|
|
|
318 |
|
|
|
742 |
|
Oil sales |
$ |
25,889 |
|
|
$ |
1,617 |
|
|
$ |
19,433 |
|
|
$ |
46,939 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2025 |
|
|
Price
Variance |
|
|
Volume
Variance |
|
|
2026 |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
Price (per mcfe) |
$ |
4.00 |
|
|
$ |
1.09 |
|
|
$ |
— |
|
|
$ |
5.09 |
|
Production (Mmcfe) |
|
198,025 |
|
|
|
— |
|
|
|
644 |
|
|
|
198,669 |
|
Total natural gas, NGLs and oil sales |
$ |
791,920 |
|
|
$ |
215,755 |
|
|
$ |
2,577 |
|
|
$ |
1,010,252 |
|
Transportation, gathering, processing and compression expense was $323.3 million in first quarter 2026 compared to $306.1 million in first quarter 2025. These third-party costs are higher in first quarter 2026 compared to first quarter 2025 primarily due to higher electricity rates and fuel prices. We have included these costs in the calculation of average realized prices (including derivative settlements and third-party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the three months ended March 31, 2026 and 2025 on a per mcf and per barrel basis (in thousands, except for costs per unit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Transportation, gathering
processing and compression |
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
$ |
169,206 |
|
|
$ |
157,519 |
|
|
$ |
11,687 |
|
|
|
7 |
% |
NGLs |
|
153,344 |
|
|
|
147,838 |
|
|
|
5,506 |
|
|
|
4 |
% |
Oil |
|
779 |
|
|
|
752 |
|
|
|
27 |
|
|
|
4 |
% |
Total |
$ |
323,329 |
|
|
$ |
306,109 |
|
|
$ |
17,220 |
|
|
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per mcf) |
$ |
1.25 |
|
|
$ |
1.16 |
|
|
$ |
0.09 |
|
|
|
8 |
% |
NGLs (per bbl) |
|
15.75 |
|
|
|
14.90 |
|
|
|
0.85 |
|
|
|
6 |
% |
Oil (per bbl) |
|
1.05 |
|
|
|
1.77 |
|
|
|
(0.72 |
) |
|
|
(41 |
)% |
Total (per mcfe) |
$ |
1.63 |
|
|
$ |
1.55 |
|
|
|
0.08 |
|
|
|
5 |
% |
Derivative fair value loss was $33.4 million in first quarter 2026 compared to a loss of $159.0 million in first quarter 2025. 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 derivative losses indicate potentially higher future wellhead revenues. The following table summarizes the impact of our commodity derivatives for the three months ended March 31, 2026 and 2025 (in thousands):
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, |
|
|
2026 |
|
|
2025 |
|
Derivative fair value loss per consolidated statements of income |
$ |
(33,429 |
) |
|
$ |
(158,957 |
) |
|
|
|
|
|
|
Non-cash fair value income (loss): (a) |
|
|
|
|
|
Natural gas derivatives |
$ |
39,367 |
|
|
$ |
(163,067 |
) |
NGLs derivatives |
|
(9,982 |
) |
|
|
(551 |
) |
Oil derivatives |
|
(13,519 |
) |
|
|
88 |
|
Total non-cash fair value income (loss) (a) |
$ |
15,866 |
|
|
$ |
(163,530 |
) |
|
|
|
|
|
|
Net cash (payment) receipt on derivative settlements: |
|
|
|
|
|
Natural gas derivatives |
$ |
(45,669 |
) |
|
$ |
4,729 |
|
NGLs derivatives |
|
— |
|
|
|
(412 |
) |
Oil derivatives |
|
(3,626 |
) |
|
|
256 |
|
Total net cash (payment) receipt |
$ |
(49,295 |
) |
|
$ |
4,573 |
|
(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, NGLs and marketing revenue was $57.2 million in first quarter 2026 compared to $54.4 million in first quarter 2025, which is the result of higher commodity prices 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, NGLs and marketing expense below for more information on our net brokered margin.
Other income was $118,000 in first quarter 2026 compared to $3.2 million in first quarter 2025. This includes $55,000 of interest income and a $6,000 gain on sale of assets in first quarter 2026 compared to $3.1 million of interest income and a $62,000 gain on sale of assets in first quarter 2025. Interest income is lower in 2026 due to lower cash balances primarily resulting from the use of cash to repay senior notes in May 2025.
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 months ended March 31, 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Direct operating expense |
$ |
0.14 |
|
|
$ |
0.13 |
|
|
$ |
0.01 |
|
|
|
8 |
% |
Taxes other than income |
|
0.03 |
|
|
|
0.04 |
|
|
|
(0.01 |
) |
|
|
(25 |
)% |
General and administrative expense |
|
0.23 |
|
|
|
0.21 |
|
|
|
0.02 |
|
|
|
10 |
% |
Interest expense |
|
0.10 |
|
|
|
0.15 |
|
|
|
(0.05 |
) |
|
|
(33 |
)% |
Depletion, depreciation and amortization expense |
|
0.45 |
|
|
|
0.46 |
|
|
|
(0.01 |
) |
|
|
(2 |
)% |
Direct operating expense was $28.7 million in first quarter 2026 compared to $25.4 million in first quarter 2025. 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 first quarter 2026 primarily due to higher water hauling costs and winter operations costs. We incurred $644,000 of workover costs in first quarter 2026 compared to $789,000 in first quarter 2025. The following table summarizes direct operating expense per mcfe for the three months ended March 31, 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Direct operating |
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
$ |
0.14 |
|
|
$ |
0.13 |
|
|
$ |
0.01 |
|
|
|
8 |
% |
Workovers |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
% |
Stock-based compensation |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
% |
Total direct operating expense |
$ |
0.14 |
|
|
$ |
0.13 |
|
|
$ |
0.01 |
|
|
|
8 |
% |
Taxes other than income expense is predominantly comprised of the Pennsylvania impact fee which functions as a tax on unconventional natural gas and oil production in Pennsylvania. This impact fee was $5.8 million in first quarter 2026 compared to $6.8 million in first quarter 2025. The impact fee is based on drilling activities and is adjusted based on annual prevailing natural gas prices, which is comparable to the 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 months ended March 31, 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Taxes other than income |
|
|
|
|
|
|
|
|
|
|
|
Impact fee |
$ |
0.03 |
|
|
$ |
0.04 |
|
|
$ |
(0.01 |
) |
|
|
(25 |
)% |
Other |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
% |
Total taxes other than income |
$ |
0.03 |
|
|
$ |
0.04 |
|
|
$ |
(0.01 |
) |
|
|
(25 |
)% |
General and administrative (G&A) expense was $45.4 million in first quarter 2026 compared to $41.7 million in first quarter 2025. The first quarter 2026 increase of $3.7 million compared to the same period of 2025 is primarily due to higher employee related costs. The following table summarizes G&A expense on a per mcfe basis for the three months ended March 31, 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
$ |
0.18 |
|
|
$ |
0.16 |
|
|
$ |
0.02 |
|
|
|
13 |
% |
Stock-based compensation |
|
0.05 |
|
|
|
0.05 |
|
|
|
— |
|
|
|
— |
% |
Total general and administrative expense |
$ |
0.23 |
|
|
$ |
0.21 |
|
|
$ |
0.02 |
|
|
|
10 |
% |
Interest expense was $19.4 million in first quarter 2026 compared to $29.2 million in first quarter 2025. The following table presents information about interest expense per mcfe for the three months ended March 31, 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Bank credit facility (a) |
$ |
0.05 |
|
|
$ |
0.01 |
|
|
$ |
0.04 |
|
|
|
400 |
% |
Senior notes |
|
0.04 |
|
|
|
0.13 |
|
|
|
(0.09 |
) |
|
|
(69 |
)% |
Amortization of debt issuance costs and other |
|
0.01 |
|
|
|
0.01 |
|
|
|
— |
|
|
|
— |
% |
Total interest expense |
$ |
0.10 |
|
|
$ |
0.15 |
|
|
$ |
(0.05 |
) |
|
|
(33 |
)% |
Average debt outstanding ($000) |
$ |
1,210,027 |
|
|
$ |
1,706,718 |
|
|
$ |
(496,691 |
) |
|
|
(29 |
)% |
Average interest rate (b) |
|
6.1 |
% |
|
|
6.5 |
% |
|
|
(0.4 |
)% |
|
|
(6 |
)% |
(a)Includes commitment fees.
(b)Excludes debt issuance costs.
The decrease in interest expense for three months ended March 31, 2026 compared to the same period of 2025 was primarily due to lower average outstanding debt balances and lower interest rates. In January 2026, we repaid the $600 million principal balance of our 8.25% senior notes due 2029 by utilizing borrowings on our credit facility. We had $334.0 million outstanding on the bank credit facility as of March 31, 2026 compared to no bank debt outstanding for the same period of 2025.
Depletion, depreciation and amortization (DD&A) expense was $88.5 million in first quarter 2026 compared to $90.6 million in first quarter 2025. This decrease is due to a lower depletion rate offset by slightly higher production volumes. Depletion expense, the largest component of DD&A expense, was $0.44 per mcfe in first quarter 2026 compared to $0.45 per mcfe in the same period of 2025. 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 months ended March 31, 2026 and 2025:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
DD&A |
|
|
|
|
|
|
|
|
|
|
|
Depletion and amortization |
$ |
0.44 |
|
|
$ |
0.45 |
|
|
$ |
(0.01 |
) |
|
|
(2 |
)% |
Depreciation |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
% |
Accretion and other |
|
0.01 |
|
|
|
0.01 |
|
|
|
— |
|
|
|
— |
% |
Total DD&A expense |
$ |
0.45 |
|
|
$ |
0.46 |
|
|
$ |
(0.01 |
) |
|
|
(2 |
)% |
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 loss 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, NGLs and marketing expense was $58.1 million in first quarter 2026 compared to $58.2 million in first quarter 2025 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 months ended March 31, 2026 and 2025 (in thousands):
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, |
|
|
2026 |
|
|
2025 |
|
Brokered natural gas, NGLs and marketing |
|
|
|
|
|
Brokered natural gas sales |
$ |
52,877 |
|
|
$ |
51,085 |
|
Brokered NGLs sales |
|
2,266 |
|
|
|
1,767 |
|
Other marketing revenue |
|
2,086 |
|
|
|
1,556 |
|
Brokered natural gas purchases and transportation |
|
(52,779 |
) |
|
|
(53,465 |
) |
Brokered NGLs purchases |
|
(2,223 |
) |
|
|
(1,834 |
) |
Other marketing expense |
|
(3,121 |
) |
|
|
(2,902 |
) |
Net brokered natural gas, NGLs and marketing net margin |
$ |
(894 |
) |
|
$ |
(3,793 |
) |
Exploration expense was $6.0 million in first quarter 2026 compared to $6.4 million in first quarter 2025 mainly due to lower delay rentals somewhat offset by higher personnel expense. The following table details our exploration expense for the three months ended March 31, 2026 and 2025 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
Change |
|
|
% |
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
Delay rentals and other |
$ |
4,138 |
|
|
$ |
4,488 |
|
|
$ |
(350 |
) |
|
|
(8 |
)% |
Seismic |
|
— |
|
|
|
124 |
|
|
|
(124 |
) |
|
|
(100 |
)% |
Personnel expense |
|
1,558 |
|
|
|
1,432 |
|
|
|
126 |
|
|
|
9 |
% |
Stock-based compensation expense |
|
334 |
|
|
|
347 |
|
|
|
(13 |
) |
|
|
(4 |
)% |
Total exploration expense |
$ |
6,030 |
|
|
$ |
6,391 |
|
|
$ |
(361 |
) |
|
|
(6 |
)% |
Abandonment and impairment of unproved properties expense was $3.9 million in first quarter 2026 compared to $4.6 million in first quarter 2025. Abandonment and impairment of unproved properties for first quarter 2026 decreased when compared to the same period of 2025 due to lower than 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 $7.0 million in first quarter 2026 compared to $8.9 million in first quarter 2025. 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 loss of $2.5 million in first quarter 2026 compared to a loss of $2.9 million in first quarter 2025. 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 change in both periods is related to the change in Range stock price at the end of each period combined with fewer shares being held within the deferred compensation plan. The deferred compensation plan held 248,000 shares (237,000 vested shares) of Range common stock as of March 31, 2026 compared to 621,000 shares (609,000 vested shares) as of March 31, 2025.
Loss on early extinguishment of debt was $12.3 million in first quarter 2026 compared to a gain of $3,000 in first quarter 2025. During January 2026 we fully redeemed the $600 million principal balance of our 8.25% senior notes due 2029. The redemption price was equal to 101.375% of par. In addition to the premium paid on early redemption of $8.2 million, all $4.1 million of the unamortized debt issuance costs associated with the redemption were written off to loss on early extinguishment of debt.
Income tax expense was $91.5 million in first quarter 2026 compared to an expense of $12.7 million in first quarter 2025. The 2026 effective tax rates were not materially different than the federal statutory rate. The 2025 effective tax rates were lower than the federal statutory rate due primarily 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, and the amount of capital we have available to invest in our business, pay dividends and fund 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 maintain a strong balance sheet while making prudent investments in our business. 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 three months ended March 31, 2026 and 2025 (in thousands):
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
Sources of cash and cash equivalents |
|
|
|
|
|
Operating activities |
$ |
619,136 |
|
|
$ |
330,083 |
|
Disposal of assets |
|
31 |
|
|
|
50 |
|
Borrowings on credit facility |
|
1,182,000 |
|
|
|
— |
|
Other |
|
13,642 |
|
|
|
3,996 |
|
Total sources of cash and cash equivalents |
$ |
1,814,809 |
|
|
$ |
334,129 |
|
|
|
|
|
|
|
Uses of cash and cash equivalents |
|
|
|
|
|
Additions to natural gas, NGLs and oil properties |
$ |
(158,310 |
) |
|
$ |
(132,681 |
) |
Repayments on credit facility |
|
(966,000 |
) |
|
|
— |
|
Acreage purchases |
|
(7,633 |
) |
|
|
(24,919 |
) |
Additions to field service assets and other |
|
(1,793 |
) |
|
|
(722 |
) |
Repayment of senior notes |
|
(608,250 |
) |
|
|
(2,157 |
) |
Treasury stock purchases |
|
(27,124 |
) |
|
|
(67,477 |
) |
Dividends paid |
|
(23,835 |
) |
|
|
(21,613 |
) |
Other |
|
(21,821 |
) |
|
|
(44,476 |
) |
Total uses of cash and cash equivalents |
$ |
(1,814,766 |
) |
|
$ |
(294,045 |
) |
Sources of Cash and Cash Equivalents
Cash flows provided from operating activities in first three months 2026 were $619.1 million compared to $330.1 million in first three months 2025. 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 March 31, 2026, we have hedged more than 35% of our projected natural gas production for the remainder of 2026. Changes in working capital (as reflected in our consolidated statements of cash flows) for first three months 2026 was a positive $79.5 million compared to a negative $61.4 million for first three months 2025.
Borrowings on credit facility in first three months 2026 were $1.2 billion, of which approximately $608 million was utilized for the early redemption of principal of our 8.25% senior notes due 2029. Borrowings net of repayments on the credit facility for the first three months 2026 brought the credit facility balance to $334.0 million as of March 31, 2026.
Uses of Cash and Cash Equivalents
Additions to natural gas, NGLs and oil properties for first three months 2026 were consistent with expectations relative to our announced 2026 capital budget.
Repayment of senior notes for first three months 2026 includes the early redemption of principal of our 8.25% senior notes due 2029 through utilization of borrowings on our credit facility.
Treasury stock purchases for first three months 2026 include the repurchase and settlement of 800,000 shares for a total of $27.1 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 internally generated cash flow from operations, cash on hand, our bank credit facility and capital market transactions. As of March 31, 2026, we had approximately $1.5 billion of liquidity consisting of $247,000 of cash on hand and $1.5 billion available 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 2026 capital program to be funded by cash flows from operations. During the three months ended March 31, 2026, we generated $619.1 million of cash flows from operating activities.
Bank Credit Facility
Our bank credit facility is secured by substantially all of our assets. As of March 31, 2026, we had a balance of $334.0 million on our credit facility and we maintained a borrowing base of $3.0 billion and aggregate lender commitments of $2.0 billion. We had undrawn letters of credit of $165.1 million as of March 31, 2026, which reduced our borrowing capacity under our bank credit facility.
The borrowing base is subject to regular, annual re-determinations and is dependent on a number of factors but primarily the lenders' assessment of our future cash flows. On October 2, 2025, we entered into an amended and restated revolving bank credit facility, which continues to be secured by substantially all of our assets and has a maturity date of October 2, 2030. This amended credit facility maintains a maximum facility amount of $4.0 billion and an initial borrowing base of $3.0 billion, and increased bank commitments from $1.5 billion to $2.0 billion.
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 as of March 31, 2026.
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 three months 2026, we used operating cash flows to fund $167.7 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 February 27, 2026, our Board of Directors announced the approval of a dividend of $0.10 per share payable on March 27, 2026, to stockholders of record at the close of business on March 13, 2026. 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
In February 2026, our Board of Directors approved an increase to our existing stock repurchase program to an aggregate $1.5 billion. Our total remaining share repurchase authorization was $1.5 billion as of March 31, 2026.
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
As of March 31, 2026, we had approximately $500 million of senior notes which bore interest at fixed rates of 4.75%. Bank debt totaling $334.0 million bears interest at a floating rate, which was 5.4% as of March 31, 2026.
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 2026 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, 2025, as filed with the SEC on February 24, 2026.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 65% of our December 31, 2025 proved reserves are natural gas and 1% of proved reserves are oil. In addition, a portion of our NGLs, which are 34% 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, 2025 to March 31, 2026.
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). As of March 31, 2026, 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, was an asset of $94.5 million as of March 31, 2026. These contracts expire monthly through December 2028. For additional information on 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 liability of $12.8 million as of March 31, 2026, and they settle through December 2030.
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 as of March 31, 2026. 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):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hypothetical Change in Fair Value |
|
|
|
|
|
Increase in Commodity
Price of |
|
|
Decrease in Commodity
Price of |
|
|
Fair Value |
|
|
10% |
|
|
25% |
|
|
10% |
|
|
25% |
|
Swaps |
$ |
72,982 |
|
|
$ |
(68,692 |
) |
|
$ |
(171,731 |
) |
|
$ |
68,692 |
|
|
$ |
171,731 |
|
Collars |
|
427 |
|
|
|
(2,010 |
) |
|
|
(5,065 |
) |
|
|
2,012 |
|
|
|
5,094 |
|
Three-way collars |
|
23,478 |
|
|
|
(30,442 |
) |
|
|
(77,191 |
) |
|
|
27,247 |
|
|
|
59,729 |
|
Basis swaps |
|
(12,766 |
) |
|
|
5,616 |
|
|
|
14,040 |
|
|
|
(5,616 |
) |
|
|
(14,040 |
) |
Swaptions |
|
(2,418 |
) |
|
|
(6,831 |
) |
|
|
(26,273 |
) |
|
|
2,091 |
|
|
|
2,415 |
|
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. As of March 31, 2026, our derivative counterparties include fifteen 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
As of March 31, 2026, we had total debt of $834.0 million, of which $500 million, or approximately 60% were senior notes based on fixed interest rates and the remainder is based on variable rates. Our bank credit facility provides for variable interest rate borrowings, which had a balance of $334.0 million as of March 31, 2026 and incurred interest at a rate of 5.4% as of March 31, 2026. The 30-day SOFR rate as of March 31, 2026 was approximately 3.7%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on March 31, 2026 would result in approximately $3.3 million in additional annual interest expense.
ITEM 4. CONTROLS AND PROCEDURES
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 March 31, 2026 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 March 31, 2026 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.