RANGE RESOURCES CORP (RRC)

CIK: 0000315852. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-24.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=315852. Latest filing source: 0001193125-26-067292.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-24. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000315852.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-21. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000315852.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001193125-26-167076.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-04-21. Report date: 2026-03-31.

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.

17

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.

18

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 R

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-24. Report date: 2025-12-31.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition and should be read in conjunction with the information under Item 8. Financial Statements and Supplementary Data and other financial information found elsewhere in this Form 10-K. See also matters referenced in the foregoing pages under "Disclosures Regarding Forward-Looking Statements."

The following tables and discussions set forth key operating and financial data for the years ended December 31, 2025 and 2024. For similar discussions of the year ended December 31, 2024 compared to December 31, 2023 results, refer to Item 7. Managements’ Discussion and Analysis of Financial Condition and Results of Operations under Part II of our annual report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC on February 25, 2025.

Overview of Our Business

We are an independent natural gas, NGLs and oil company engaged in the exploration, development and acquisition of natural gas, NGLs and oil properties located 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 an area-by-area basis.

Our overarching business objective is to build stockholder value through returns-focused development of natural gas, NGLs and oil 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 any 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 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 require us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities.

Outlook for 2026

As we enter 2026, we believe we are positioned for sustainable long-term success. For 2026, we expect our capital budget to be in the range of $650 million to $700 million for natural gas, NGLs and oil related activities, excluding any potential acquisitions, for which we do not budget. As has been our historical practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity prices, drilling success and other factors. We expect our 2026 capital budget to achieve modest growth in production relative to 2025 production, while also supporting our longer-term operational plans. Our 2026 capital budget is focused on generating free cash flow while efficiently developing our resource base to achieve competitive full cycle

32

returns for our stockholders. The prices we receive for our natural gas, NGLs and oil production are largely based on current market prices, which are beyond our control. The price risk on a portion of our forecasted natural gas, NGLs and oil production for 2026 is partially mitigated by entering into commodity derivative contracts, and we intend to continue to enter into these types of contracts. We believe it is likely that commodity prices will continue to be volatile during 2026.

Market Conditions

We continue to monitor the impact of the actions of OPEC and other large producing nations, the Russia-Ukraine conflict, tensions in the Middle East, 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 transitioning towards lower carbon energy. We expect prices for commodities we produce to remain volatile given the complex dynamics of supply and demand that exist in the global energy markets. During 2025, natural gas prices increased primarily due to increased exports from new U.S. LNG export facilities. Longer term natural gas futures prices remain constructive based on market expectations that associated gas-related activity in oil basins and dry gas basin activity will show modest rates of growth due to infrastructure constraints, moderated reinvestment rates and core inventory exhaustion. In addition, the global energy shortage experienced in recent years further highlighted the need for affordable and reliable fuel sources, supporting continued strong structural demand growth for United States LNG exports, as well as domestic electricity generation. Other factors such as geopolitical disruptions, supply chain disruptions, cost inflation, concerns over a potential economic recession and the pace and changes in global monetary policy may impact global demand for natural gas, NGLs and oil. We continue to assess and monitor the impact and consequences of these factors on our business and operations.

Benchmarks for natural gas increased in 2025 compared to 2024, while NGLs slightly decreased. As a result, we have experienced increases in our price realizations in 2025. Recently, benchmark natural gas prices have increased further compared to the fourth quarter 2025, with the average NYMEX monthly settlement price for natural gas increasing to $4.69 per mcf for January 2026 and $7.46 for February 2026 settlement following winter weather. The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the years ended December 31, 2025 and 2024.

Year Ended December 31,

2025

2024

Benchmarks:

Average NYMEX prices (a)

Natural gas (per mcf)

$

3.43

$

2.27

Oil (per bbl)

64.52

76.17

Mont Belvieu NGLs composite (per gallon) (b)

0.55

0.56

(a)
Based on average of monthly last day settlement prices on the New York Mercantile Exchange ("NYMEX").

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

Prices for various quantities of 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 the benchmarks for many reasons, including quality, location, or production being sold at different prices.

Management’s Discussion and Analysis of Results of Operations

Overview of 2025 Results

For the year ended December 31, 2025, we experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a 14% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) compared to 2024. Daily production in 2025 averaged 2.24 Bcfe compared to 2.18 Bcfe in 2024.

During 2025, we recognized net income of $658.0 million, or $2.74 per diluted common share compared to $266.3 million, or $1.09 per diluted common share during 2024. The increase in net income for the year ended December 31, 2025 compared to 2024 is primarily due to higher realized prices combined with slightly higher production.

During 2025, our financial and operating performance included the following results:

•
revenue from the sale of natural gas, NGLs and oil increased 27% from the same period of 2024 with a 24% 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 11% from the same period of 2024;

33

•
transportation, gathering, processing and compression expense per mcfe was $1.50 in 2025 compared to $1.48 in the same period of 2024 primarily due to the increase of electricity costs and FERC rates;

•
direct operating expense per mcfe increased to $0.13 in 2025 compared to $0.12 in the same period of 2024 due to an increase in workover costs;

•
general and administrative expense per mcfe for 2025 remained the same at $0.22 compared to the same period of 2024;

•
interest expense per mcfe for 2025 decreased 13% from the same period of 2024 due to lower debt balances;

•
our DD&A rate per mcfe for 2025 remained the same compared to the same period of 2024;

•
drilled and completed 53 net wells with a 100% success rate;

The year ended December 31, 2025 also included the following returns of capital and balance sheet highlights:

•
paid $85.7 million in dividends, increasing per share dividend by 12.5% to an annual $0.36 per common share compared to $0.32 per common share in 2024;

•
repurchased $230.6 million of our common stock compared to $65.3 million in 2024;

•
repurchased in the open market $2.2 million principal amount of our 4.875% senior notes due 2025 at a discount and repaid the remaining $606.5 million principal balance of our 4.875% senior notes due 2025 at par by utilizing cash on hand and borrowing on our credit facility;

•
maintained substantial liquidity with the accumulation of cash on hand of $204,000 along with $1.7 billion available under our credit facility;

•
enabled longer laterals and enhanced efficiency through continued selective acreage leasing and lease renewals to consolidate our acreage positions in the Marcellus Shale play in Pennsylvania by investing $51.8 million to acquire unproved acreage; and

•
our capital investment for 2025 was $673.8 million, which was within our announced range of $650.0 million to $690.0 million.

We generated $1.2 billion of cash from operating activities in 2025, which is $226.8 million higher compared to 2024 and reflects higher realized prices and higher production volumes.

The year ended December 31, 2025 also included the following highlights that emphasized our corporate sustainability initiatives:

•
expanded "A" grade MiQ certification to include all Pennsylvania production;

•
maintained net zero scope 1 and 2 GHG emissions through direct emissions reductions and verified carbon credits;

•
continued to recycle approximately 100% of our flowback and produced water generated from our operations; and

•
expanded the installation and use of compressed air pneumatic controllers.

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

Our revenues vary from year-to-year as a result of changes in realized commodity prices and production volumes. The following table illustrates the primary components of natural gas, NGLs and oil sales for the last two years (in thousands):

Year Ended December 31,

2025

2024

Change

%

Natural gas, NGLs and oil sales

Natural gas

$

1,730,205

$

1,052,442

$

677,763

64

%

NGLs

979,313

1,020,903

(41,590

)

(4

)%

Oil

106,073

140,505

(34,432

)

(25

)%

Total natural gas, NGLs and oil sales

$

2,815,591

$

2,213,850

$

601,741

27

%

34

Production growth is generated through drilling success as we place new wells on production, which is partially offset by the natural decline of our natural gas, NGLs and oil reserves through production. Our production for the last two years is set forth in the following table:

Year Ended December 31,

2025

2024

Change

%

Production (a)

Natural gas (mcf)

560,891,967

545,415,974

15,475,993

3

%

NGLs (bbls)

40,551,764

39,622,576

929,188

2

%

Oil (bbls)

1,975,937

2,180,528

(204,591

)

(9

)%

Total (mcfe) (b)

816,058,173

796,234,598

19,823,575

2

%

Average daily production (a)

Natural gas (mcf)

1,536,690

1,490,208

46,482

3

%

NGLs (bbls)

111,101

108,258

2,843

3

%

Oil (bbls)

5,414

5,958

(544

)

(9

)%

Total (mcfe) (b)

2,235,776

2,175,504

60,272

3

%

(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 and natural gas, which is not indicative of the relationship between oil and natural gas prices.

Our average realized price (including derivative settlements and third-party transportation costs paid by Range) received during 2025 was $2.10 per mcfe compared to $1.84 per mcfe in 2024. The majority of our production is sold at market-based prices. We believe computed final realized prices should include the impact of transportation, gathering, processing and compression expense. Average sales prices (excluding derivative settlements) do not include any derivative settlements or third-party transportation costs which are reported in transportation, gathering and compression expense on the accompanying consolidated statements of income. Average sales prices (excluding derivative settlements) do include transportation costs where we receive net proceeds from the purchaser. Our average realized price (including derivative settlements and third-party transportation costs paid by Range) calculation includes cash settlements for derivatives. Average realized price calculations for the last two years are shown below:

Year Ended December 31,

2025

2024

Change

%

Average Prices

Average realized prices (excluding derivative settlements):

Natural gas (per mcf)

$

3.08

$

1.93

$

1.15

60

%

NGLs (per bbl)

24.15

25.77

(1.62

)

(6

)%

Oil (per bbl)

53.68

64.44

(10.76

)

(17

)%

Total (per mcfe) (a)

3.45

2.78

0.67

24

%

Average realized prices (including derivative settlements):

Natural gas (per mcf)

$

3.29

$

2.70

$

0.59

22

%

NGLs (per bbl)

24.28

25.86

(1.58

)

(6

)%

Oil (per bbl)

55.06

68.77

(13.71

)

(20

)%

Total (per mcfe) (a)

3.60

3.32

0.28

8

%

Average realized prices (including derivative settlements and third-party transportation costs paid by Range):

Natural gas (per mcf)

$

2.17

$

1.58

$

0.59

37

%

NGLs (per bbl)

9.67

11.62

(1.95

)

(17

)%

Oil (per bbl)

53.35

67.87

(14.52

)

(21

)%

Total (per mcfe) (a)

2.10

1.84

0.26

14

%

(a)
Oil and NGLs volumes are converted 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:

Year Ended December 31,

2025

2024

Average natural gas differentials below NYMEX

$

(0.35

)

$

(0.34

)

Realized gains (losses) on basis hedging

$

(0.02

)

$

(0.02

)

35

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

Year Ended December 31,

2024

Price

Variance

Volume

Variance

2025

Natural gas

Price (per mcf)

$

1.93

$

1.15

$

—

$

3.08

Production (Mmcf)

545,416

—

15,476

560,892

Natural gas sales

$

1,052,442

$

647,900

$

29,863

$

1,730,205

Year Ended December 31,

2024

Price

Variance

Volume

Variance

2025

NGLs

Price (per bbl)

$

25.77

$

(1.62

)

$

—

$

24.15

Production (Mbbls)

39,623

—

929

40,552

NGLs sales

$

1,020,903

$

(65,531

)

$

23,941

$

979,313

Year Ended December 31,

2024

Price

Variance

Volume

Variance

2025

Oil

Price (per bbl)

$

64.44

$

(10.76

)

$

—

$

53.68

Production (Mbbls)

2,181

—

(205

)

1,976

Oil sales

$

140,505

$

(21,249

)

$

(13,183

)

$

106,073

Year Ended December 31,

2024

Price

Variance

Volume

Variance

2025

Consolidated

Price (per mcfe)

$

2.78

$

0.67

$

—

$

3.45

Production (Mmcfe)

796,235

—

19,823

816,058

Total natural gas, NGLs and oil sales

$

2,213,850

$

546,623

$

55,118

$

2,815,591

Transportation, gathering, processing and compression expense was approximately $1.2 billion in 2025 and 2024. As shown in the table below, these third-party costs are higher than the prior year due to an increase in electricity costs, FERC charges and an increase in NGLs volumes which increases processing cost. 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 last two years (in thousands) and on a per mcf and per barrel basis:

Year Ended December 31,

2025

2024

Change

%

Transportation, gathering

     processing and compression

Natural gas

$

627,651

$

611,698

$

15,953

3

%

NGLs

592,296

564,269

28,027

5

%

Oil

3,377

1,958

1,419

72

%

Total

$

1,223,324

$

1,177,925

$

45,399

4

%

Natural gas (per mcf)

$

1.12

$

1.12

$

—

—

%

NGLs (per bbl)

14.61

14.24

0.37

3

%

Oil (per bbl)

1.71

0.90

0.81

90

%

      Total (per mcfe)

$

1.50

$

1.48

0.02

1

%

36

Derivative fair value income was $121.5 million in 2025 compared to income of $56.7 million in 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 in our revenues as the change in 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 lower wellhead revenues in the future while losses indicate higher future wellhead revenues. The following table summarizes the impact of our commodity derivatives for the last two years (in thousands):

Year Ended

December 31,

2025

2024

Derivative fair value income per consolidated statements of income

$

121,535

$

56,726

Non-cash fair value loss: (a)

Natural gas derivatives

$

(1,138

)

$

(364,467

)

NGLs derivatives

—

—

Oil derivatives

—

(11,199

)

Total non-cash fair value loss (a)

$

(1,138

)

$

(375,666

)

Net cash receipt on derivative settlements:

Natural gas derivatives

$

114,864

$

419,199

NGLs derivatives

5,096

3,743

Oil derivatives

2,713

9,450

Total net cash receipt

$

122,673

$

432,392

(a)
Non-cash fair value adjustments on commodity derivatives is a non-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 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 $172.6 million in 2025 compared to $133.0 million in 2024. We enter into purchase transactions with third parties and separate sale transactions with third parties at different times to utilize available pipeline capacity and to fulfill sales commitments in the event of operational upsets. These brokered revenues increased compared to 2024 due to higher sales prices partially offset by lower brokered volumes. See also Brokered natural gas and marketing expense below for more information on our net brokered margin.

Other income was $5.8 million in 2025 compared to $13.5 million in 2024. This includes $4.9 million of interest income and $261,000 of gain on sale of assets in 2025 compared to $12.7 million of interest income and $311,000 gain on sale of assets in 2024. Interest income is lower in the current year due to lower cash balances that earn interest in 2025 compared to 2024. In 2023 and prior, interest income was included within brokered natural gas and marketing revenue and other and gain on sale of assets was its own discrete line item within our annual report on Form 10-K for the year ended December 31, 2023. In 2024, and for the prior years presented in the accompanying consolidated statements of income, we reclassified both of these items into other income on the accompanying consolidated statements of income.

Costs and Expenses per mcfe

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the last two years:

Year Ended December 31,

2025

2024

Change

%

Direct operating expense

$

0.13

$

0.12

$

0.01

8

%

Taxes other than income

0.04

0.03

0.01

33

%

General and administrative expense

0.22

0.22

—

—

%

Interest expense

0.13

0.15

(0.02

)

(13

)%

Depletion, depreciation and amortization expense

0.45

0.45

—

—

%

37

Direct operating expense was $102.2 million in 2025 compared to $95.3 million in 2024. Direct operating expenses include normally recurring expenses to operate and produce our wells, workover and repair-related expenses. Our direct operating expenses for 2025 increased from the prior year primarily due to higher workover and water hauling costs. We incurred $6.0 million of workover costs in 2025 compared to $3.3 million of workover costs in 2024. Stock-based compensation expense represents the amortization of equity grants as part of the compensation of field employees. The following table summarizes direct operating expenses per mcfe for the last two years:

Year Ended December 31,

2025

2024

Change

%

Direct operating

Lease operating expense

$

0.12

$

0.12

$

—

—

%

Workovers

0.01

—

0.01

100

%

Stock-based compensation

—

—

—

—

%

Total direct operating expense

$

0.13

$

0.12

$

0.01

8

%

Taxes other than income expense was $32.8 million in 2025 compared to $21.6 million in 2024. This expense category is primarily the Pennsylvania impact fee. In 2012, Pennsylvania enacted an "impact fee" on unconventional natural gas, NGLs and oil production which includes the Marcellus Shale. The impact fee is based upon the year wells are drilled and the fee varies, like a severance tax, based upon natural gas prices. The year ended December 31, 2025 includes a $31.6 million impact fee compared to $21.2 million in the year ended December 31, 2024, with the increase primarily due to an increase in the average fee per well caused by higher natural gas prices in 2025 compared to 2024. This category also includes other taxes such as franchise, real estate and commercial activity taxes. The following table summarizes taxes other than income per mcfe for the last two years:

Year Ended December 31,

2025

2024

Change

%

Taxes other than income

Impact fee

$

0.04

$

0.03

$

0.01

33

%

Other

—

—

—

—

%

Total taxes other than income

$

0.04

$

0.03

$

0.01

33

%

General and administrative expense was $178.3 million for 2025 compared to $172.1 million for 2024. The increase in 2025, compared to 2024, is primarily due to higher salary and benefit related costs and higher stock-based compensation. As of December 31, 2025, the number of general and administrative employees remained similar compared to December 31, 2024. Stock-based compensation expense represents the amortization of stock-based compensation awards granted to our employees and our non-employee directors as part of their compensation. The following table summarizes general and administrative expenses per mcfe for the last two years:

Year Ended December 31,

2025

2024

Change

%

General and administrative

General and administrative

$

0.17

$

0.17

$

—

—

%

Stock-based compensation

0.05

0.05

—

—

%

Total general and administrative expense

$

0.22

$

0.22

$

—

—

%

Interest expense was $104.9 million for 2025 compared to $118.8 million for 2024. The following table summarizes interest expense per mcfe for the last two years:

Year Ended December 31,

2025

2024

Change

%

Bank credit facility (a)

$

0.02

$

0.01

$

0.01

100

%

Senior notes

0.10

0.13

(0.03

)

(23

)%

Amortization of debt issuance costs and other

0.01

0.01

—

—

%

Total interest expense

$

0.13

$

0.15

$

(0.02

)

(13

)%

Average debt outstanding ($000)

$

1,435,942

$

1,741,648

$

(305,706

)

(18

)%

Average interest rate (b)

7.0

%

6.5

%

0.5

%

8

%

(a)
Includes commitment fees.

(b)
Excludes debt issuance costs.

38

The decrease in interest expense from 2024 to 2025 was primarily due to lower overall outstanding average debt balances. In May 2025, we repaid 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 $118.0 million outstanding on the bank credit facility as of December 31, 2025 compared to no bank debt outstanding for the same period of 2024. See Note 6 to our consolidated financial statements for additional information.

Depletion, depreciation and amortization ("DD&A") was $370.5 million in 2025 compared to $358.4 million in 2024. The increase in 2025 compared to 2024 is due to higher production volumes. Depletion expense, the largest component of DD&A, was $0.44 per mcfe in 2025 compared to $0.44 per mcfe in 2024. We have historically adjusted our depletion rates in the fourth quarter of each year based on our 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 expenses per mcfe for the last two years:

Year Ended December 31,

2025

2024

Change

%

DD&A

Depletion and amortization

$

0.44

$

0.44

$

—

—

%

Depreciation

—

—

—

—

%

Accretion and other

0.01

0.01

—

—

%

Total DD&A expense

$

0.45

$

0.45

$

—

—

%

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation (including the amortization of time-based stock awards and performance-based stock awards), brokered natural gas and marketing, exploration expense, abandonment and impairment of unproved properties, exit costs, deferred compensation plan and gain or loss on early extinguishment of debt. See Note 10 to our consolidated financial statements for more information on allocation of stock-based compensation to functional expense categories.

Brokered natural gas and marketing expense was $185.6 million in 2025 compared to $140.5 million in 2024. We enter into purchase transactions with third parties and separate sale transactions with third parties at different times to utilize available pipeline capacity and fulfill sales commitments in the event of operational upsets. The increase in these costs reflects higher purchase prices partially offset by lower purchased volumes. The following table details our brokered natural gas and marketing net margin which includes the net effect of these third-party transactions for the last two years (in thousands):

Year Ended

December 31,

2025

2024

Brokered natural gas and marketing

Brokered natural gas sales

$

164,191

$

119,767

Brokered NGLs sales

2,443

5,370

Other marketing revenue

5,939

7,911

Brokered natural gas purchases and transportation

(171,010

)

(123,851

)

Brokered NGLs purchases

(2,267

)

(4,947

)

Other marketing expense

(12,277

)

(11,747

)

Net brokered natural gas and marketing net margin

$

(12,981

)

$

(7,497

)

Exploration expense was $30.2 million in 2025 compared to $26.8 million in 2024. Exploration expense in 2025 was higher compared to the prior year due to higher delay rentals, seismic costs and personnel expense. Stock-based compensation represents the amortization of equity stock grants as part of the compensation of our exploration staff. The following table details our exploration related expenses for the last two years (in thousands):

Year Ended December 31,

2025

2024

Change

%

Exploration

Delay rentals and other

$

21,550

$

19,256

$

2,294

12

%

Seismic

1,024

229

795

347

%

Personnel expense

6,250

6,004

246

4

%

Stock-based compensation expense

1,355

1,354

1

0

%

Total exploration expense

$

30,179

$

26,843

$

3,336

12

%

39

Abandonment and impairment of unproved properties was $28.9 million in 2025 compared to $8.4 million in 2024. These costs increased compared to 2024 due to higher estimated lease expirations in Pennsylvania. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property.

Exit costs were $25.7 million in 2025 compared to $37.2 million in 2024. In August 2020, we completed the sale of our North Louisiana operations in a transaction that included the retention of certain related gathering, transportation and processing obligations extending until 2030. In the year ended December 31, 2025, we recorded $33.1 million of accretion expense related to these retained liabilities, and during 2025, we recorded an adjustment of $7.4 million to decrease this obligation mainly due to a decrease in certain expected gathering and transportation costs. In the year ended December 31, 2024, we recorded $39.2 million of accretion expense related to these retained liabilities, and we recorded an adjustment of $2.1 million to decrease this obligation mainly due to a decrease in forecasted electricity costs. See Note 14 to our consolidated financial statements for further detail.

Deferred compensation plan expense was $1.4 million in 2025 compared to $9.6 million in 2024. Our stock price decreased to $35.26 at December 31, 2025 from $35.98 at December 31, 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. The deferred compensation plan held 258,000 vested shares at December 31, 2025 compared to 724,000 shares at December 31, 2024. See Note 10 to our consolidated financial statements for further detail.

Gain on early extinguishment of debt was a gain of $3,000 in 2025 compared to a gain of $257,000 in 2024. During 2025, we repurchased in the open market $2.2 million principal amount of our 4.875% senior notes due 2025 at a discount and recorded a gain of $3,000, net of transaction costs and the expensing of debt issuance costs on the repurchased debt. During 2024, we purchased on the open market $79.7 million principal amount of 4.875% senior notes due in May of 2025 at a discount and recognized a gain on early extinguishment of debt of $257,000 net of transaction costs and the expensing of debt issuance costs on the repurchased debt.

Income tax expense was $173.7 million in 2025 compared to a benefit of $15.7 million in 2024. Income tax expense was higher than prior year due to higher operating income in 2025 combined with the impact of prior year decreases in our valuation allowances and generation of tax credits in 2024. See Note 4 to our consolidated financial statements for further detail. The following is a summary of income tax expense (in thousands):

Year Ended December 31,

2025

2024

Income tax expense (benefit)

Current tax expense

$

9,394

$

8,165

Deferred income tax expense (benefit)

164,272

(23,900

)

Total income tax expense (benefit)

$

173,666

$

(15,735

)

Combined federal and state effective income tax rate

20.9

%

(6.3

)%

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

Commodity prices are the most significant factor impacting our revenues, net income, operating cash flows, 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 budget 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.

40

Cash Flows

The following table presents sources and uses of cash and cash equivalents for the last two years (in thousands):

Year Ended December 31,

2025

2024

Sources of cash and cash equivalents

Operating activities

$

1,171,324

$

944,514

Disposal of assets

187

313

Borrowing on credit facility

1,334,000

—

Other

35,226

66,363

Total sources of cash and cash equivalents

$

2,540,737

$

1,011,190

Uses of cash and cash equivalents

Additions to natural gas, NGLs and oil properties

$

(581,489

)

$

(570,426

)

Repayments on credit facility

(1,216,000

)

—

Acreage purchases

(56,814

)

(56,085

)

Additions to field service assets and other

(3,212

)

(2,069

)

Repayment of senior notes

(608,699

)

(79,272

)

Treasury stock purchases

(230,568

)

(65,260

)

Dividends paid

(85,680

)

(77,463

)

Other

(62,561

)

(68,099

)

Total uses of cash and cash equivalents

$

(2,845,023

)

$

(918,674

)

Sources of Cash and Cash Equivalents

Cash flow from operating activities in 2025 was $1.2 billion compared to $944.5 million in 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. The increase in cash provided from operating activities in 2025 from 2024 reflects higher realized prices and lower working capital outflow. Changes in working capital (as reflected in our consolidated statements of cash flows) for 2025 was an outflow of $129.2 million compared to an outflow of $135.3 million for 2024.

Borrowing on credit facility in 2025 was $1.3 billion of which approximately $447.0 million was utilized for the repayment of principal of our 4.875% senior notes due 2025 at their maturity date in May. Borrowings net of repayments for 2025 brought the credit facility balance to $118.0 million as of December 31, 2025.

Uses of Cash and Cash Equivalents

Additions to natural gas, NGLs and oil properties are our most significant use of cash and cash equivalents. These cash outlays are associated with our drilling and completion capital investment program. The following table shows capital investments and reconciles to additions to natural gas, NGLs and oil properties as presented on our consolidated statements of cash flows for the last two years (in thousands):

2025

2024

Additions due to natural gas, NGLs and oil properties

$

616,909

$

593,998

Change in capital expenditure accrual for proved properties

(34,533

)

(23,318

)

Change in other non-cash capital expenditures

(887

)

(254

)

Additions to natural gas, NGLs and oil properties

$

581,489

$

570,426

Repayment of senior notes for 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.

Purchases of treasury stock for 2025 include the repurchase of 6.4 million shares of common stock for a total of $230.6 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 December 31, 2025, we had approximately $1.7 billion of liquidity consisting of cash on hand and availability under our bank credit facility. On January 15, 2026 we fully redeemed the $600 million principal balance of our 8.25% senior notes due 2029 by utilizing borrowings on our credit facility, reducing liquidity to approximately $1.1 billion as of January 31, 2026. See Note 6 to our consolidated financial statements for more information.

41

Our liquidity requirements are supported by our cash on hand and our bank credit facility. We may draw on our bank credit facility to meet short-term cash requirements or issue debt or equity securities through the shelf registration discussed below as part of our longer-term liquidity and capital management. We believe our short-term and long-term liquidity is adequate to fund our current operations and our near-term and long-term funding requirements including our capital spending programs, repayment of debt maturities and dividends. Although we expect cash flows to be sufficient to fund our expected 2026 capital program and operations, we may elect to use the bank credit facility or raise funds through new debt or equity offerings or from other sources of financing.

Bank Credit Facility

Our bank credit facility is secured by substantially all of our assets. In October 2025, we entered into an amended and restated bank credit facility with a maturity date of October 2, 2030. As of December 31, 2025, we had a balance of $118.0 million on our bank credit facility, and we maintained a borrowing base of $3.0 billion and aggregate lender commitments of $2.0 billion. We also have undrawn letters of credit of $165.2 million as of December 31, 2025 which reduce the 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. The next scheduled borrowing base re-determination is during the spring of 2026. 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 agreement). We were in compliance with all such covenants at December 31, 2025. See Note 6 to our consolidated financial statements for more information.

Capital Requirements

Our material cash requirements include the following contractual and other potential or expected obligations:

Capital Budget

Our approved capital budget for 2026 is $650 million to $700 million. The amount of our future capital investment will depend upon a number of factors including our cash flows from operations, investing and financing activities, infrastructure availability, supply and demand fundamentals and our ability to execute our development program. We periodically review our budget to assess changes in these and other factors.

Cash Dividend Payments

On November 28, 2025, our board of directors announced the approval of a dividend of $0.09 per share payable on December 26, 2025, to stockholders of record at the close of business on December 12, 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 $785.5 million at December 31, 2025.

Interest Rates

As of December 31, 2025, we had $1.2 billion of total debt outstanding, of which $1.1 billion outstanding are senior notes which bore interest at fixed rates averaging 6.7%. Our expected annual incurred interest for the senior notes is $73.2 million assuming debt balances remain the same. Bank debt totaling $118.0 million bears interest at a floating rate which was 5.6% as of December 31, 2025. Annual expected interest for the bank credit facility is $9.3 million assuming there is no change to the debt balance and interest rate from December 31, 2025. These expectations do not include the impacts from the subsequent payoff in January 2026 of the 8.25% senior notes due 2029 as described in Note 6.

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 ability to sell an indeterminate amount of various types of debt and equity securities.

42

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations and transportation, gathering and processing commitments. As of December 31, 2025, we do not have any capital leases or any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2025. In addition to the contractual obligations listed in the table below, our consolidated balance sheet at December 31, 2025 reflects accrued interest payable associated with our bank credit facility and senior notes of $31.9 million, which is payable in 2026.

The following summarizes our contractual financial obligations at December 31, 2025 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities and, if necessary, borrowings under our bank credit facility or other sources (in thousands):

Payment due by period

2026

2027

2028

2029 and 2030

Thereafter

Total

Debt:

Bank debt due 2030 (a)

$

—

$

—

$

—

$

118,000

$

—

$

118,000

8.25% senior notes due 2029

—

—

—

600,000

—

600,000

4.75% senior notes due 2030

—

—

—

500,000

500,000

Other obligations:

Operating leases, net (b)

65,735

71,702

6,493

12,199

47,588

203,717

Software licenses and other

6,278

3,515

1,039

—

—

10,832

Derivative obligations (c)

1,196

(35

)

1,683

715

—

3,559

Transportation and gathering commitments (d)

833,967

823,437

805,735

1,233,456

2,161,282

5,857,877

Asset retirement obligation liability (e)

1,173

540

—

—

147,239

148,952

Total contractual obligations (f)

$

908,349

$

899,159

$

814,950

$

2,464,370

$

2,356,109

$

7,442,937

(a)
Due at termination date of our bank credit facility.

(b)
Includes amounts expected to be received as sublease income.

(c)
Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity derivatives that were valued as of December 31, 2025. Our derivatives are measured and recorded at fair value and are subject to market and credit risk. The ultimate liquidation value will be dependent upon actual future commodity prices which may differ materially from the inputs used to determine fair value as of December 31, 2025. See Note 8 to our consolidated financial statements.

(d)
The obligations above represent our minimum financial commitments pursuant to the terms of these contracts. Our actual expenditures may exceed these minimum commitments.

(e)
The amount above represents the discounted values. There are inherent uncertainties surrounding the obligations and the actual amount and timing may differ from our estimates. See Note 7 to our consolidated financial statements.

(f)
This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets and does not include obligations to taxing authorities.

Not included in the above table are agreements that are contingent on future construction. See Note 13 to our consolidated financial statements for more information regarding these contracts. Also not included in the table above is our estimate of accrued contractual obligations related to certain obligations retained by us after our divestiture of our North Louisiana assets. See additional information for these obligations in Note 14 to our consolidated financial statements.

Delivery Commitments

We have various volume delivery commitments that we expect to be able to fulfill from our own production; however, we may purchase third-party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2025, our delivery commitments through 2037 are included in Note 13 to our consolidated financial statements.

Income Taxes

We are subject to income-based and non-income-based taxes under federal, state and local jurisdictions in which we operate. Historically, we have generated and carried forward net operating losses ("NOL") in amounts sufficient to offset the majority of our taxable income at the federal level. To the extent we utilize all or substantially all of our federal NOL carryovers, we expect to make federal income tax payments. In addition, the Inflation Reduction Act of 2022 could trigger minimum income taxes if we become subject to the corporate alternative minimum tax where we may have to make estimated federal income tax payments. We currently pay federal income taxes and state income taxes in the Commonwealth of Pennsylvania. See Note 4 to our consolidated financial statements for more information.

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Proved Reserves

To maintain and grow production and cash flow, we must continue to develop existing proved reserves and locate or acquire new natural gas, NGLs and oil reserves. The following is a discussion of proved reserves, reserve additions and revisions and future net cash flows from proved reserves.

Year End December 31,

2025

2024

(Mmcfe)

Proved Reserves:

Beginning of year

18,131,475

18,113,125

Reserve revisions

264,073

75,765

Reserve extensions, discoveries and additions

562,372

749,362

Sales

—

(10,542

)

Production

(816,058

)

(796,235

)

End of year

18,141,862

18,131,475

Proved Developed Reserves:

Beginning of year

11,930,793

11,535,852

End of year

12,801,132

11,930,793

Reserve Revisions and Additions. See additional information and a summary of these revisions and additions in Note 16 to our consolidated financial statements.

Future Net Cash Flows. At December 31, 2025, the present value (discounted at 10%) of estimated future net cash flows from our proved reserves was $11.6 billion. The present value of our estimated future net cash flows at December 31, 2024 was $5.5 billion. This present value was calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves, in accordance with SEC rules. At December 31, 2025, the after-tax present value of estimated future net cash flows from our proved reserves was $9.6 billion compared to $4.7 billion at December 31, 2024.

The present value of future net cash flows does not purport to be an estimate of the fair market value of our proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money to the evaluating party and the perceived risks inherent in producing natural gas, NGLs and oil.

Other

We lease acreage that is generally subject to expiration if initial wells are not drilled within a specified period, generally between three and five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. We also regularly provide letters of credit in the normal course of business under certain contracts that may be drawn if we fail to perform under those contracts.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resources position. However, as is customary in the natural gas, NGLs and oil industry, we have various contractual work commitments which are described above under cash contractual obligations.

Management’s Discussion of Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

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Estimated Quantities of Net Reserves

We use the successful efforts method of accounting for natural gas, NGLs and oil producing activities as opposed to the alternate acceptable full cost method. We believe that net assets and net income are more conservatively measured under the successful efforts method of accounting than under the full cost method, particularly during periods of active exploration. One difference between the successful efforts method of accounting and the full cost method is that under the successful efforts method, all exploratory dry holes and geological and geophysical costs are charged against earnings during the periods they occur; whereas, under the full cost method of accounting, such costs are capitalized as assets, pooled with the costs of successful wells and charged against earnings of future periods as a component of depletion expense. Under the successful efforts method of accounting, successful exploration drilling costs and all development costs are capitalized and these costs are systematically charged to expense using the units of production method based on proved developed natural gas, NGLs and oil reserves as estimated by our engineers and audited by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our balance sheet if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.

Proved reserves are defined by the SEC as those volumes of natural gas, NGLs and oil that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves for which a development plan has been adopted indicating each location is scheduled to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer time. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas, NGLs and oil prices can lead to a decision to start up or shut in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to audit our estimates of proved reserves. Estimates prepared by third parties may be higher or lower than those included herein. Independent petroleum consultants audited approximately 96% of our reserves in 2025 and 2024. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been approximately 6% or less. The reserves included in this report are those reserves estimated by our petroleum engineering staff. For additional discussion, see Items 1 & 2. Business and Properties – Proved Reserves and Note 16 to our consolidated financial statements.

Reserves are based on the weighted average of commodity prices during the 12-month period, using the closing prices on the first day of each month, as defined by the SEC. When determining the December 31, 2025 proved reserves for each property, benchmark prices are adjusted using price differentials that account for property-specific quality and location differences. If prices in the future average below prices used to determine reserves at December 31, 2025, it could have an adverse effect on our estimates of proved reserves. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves due to numerous factors (including commodity prices and performance revisions).

Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Based on proved reserves at December 31, 2025, we estimate that a 1% change in proved reserves would increase or decrease 2026 depletion expense by approximately $3.5 million (based on current production estimates). We currently expect our DD&A rate to be approximately $0.43 per mcfe in 2026. Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities in Note 16 to our consolidated financial statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis. It should not be assumed that the standardized measure is the current market value of our estimated proved reserves.

45

Accounting Standards Not Yet Adopted

Refer to Note 2 to our consolidated financial statements for a discussion of new accounting pronouncements that may affect us in the future.