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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K


☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)


Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)

100 Throckmorton Street, Suite 1200, Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code (817) 870-2601

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class	Trading Symbol	Name of each exchange on which registered
Common Stock, $.01 par value	RRC	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer	☒	Smaller reporting company	☐
Accelerated filer	☐	Emerging growth company	☐
Non-accelerated filer	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act: ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2025 was $9,592,497,000. This amount is based on the closing price of the registrant's common stock on the New York Stock Exchange on the last trading day of the month. Shares of common stock held by executive officers and directors of the registrant and treasury shares held by the registrant are not included in the computation.

As of February 20, 2026, there were 235,381,000 shares of Range Resources Corporation common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be furnished to stockholders in connection with its 2026 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates, are incorporated by reference in Part II, Item 5 and Part III, Items 10-14 of this report.

RANGE RESOURCES CORPORATION

Unless the context otherwise indicates, all references in this report to "Range," "we," "us" or "our" are to Range Resources Corporation and its directly and indirectly owned subsidiaries. Unless otherwise noted, all information in the report relating to natural gas, natural gas liquids and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates and are net to our interest. If you are not familiar with the oil and gas terms used in this report, please refer to the explanation of such terms under the caption "Glossary of Certain Defined Terms."

TABLE OF CONTENTS


		Page
	Glossary of Certain Defined Terms	iii
PART I
ITEMS 1. & 2.	Business and Properties	1
	General	1
	Available Information	1
	Our Business Strategy	1
	Outlook for 2026	2
	Property Overview and Geographical Information	3
	Proved Reserves	3
	Production, Sales Price and Production Costs	4
	Drilling Activity	5
	Gross and Net Acreage	5
	Undeveloped Acreage Expirations	5
	Title to Properties	6
	Competition	6
	Marketing and Customers	6
	Seasonal Nature of Business	7
	Markets	7
	Human Capital Management	7
	Executive Officers of the Registrant	8
	Governmental Regulation	9
	Environmental and Occupational Health and Safety Matters	11

ITEM 1A.	Risk Factors	16

ITEM 1B.	Unresolved Staff Comments	28

ITEM 1C.	Cybersecurity	28

ITEM 3.	Legal Proceedings	29

ITEM 4.	Mine Safety Disclosures	29

PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
	Market for Common Stock	30
	Holders of Record	30
	Dividends	30
	Equity Compensation Plan Information	30
	Purchases of Equity Securities by Issuer and Affiliated Purchasers	30
	Stockholder Return Performance Presentation	31

TABLE OF CONTENTS (continued)


		Page
ITEM 6.	[Reserved]	31

ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
	Management's Discussion and Analysis of Results of Operations	33
	Management's Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity	40
	Management's Discussion of Critical Accounting Estimates	44

ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	46
	Commodity Price Risk	46
	Derivative Instruments	46
	Other Commodity Risk	47
	Commodity Sensitivity Analysis	47
	Counterparty Risk	47
	Interest Rate Risk	47

ITEM 8.	Financial Statements and Supplementary Data	F-1

ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	49

ITEM 9A.	Controls and Procedures	49

ITEM 9B.	Other Information	49

ITEM 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	49

PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance	50

ITEM 11.	Executive Compensation	50

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50

ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	50

ITEM 14.	Principal Accountant Fees and Services	50

PART IV

ITEM 15.	Exhibits and Financial Statement Schedules	51

SIGNATURES		53

GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this glossary are used in this report.

bbl. One stock tank barrel, or 42 U.S. gallons liquid volumes, used herein in reference to crude oil or other liquid hydrocarbons.

bcf. One billion cubic feet of gas.

bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel of oil or NGLs, which reflects relative energy content.

btu. One British thermal unit, an energy equivalence measure. A British thermal unit is the heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Developed Oil and Gas Reserves. Oil and natural gas reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Dry hole. A well found to be incapable of producing oil or natural gas in sufficient economic quantities.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Henry Hub price. A natural gas benchmark price quoted at settlement date average.

mbbl. One thousand barrels of oil or other liquid hydrocarbons.

mcf. One thousand cubic feet of gas.

mcf per day. One thousand cubic feet of gas per day.

mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel of oil or NGLs, which reflects relative energy content.

mmbbl. One million barrels of oil or other liquid hydrocarbons.

mmbtu. One million British thermal units.

mmcf. One million cubic feet of gas.

mmcfe. One million cubic feet of gas equivalents.

NGLs. Natural gas liquids, which are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline that can be collectively removed from produced natural gas, separated into these substances and sold.

Net acres or Net wells. The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Performance Share Unit (PSU). An equity-based compensation award that vests based upon the achievement of performance conditions.

Present Value (PV). The present value of future net cash flows, using a 10% discount rate, from estimated proved reserves, using constant prices and costs in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions). The after-tax present value is the Standardized Measure.

iii

Productive well. A well that is producing oil or gas or that is capable of production.

Proved developed non-producing reserves. Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed reserves. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extracting equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.

Proved reserves. The quantities of crude oil, natural gas and NGLs, which by analysis of geological and engineering data, can estimate with reasonable certainty to be economically producible from a given date forward, from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

Reserve life index. Proved reserves at a point in time divided by the then production rate (annually or quarterly).

Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Royalty acreage. Acreage represented by a fee mineral or royalty interest which entitles the owner to receive free and clear of all production costs a specified portion of the oil and gas produced or a specified portion of the value of such production.

Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of costs of production.

Standardized Measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves after income taxes, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the SEC's rules for inclusion of oil and gas reserve information in financial statements filed with the SEC.

Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

tcfe. One trillion cubic feet of natural gas equivalents, with one barrel of NGLs or oil being equivalent to 6,000 cubic feet of natural gas.

Unconventional play. A term used in the oil and gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds or (3) shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation or other special recovery processes in order to achieve economic flow rates.

Undeveloped Oil and Gas Reserves. Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Unproved properties. Properties with no proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens, and to all costs of exploration, development and operations, and all risks in connection therewith.

Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended ("Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended ("Exchange Act"). These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including without limitation, operational and financial strategies: drilling plans; planned wells; rig count; our 2026 capital budget; reserve estimates; financial flexibility; expectations regarding future economic and market conditions and their effects on us; our financial and operational outlook and ability to fulfill that outlook; our financial position, balance sheet, liquidity and capital resources and the benefits thereof. These statements typically contain words such as "anticipates," "believes," "estimates," "expects," "intend," "may," "outlook," "plans," "projects," "targets," "should," "would" or similar words, indicating that future outcomes are uncertain. Such forward-looking statements are intended to be subject to the safe harbor protections provided by the federal securities law. While we believe our assumptions concerning future events are reasonable, these expectations may not prove to be correct. A number of factors could cause results to differ materially from those indicated by such forward looking statements including, but not limited to:

•

conditions in the oil and gas industry, including supply and demand levels for natural gas, natural gas liquids ("NGLs") and oil and the resulting impact on price;

•

the availability and volatility of securities, capital or credit markets and the cost of capital to fund our operation and business strategy;

•

accuracy and fluctuations in our reserves estimates due to regulations, reservoir performance or sustained low commodity prices;

•

lack of, or disruption in, processing facilities and access to pipelines or other transportation methods;

•

ability to develop existing reserves or add new reserves;

•

drilling and operating risks;

•

well production timing;

•

changes in the regulatory climate, either nationally or in our key operating market, that result in difficulty obtaining necessary approvals and permits;

•

changes in geopolitical or economic conditions, including changes in interest rates and inflation rates, both domestically and internationally and more specifically in our key operating market;

•

prices and availability of goods and services, including drilling rigs, completions equipment, materials, labor and third-party infrastructure;

•

unforeseen hazards such as weather conditions, health pandemics, acts of war or terrorist acts;

•

security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;

•

changes in safety, health, environmental, tax and other regulations or requirements or initiatives including those addressing the impact of global climate change, air emissions, waste or water management;

•

the availability, cost, terms and competition for mineral leases and surface use agreements;

•

other geological, operating and economic considerations;

•

risks related to our derivative activities;

•

non-performance by third parties of their contractual obligations; or

•

other factors discussed in Items 1 and 2. Business and Properties, Item 1A. Risk Factors, Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures about Market Risk and elsewhere in this report.

All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, 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. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

General

Range Resources Corporation ("Range"), a Delaware corporation, is a Fort Worth, Texas-based independent producer of natural gas, NGLs and oil (predominately condensate but referred to herein as "oil"), engaged in the exploration, development and acquisition of natural gas, NGLs and oil properties in the Appalachian region of the United States. Our principal area of operations is the Marcellus Shale in Pennsylvania. Our corporate offices are located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102 (telephone (817) 870-2601). We also maintain field offices in our area of operations. Our common stock is listed and traded on the New York Stock Exchange (the "NYSE") under the ticker symbol "RRC." Range Resources Corporation was incorporated in 1980.

As of December 31, 2025, we had 1,579 gross (1,499 net) operating producing wells that produced average daily production of 2.24 Bcfe per day for the year. As of December 31, 2025 we had estimated net proved reserves of 18.1 Tcfe of which 71% was proved developed and consisted of 65% gas, 34% NGLs and 1% oil.

Available Information

Our corporate website is available at http://www.rangeresources.com. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing we make with the U.S. Securities and Exchange Commission (the "SEC"). We make available, free of charge on our website, the annual report on Form 10-K, our proxy statement, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after filing such reports with the SEC. Other information such as presentations, our corporate sustainability report, our Corporate Governance Guidelines, the charters of each board committee and the Code of Business Conduct and Ethics are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including our President and Chief Executive Officer and Chief Financial Officer.

The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers, including Range, that file electronically with the SEC. The public can obtain any document we file with the SEC at http://www.sec.gov.

Our Business Strategy

Our overarching business objective is to build stockholder value through returns-focused development of our natural gas, NGLs and oil properties. The strategy to achieve our business objectives is to generate consistent cash flows from reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and dispositions. Our strategy requires us to make significant investments and financial commitments in technical staff, acreage, seismic data, drilling and completion technology and gathering and transportation arrangements to build drilling inventory and market our products. Our strategy has the following key elements that are anchored by our assets located in the Commonwealth of Pennsylvania which is anticipated to have remaining productive life in excess of 50 years:

Commit to Environmental Protection, Worker and Community Safety. We strive to implement technologies and commercial practices to minimize potential adverse impacts from the development of our properties on the environment, worker health and safety and the safety of the communities where we operate. We analyze and review performance while striving for continual improvement by working with peer companies, regulators, non-governmental organizations, industries not related to the oil and natural gas industry and other engaged stakeholders. We expect every employee to maintain safe operations, minimize environmental impact and conduct their daily business with the highest ethical standards. Safety is at the foundation of everything we do at Range and it is essential to our success. We have published on our website our 2024 - 2025 Corporate Sustainability Report which includes more information related to our sustainability practices.

Concentrate in Our Core Operating Area. We currently operate in the Commonwealth of Pennsylvania. Concentrating our drilling and producing activities allows us to develop the regional expertise needed to interpret specific geological and operating conditions and develop economies of scale. Our management team has extensive experience in executing a multi-rig development drilling program, planning long-term logistics, marketing production and prudently allocating capital. Operating in our core area also allows us to pursue our goal of consistent production at attractive returns. We intend to further develop our acreage and improve our operating and financial results through the use of technology and detailed analysis of our properties. We periodically evaluate and pursue acquisition opportunities (including opportunities to acquire particular natural gas, NGLs and oil properties or entities owning natural gas and oil assets) and at any given time we may be in various stages of evaluating such opportunities.

Focus on Cost Efficiency. We concentrate in areas which we believe to have sizable hydrocarbon deposits in place that will allow economic production while controlling costs. Because there is little long-term competitive sales price advantage available to a commodity producer, the costs to find, develop, and produce a commodity are important to organizational sustainability and long-term stockholder value creation. We endeavor to control costs such that our cost to find, develop and produce natural gas, NGLs and oil is one of the lowest in the industry. We operate almost all of our total net production and believe that our extensive knowledge of the geologic and operating conditions in the areas where we operate provides us with the ability to achieve operational efficiencies.

Maintain a High-Quality Multi-Year Drilling Inventory. We focus on areas with multiple prospective and productive horizons and development opportunities. We use our technical expertise to build and maintain a multi-year drilling inventory. We believe that a large, high-quality multi-year inventory of drilling projects increases our ability to efficiently plan for economic production. Currently, we have an estimated 27 million lateral feet of drilling inventory remaining in the Marcellus Shale, both proved and unproved.

Maintain a Long-Life Reserve Base with a Low Base Decline Rate. Long-life natural gas, NGLs and oil reserves provide a more stable platform than short-life reserves. Long-life reserves with relatively low decline rates reduce reinvestment risk as they lessen the amount of reinvestment capital deployed each year to replace production. Long-life natural gas, NGLs and oil reserves also assist us in minimizing costs as stable production makes it easier to build and maintain operating economies of scale and also offer upside from technology enhancements.

Market Our Products to a Large Number of Customers in Diverse Markets Under a Variety of Commercial Terms. We market our natural gas, NGLs and oil to a large number of customers in both domestic and international markets to maximize cash flow and diversify risk. We hold numerous firm transportation contracts on multiple pipelines to enable us to transport and sell natural gas and NGLs in the Midwest, Gulf Coast, Southeast, Northeast and international markets. We sell our products under a variety of price indices and price formulas that assist us in optimizing regional price differentials and reducing commodity price volatility.

Maintain Operational and Financial Flexibility. Because of the risks involved in drilling, coupled with changing commodity prices, we are flexible and may adjust our capital budget or other projections throughout the year. We are the operator of almost all of our total net production. This operating control allows us to better execute our strategies of enhancing returns through operational and cost efficiencies and increasing recovery of hydrocarbons by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation process. We believe our asset base, revenue diversity, low-cost structure and strong balance sheet provide us the flexibility we need to thrive across various commodity price environments. We also believe in maintaining ample liquidity, using commodity derivatives to help stabilize our realized prices, and focusing on financial discipline. We believe this provides more predictable cash flows and financial results.

Provide Employee Equity Ownership and Incentive Compensation Aligned with Our Stakeholders’ Interests. We want our employees to think and act like business owners. To achieve this, we reward and encourage them through equity ownership in Range. All full-time employees are eligible to receive equity grants. As of December 31, 2025, our employees and directors owned equity securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $140.6 million. However, many employees and directors have Range stock ownership outside of our benefit plans, which would only further increase the total market value owned. We seek to align our incentive compensation with stakeholders’ interests and key business objectives. Members of our board of directors annually engage with stockholders to discuss our incentive compensation framework.

Outlook for 2026

For 2026, in line with what we previously announced, 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. This budget includes $620 million to $640 million for drilling costs, $15 million to $35 million for acreage and $15 million to $25 million of investment in software, office facilities and other. This plan is expected to achieve modest growth of 2026 production relative to 2025 production volumes, while also supporting our longer-term operational plans. 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. Throughout the year, we allocate capital on a project-by-project basis. Our expectation for 2026 is for our capital expenditure program to be funded with operating cash flows. However, in the event our 2026 capital investments exceed our internally generated cash flow, we may reduce the capital budget, draw on our bank credit facility and/or debt or equity financing may be used to fund these investments. 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 using commodity derivative contracts and we intend to continue to enter into these transactions.

Our primary near-term focus includes the following:

•

operate safely;

•

be good stewards of the environment;

•

achieve competitive returns on investments;

•

develop our world-class assets through disciplined capital investments;

•

improve operational efficiencies and economic returns;

•

return capital to stockholders while maintaining a strong balance sheet;

•

continue to reduce absolute emissions and maintain net-zero Scope 1 and Scope 2 GHG emissions;

•

attract and retain quality employees; and

•

align employee incentives with our stockholders’ interests and key business objectives.

Property Overview and Geographical Information

Our natural gas, NGLs and oil operations are concentrated in the Appalachian region of the United States, and more specifically, in the Marcellus Shale in Pennsylvania. Our properties consist of interests in developed and undeveloped natural gas, NGLs and oil leases. These interests entitle us to drill for and produce natural gas, NGLs and oil from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, royalty and overriding royalty interests.

We hold a large portfolio of drilling opportunities beyond the five-year horizon of proved reserves and therefore a significant unbooked resource potential within the Marcellus, Utica/Point Pleasant and Upper Devonian formations. We own 1,577 gross (1,499 net) producing gas wells in Pennsylvania, almost all of which we operate. Our average working interest in this region is 95%. We do not have any dual completions. As of December 31, 2025, we have approximately 879,000 gross (769,000 net) acres under lease in the Marcellus. During 2025, we averaged approximately two horizontal drilling rigs in the field and expect to have less drilling activity throughout 2026, while completions activity is expected to increase. Substantially all of our reserves and production are located in the Marcellus Shale.

Proved Reserves

The following table sets forth our estimated proved reserves for year ended 2025 based on the average of prices on the first day of each month of the given calendar year, in accordance with SEC rules. We have no natural gas, NGLs or oil reserves from non-traditional sources. During the year ended December 31, 2025, we did not file any reports with any federal authority or agency with respect to our estimate of natural gas, NGLs and oil reserves. Additionally, we do not provide optional disclosures of probable or possible reserves.


	Summary of Oil and Gas Reserves as of Year-End Based on Average Prices
Reserve Category	Natural Gas (Mmcf)		NGLs (Mbbls)		Oil (Mbbls)		Total (Mmcfe) (a)		%
As of December 31, 2025:
Proved
Developed		8,381,647		715,291		21,290		12,801,132		71	%
Undeveloped		3,334,265		322,872		11,538		5,340,730		29	%
Total Proved		11,715,912		1,038,163		32,828		18,141,862		100	%


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

For additional information regarding estimates of our proved reserves, the qualifications of the preparers of our reserve estimates, the evaluation of such estimates by our independent petroleum engineering consultants, our processes and controls with respect to our reserves estimates and other information about our reserves, including the risks inherent in our estimates of proved reserves, refer to the Supplemental Information on Natural Gas, NGLs and Oil Exploration, Development and Production Activities included in Note 16 of our consolidated financial statements for more information.

Proved Reserves (PV-10)

The following table sets forth the estimated future net cash flows, excluding open derivative contracts, from proved reserves, the present value of those net cash flows discounted at a rate of 10% PV-10(a), and the expected benchmark prices and average field prices used in projecting net cash flows over the past three years. The benchmark prices used are based on the average of prices on the first day of each month of the given calendar year, in accordance with SEC rules. Our reserve estimates do not include any probable or possible reserves (in millions, except prices):


	2025		2024		2023
Future net cash flows	$	29,295	$	15,261	$	21,748
Present value:
Before income tax		11,566		5,454		7,926
After income tax (Standardized Measure)		9,636		4,691		6,838
Benchmark prices (NYMEX):
Gas price (per mcf)		3.39		2.13		2.62
Oil price (per bbl)		65.68		74.88		78.10
Wellhead prices:
Gas price (per mcf)		3.03		1.74		2.20
Oil price (per bbl)		55.00		63.39		68.32
NGLs price (per bbl)		25.03		24.40		24.91

     (a)

     PV-10 is considered a non-GAAP financial measure as defined by the U.S. Securities and Exchange Commission (the "SEC"). We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on prices and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and security analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV-10 amount is the discounted estimated future income tax of $1.9 billion at December 31, 2025. Oil and NGLs volumes are converted at the rate of one barrel equals six mcf based on approximate relative energy content.

Future net cash flows represent projected revenues from the sale of proved reserves, net of production and development costs (including transportation and gathering expenses, operating expenses and production taxes). Revenues are based on a twelve-month unweighted average of the first day of the month pricing, without escalation. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic conditions at each year-end. There can be no assurance that the proved reserves will be produced in the future or that prices, production or development costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.

Production, Sales Price and Production Costs

The following presents historical information about our total production volumes for natural gas, NGLs and oil; average sales prices and average production costs:


	Year Ended December 31,
	2025		2024		2023
Production Volumes:
Natural gas (mcf)		560,891,967		545,415,974		538,084,671
NGLs (bbls)		40,551,764		39,622,576		37,939,700
Oil (bbls)		1,975,937		2,180,528		2,475,306
Total mcfe (a)		816,058,173		796,234,598		780,574,707
Sales Prices: (b)
Natural gas (per mcf)	$	3.08	$	1.93	$	2.29
NGLs (per bbl)		24.15		25.77		24.61
Oil (per bbl)		53.68		64.44		67.29
Total (per mcfe) (a)		3.45		2.78		2.99
Production Costs:
Lease operating (per mcfe)	$	0.13	$	0.12	$	0.12
Taxes other than income (per mcfe) (c)		0.04		0.03		0.03


(a)	Oil and NGLs volumes are converted at the rate of one barrel equals six mcf based on approximate relative energy content.
(b)	Does not include derivative settlements or deductions for third-party transportation, gathering or processing costs.
(c)	Includes Pennsylvania impact fee.

Drilling Activity

The following table summarizes drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. This information should not be indicative of future performance nor should it be assumed that there was any correlation between the number of productive wells and the natural gas, NGLs and oil reserves generated thereby. As of December 31, 2025, we had 29 gross (28 net) wells in the process of drilling or active completions stage. In addition, there were 53 gross (52 net) wells waiting on completion or waiting on pipelines at year-end 2025.


	2025						2024						2023
	Gross			Net			Gross			Net			Gross			Net
Development wells
Productive		54.0			52.6			52.0			51.7			50.0			47.4
Dry		—			—			—			—			—			—
Exploratory wells
Productive		—			—			—			—			—			—
Dry		—			—			—			—			—			—
Total wells
Productive		54.0			52.6			52.0			51.7			50.0			47.4
Dry		—			—			—			—			—			—
Total		54.0			52.6			52.0			51.7			50.0			47.4
Success ratio		100	%		100	%		100	%		100	%		100	%		100	%

Gross and Net Acreage

We own interests in developed and undeveloped acreage. These ownership interests generally take the form of working interests in natural gas, NGLs and oil leases that have varying terms. Developed acreage generally includes leased acreage that is allocated or assignable to producing wells or wells capable of production even though shallower or deeper horizons may not have been fully explored. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas, NGLs or oil, regardless of whether or not the acreage contains proved reserves. The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2025. Acreage related to option acreage, royalty, overriding royalty and other similar interests is excluded from this summary:


	Developed Acres					Undeveloped Acres					Total Acres
	Gross		Net			Gross		Net			Gross		Net
New York		—		—			2,265		567			2,265		567
Oklahoma		12,176		5,694			9,490		3,634			21,666		9,328
Pennsylvania		775,315		673,274			95,520		90,088			870,835		763,362
Texas		3,234		1,974			3,009		2,348			6,243		4,322
West Virginia		5,876		5,197			—		—			5,876		5,197
		796,601		686,139			110,284		96,637			906,885		782,776
Average working interest				86	%				88	%				86	%

Undeveloped Acreage Expirations

The table below summarizes by year our undeveloped acreage scheduled to expire in the next five years.


	Acres				% of Total
As of December 31,	Gross		Net		Undeveloped
2026		16,855		16,325		17	%
2027		9,970		9,623		10	%
2028		12,922		11,338		12	%
2029		16,465		15,678		16	%
2030		14,028		13,615		14	%

In all cases, the drilling of a commercial well will hold acreage beyond the lease expiration date. We have leased acreage that is subject to lease expiration if initial wells are not drilled within a specified period, generally between three and five years. We do have certain acreage that expires after five years. However, we have in the past been able, and expect in the future to be able, to extend the lease terms of some of these leases and sell or exchange some of these leases with other companies. The expirations included in the table above do not take into account the fact that we may be able to extend the lease terms. 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 or when we do not intend to drill a property prior to lease expiration, we have allowed acreage to expire and we expect to allow additional acreage to expire in the future. We also believe acres needed in the future for our development plans can be leased again. We currently have no proved undeveloped reserve locations scheduled to be drilled after lease expiration.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often minimal investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use, or affect the value, of the properties. Burdens on properties may include:

•

customary royalty or overriding royalty interests;

•

liens incident to operating agreements and for current taxes;

•

obligations or duties under applicable laws;

•

development obligations under oil and gas leases; or

•

net profit interests.

Competition

Competition exists in all sectors of the oil and gas industry, and we encounter substantial competition in developing and acquiring natural gas, NGLs and oil properties, securing and retaining personnel, conducting drilling and field operations and marketing production. Competitors in exploration, development, acquisitions and production include the major oil and gas companies as well as numerous independent oil and gas companies, individual proprietors and others. Although our sizable acreage position and core area concentration provide some competitive advantages, many competitors have financial and other resources substantially exceeding ours. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources allow. We face competition for pipeline and other services to transport our product to markets, particularly in the Northeastern portion of the United States. We also face competition from companies that supply alternative sources of energy, such as wind, solar power, nuclear and other sources. Competition may increase as alternative energy technologies become more reliable and if governments throughout the world support or mandate the use of such alternative energy.

Competitive advantage is gained in the oil and gas exploration and development industry by having high-quality inventory and by employing well-trained and experienced personnel who make prudent capital investment decisions based on management direction, embrace technological innovation, focus on price and cost management, and safely develop and operate our properties. We have a team of dedicated employees who represent the professional disciplines and sciences that we believe are necessary to allow us to maximize the long-term profitability and net asset value inherent in our physical assets. For more information, see Item 1A. Risk Factors.

Marketing and Customers

We market the majority of our natural gas, NGLs, and oil production from the properties we operate for our working interest, and that of the other working interest owners. We pay our royalty owners from the sales attributable to our working interest. Natural gas, NGLs and oil purchasers are selected on the basis of price, credit quality and service reliability. For information on purchasers of our natural gas, NGLs and oil production that accounted for 10% or more of consolidated revenue, see Note 2 to our consolidated financial statements. Because alternative purchasers of natural gas, NGLs and oil are usually readily available, we believe that the loss of any of these purchasers would not have a material adverse effect on our operations. Production from our properties is marketed using methods that are consistent with industry practice. Natural gas is a commodity for which we typically receive market-based pricing for our produced natural gas. Sales prices for natural gas, NGLs and oil production are negotiated based on factors normally considered in the industry, such as index or spot price, distance from the well to the pipeline, processing and other costs, commodity quality and prevailing supply and demand conditions.

We contract with a third-party to process our natural gas and extract from the produced natural gas heavier hydrocarbon streams (consisting predominately of ethane, propane, isobutane, normal butane and natural gasoline). Our natural gas production is sold to utilities, marketing and midstream companies and industrial users. Our NGLs production is typically sold to petrochemical end users, refiners, marketers/traders (both domestically and internationally) and natural gas processors. Our oil production is sold to crude oil processors, transporters and refining and marketing companies.

We enter into derivative transactions with unaffiliated third parties for a varying portion of our production to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas, NGLs and oil prices. For a more detailed discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

We incur gathering and transportation expense to move our production from the wellhead, tanks and processing plants to purchaser-specified delivery points. These expenses vary and are primarily based on volume, distance shipped and the fee charged by the third-party gatherers and transporters. We also have processing contracts based on percent of proceeds. Transportation capacity on these gathering and transportation systems and pipelines is occasionally constrained. Our Appalachian production is transported on third-party pipelines on which we hold a certain amount of long-term contractual capacity. We have entered into several ethane agreements to sell or transport ethane from our Marcellus Shale area. We attempt to balance sales, storage and transportation positions, which can include purchases of commodities from third parties for resale, to utilize contracted transportation capacity.

We have not experienced significant difficulty to date in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to transport and market all of our production or obtain favorable prices. For more information, see Item 1A. Risk Factors – Our business depends on natural gas and oil transportation and on NGLs processing facilities, which are owned by others and depends on our ability to contract with those parties.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas and propane decreases during the spring and fall months and increases during the winter months and, in some areas, also increases during the summer months. Seasonal anomalies such as mild winters or summers also may impact this demand. In addition, pipelines, utilities, local distribution companies and industrial end-users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also impact the seasonality of demand. Exports can also impact demand based on the seasonality of global markets.

Markets

Our ability to produce and market natural gas, NGLs and oil profitably depends on numerous factors beyond our control. The effect of these factors cannot be accurately predicted or anticipated. Although we cannot predict the occurrence of events that may affect commodity prices or the degree to which commodity prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region where we deliver our production.

Human Capital Management

We believe our employees provide the foundation of our success. Successful execution of our strategy is dependent on attracting, developing and retaining our skilled employees and members of our management team. The abilities, experience and industry knowledge of our employees significantly benefit our operations and performance. To maximize the contributions of our employees, we regularly evaluate, modify and enhance our policies and practices, including compensation, to increase employee engagement, productivity and efficiency. As of January 1, 2026, we had 564 full-time employees, none of whom are currently covered by a labor union or other collective bargaining arrangement.

Compensation and Benefits. We review compensation for all employees at least annually to adjust for market conditions and to attract and retain a highly skilled workforce. We encourage our employees to take full advantage of our benefits and programs we offer. In addition to competitive base wages, other benefits include an annual bonus plan, long-term incentive plan, company-matching contributions to the 401(k) plan, healthcare and insurance benefits, flexible spending accounts, flexible work schedules, employee assistance programs and mental health.

Our compensation program includes eligibility for full-time employees to receive equity awards, encouraging every employee to think like an owner of the business and be vested in its success. We believe these practices, and those further described below, are the key drivers in our very low voluntary turnover rates, which averaged less than 2% over the five-year period ended December 31, 2025. We believe our high retention rate is in part a result of our corporate culture focused on collaboration and a commitment to employee development and career advancement.

Health and Safety. We believe health and safety is a core value ingrained in all aspects of our business. This value is reflected in our strong safety culture that emphasizes personal responsibility and safety leadership both for our employees and contractors on our worksites. Our comprehensive environmental, health and safety (EHS) management system establishes a corporate governance framework for EHS compliance and performance and covers all elements of our operating lifecycle.

Recruiting, Hiring and Advancement. Due to the cyclical nature of our business and the fluctuations in activity that can occur, we take a conservative approach to our headcount, carefully evaluating whether a new hire is necessary for an open position or whether we can fill the position by expanding the role of a current employee or several employees. In this way, we provide employees with opportunities to learn new roles and develop their skills horizontally and vertically and limit or minimize layoffs and fluctuations when downturns occur. We support employees in pursuing training opportunities to expand their professional skills. We have also implemented development programs that are designed to build leadership capabilities at all levels.

We identify qualified candidates by promoting positions internally, engaging in recruiting through our website platforms, campus outreach, internships and attending job fairs. In our recruiting and hiring efforts, we seek to foster a culture of mutual respect and strictly comply with all applicable federal, state and local laws governing non-discrimination in employment. We treat all applicants with the same high level of respect regardless of their gender, ethnicity, religion, national origin, age, marital status, political affiliation, sexual orientation, gender identity, disability or protected veteran status. This philosophy extends to all employees throughout the lifecycle of employment.

Additional information about our commitment to human capital management is available on our website. The information on our website is not incorporated by reference into this annual report.

Executive Officers of the Registrant

Our executive officers and their ages as of February 1, 2026, are as follows:


	Age	Position
Dennis L. Degner	53	Chief Executive Officer and President
Mark S. Scucchi	48	Executive Vice President – Chief Financial Officer
Erin W. McDowell	47	Senior Vice President – General Counsel and Corporate Secretary
Ashley S. Kavanaugh	44	Vice President – Controller and Principal Accounting Officer

Dennis L. Degner, chief executive officer and president, joined Range in 2010. Mr. Degner was named chief executive officer effective May 21, 2023. Mr. Degner previously served as chief operating officer and has more than 25 years of oil and gas experience, having worked in a variety of technical and managerial positions across the United States including Texas, Louisiana, Wyoming, Colorado and Pennsylvania. Prior to joining Range, Mr. Degner held positions with Encana, Sierra Engineering and Halliburton. Mr. Degner is a member of the Society of Petroleum Engineers and has been published for his work on active roles played in the deployment of new technologies. Mr. Degner holds a Bachelor of Science Degree in Agricultural Engineering from Texas A&M University.

Mark S. Scucchi, executive vice president – chief financial officer, joined Range in 2008. Mr. Scucchi was named senior vice president – chief financial officer in 2018 and executive vice president in 2024. Previously, Mr. Scucchi served as vice president – finance & treasurer. Prior to joining Range, Mr. Scucchi was with JPMorgan Securities providing commercial and investment banking services to small and mid-cap technology companies. Before joining JPMorgan Securities, Mr. Scucchi spent a number of years at Ernst & Young LLP in the audit practice. Mr. Scucchi earned a Bachelor of Science in Business Administration from Georgetown University and a Master of Science in Accountancy from the University of Notre Dame. Mr. Scucchi is a CFA Charterholder and a licensed certified public accountant in the state of Texas.

Erin W. McDowell, senior vice president – general counsel and corporate secretary, joined Range in January 2015 as division counsel for the Appalachia Division and was promoted to vice president, deputy general counsel & assistant corporate secretary before being appointed to general counsel and corporate secretary in March 2023. Ms. McDowell has more than 20 years of legal experience. Prior to joining Range, Ms. McDowell spent over ten years with the law firm Eckert Seamans Cherin & Mellott in the areas of commercial litigation and environmental regulatory counseling. Ms. McDowell graduated from Bucknell University, magna cum laude, with a Bachelor of Arts in Economics and Environmental Studies and then earned a Juris Doctor from the University of Pittsburgh School of Law.

Ashley S. Kavanaugh, vice president – controller and principal accounting officer, joined Range in 2012. She held the positions of financial reporting manager and vice president – accounting before being appointed to controller and principal accounting officer in March 2024. Prior to joining Range, she held various positions of increasing responsibility with Ernst & Young LLP beginning in 2004. Ms. Kavanaugh earned a Bachelor of Business Administration and Master of Accountancy from Baylor University and is a licensed certified public accountant in the state of Texas.

Governmental Regulation

Enterprises that sell securities in public markets are subject to regulatory oversight by federal agencies such as the SEC. The NYSE, a private stock exchange, also requires us to comply with listing requirements for our common stock. This regulatory oversight imposes on us the responsibility for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting. Additionally, we are responsible for ensuring that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the NYSE listing rules and regulations of the SEC could subject us to litigation from public or private plaintiffs. Failure to comply with the rules of the NYSE could also result in the de-listing of our common stock, which could have an adverse effect on the market price of our common stock. Compliance with some of these rules and regulations is costly and regulations are subject to change or reinterpretation.

Exploration and development and the production and sale of natural gas and NGLs are subject to extensive federal, state and local regulations, mandates and trade agreements. Governmental policies affecting the energy industry, such as taxes, tariffs, duties, price controls, subsidies, incentives, foreign exchange rates and import and export restrictions, can influence the viability and volume of production of certain commodities, the volume and types of imports and exports, whether unprocessed or processed commodity products are traded, and industry profitability. For example, the United States government has in the past imposed, and may in the future impose, tariffs on certain foreign imports and any resulting retaliation by those foreign governments may disrupt aspects of the energy market. Disruption and uncertainty of this sort can affect the price of natural gas and NGLs and may cause us to change our plans for exploration and production levels. An overview of relevant federal, state and local regulations is set forth below. We believe we are in substantial compliance with currently applicable laws and regulations, and the continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur, or past non-compliance with environmental laws or regulations may be discovered. See Item 1A. Risk Factors – The natural gas industry is subject to extensive regulation. We do not believe we are affected differently by these regulations than others in the industry.

General Overview. Our oil and gas operations are subject to various federal, state and local laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:

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leases;

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acquisition of seismic data;

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location of wells, pads, roads, water storage, facilities or rights of way;

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size of drilling and spacing units or proration units;

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number of wells that may be drilled in a unit;

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unitization or pooling of oil and gas properties;

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drilling, casing and completion of wells;

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issuance of permits in connection with exploration, drilling, production, gathering, processing and transportation;

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well production, maintenance, operations and security;

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spill prevention and containment plans;

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emissions permitting or limitations;

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protection of endangered species;

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use, transportation, storage and disposal of hazardous waste, fluids and materials incidental to natural gas and NGLs operations;

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surface usage and the restoration of properties upon which wells have been drilled;

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calculation and disbursement of royalty payments and production taxes;

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plugging and abandoning of wells;

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hydraulic fracturing;

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water withdrawal and water transfer;

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marketing of production;

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transportation of production; and

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health and safety of employees and contract service providers.

In August 2005, the United States Congress ("Congress") enacted the Energy Policy Act of 2005 ("EPAct 2005"). Among other matters, EPAct 2005 amends the Natural Gas Act ("NGA") to make it unlawful for "any entity," including otherwise non-jurisdictional producers such as Range, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (the "FERC"), in contravention of rules prescribed by the FERC. In January 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit any such statement necessary to make the statements not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities are conducted in connection with gas sales, purchases or transportation subject to the FERC’s jurisdiction which includes the reporting requirements under Order 704 (as defined and described below). Therefore, EPAct 2005 was a significant expansion of the FERC’s enforcement authority. Range has not been affected differently than any other producer of natural gas by this act. Failure to comply with applicable laws and regulations with respect to EPAct 2005 could result in substantial penalties and the regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations with respect to EPAct 2005, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the FERC, other federal regulatory entities and the courts. We cannot predict when or whether any such proposals may become effective.

In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing ("Order 704"). Under Order 704, wholesale buyers and sellers of more than 2.2 million Mmbtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are required to report to the FERC, on May 1st of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting.

Intrastate gas pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate gas pipeline rates, varies from state to state. Additional proposals and proceedings that might affect the gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their impact, if any, on our operations. We believe that the regulation of intrastate gas pipeline transportation rates will not affect our operations in any way that is materially different from its effects on similarly situated competitors.

Natural gas processing. We depend on gas processing operations owned and operated by third parties. There can be no assurance that these processing operations will continue to be unregulated in the future. However, although the processing facilities may not be directly related, other laws and regulations may affect the availability of gas for processing, such as state regulation of production rates and maximum daily production allowable from gas wells, which could impact our processing.

Gas gathering. Section 1(b) of the NGA exempts gas gathering facilities from FERC jurisdiction. We believe that our gathering facilities meet the tests the FERC has traditionally used to establish a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts. Thus, we cannot guarantee that the jurisdictional status of our gas gathering facilities will remain unchanged.

We depend on gathering facilities owned and operated by third parties to gather production from our properties, and therefore we are affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or state regulations affect the rates charged for gathering services at any of these third-party facilities, we may also be affected by these changes. We do not anticipate that we would be affected differently than similarly situated gas producers.

Regulation of transportation and sale of oil and natural gas liquids. Intrastate liquids pipeline transportation rates, terms and conditions are subject to regulation by numerous federal, state and local authorities and, in a number of instances, the ability to transport and sell such products on interstate pipelines is dependent on pipelines that are also subject to FERC jurisdiction under the Interstate Commerce Act (the "ICA"). We do not believe these regulations affect us differently than other producers.

The ICA requires that pipelines maintain a tariff on file with the FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be just and reasonable. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC. Recent FERC actions addressing rate design for interstate transportation provided by intrastate pipelines under the Natural Gas Policy Act Section 311 have affirmed the use of straight‑fixed‑variable rate structures for such service. Changes in Section 311 rate design, by increasing the fixed (reservation) component of transportation charges, may affect the tariffs charged by intrastate pipelines and, indirectly, our transportation costs and realized prices where we rely on third‑party intrastate pipelines providing Section 311 service. We will monitor these developments and the implementation of rate design changes by our counterparties.

The FERC's regulations include a methodology for oil pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates. Under the FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. In December 2020, the FERC initially set the index ceiling level at Producer Price Index for Finished Goods (“PPI-FG”) plus 0.78%. Then, in January 2022, the FERC acted on rehearing of its rulemaking docket and lowered the index ceiling for this period to PPI-FG minus 0.21% for the five-year period from July 1, 2021 to June 30, 2026. On July 1, 2023, oil pipelines regulated by FERC and utilizing this index system were able to increase their rates by over 13%, which amounted to the largest index rate increase since FERC initiated this methodology. However, in July 2024 and as a result of the outcome in Liquid Energy Pipeline Association v. FERC, the original index ceiling level based on PPI-FG plus 0.78% was reinstated. Subsequently, in October 2024, the FERC issued a supplemental notice of proposed rulemaking that proposed a reduction to the reinstated index by one percent. However, on November 20, 2025, as a result of comments received, the FERC elected to withdraw the supplemental notice of proposed rulemaking and to terminate the rulemaking proceedings related to the index ceiling adjustment. Also on November 20, 2025, the FERC completed its five‑year review of the oil pipeline index and issued a notice of proposed rule-making applicable to the next five‑year period beginning July 1, 2026. Beginning July 1, 2026, the proposed index will be PPI-FG minus 1.42%. The FERC sought public comments on this proposed rule-making through January 20, 2026, but there has not been a status update for this proposed rulemaking since the closing of the comment period. Changes to the index level for the 2026–2031 period could affect tariffs charged by pipelines that transport NGLs associated with our production and, indirectly, our realized prices and cash flows. We will monitor these developments and the implementation of any index changes by such counterparties

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity by current shippers or capacity requests are received from a new shipper. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Environmental and Occupational Health and Safety Matters

Our operations are subject to numerous federal, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may include, but are not limited to:

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the acquisition of a permit before construction commences;

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restriction of the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines;

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governing the sourcing and disposal of water used in the drilling and completion process;

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limiting or prohibiting drilling activities on certain lands lying within wilderness, wetlands, frontier and other protected areas;

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requiring some form of remedial action to prevent or mitigate pollution from existing and former operations such as plugging abandoned wells or closing earthen impoundments; and

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imposing substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings.

These laws and regulations also may restrict the rate of production. Moreover, changes in environmental laws and regulations often occur, and any changes that result in more stringent and costly well construction, drilling, water management or completion activities or more restrictive waste handling, storage, transport, disposal or cleanup requirements for any substances used or produced in our operations could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general.

Oil and gas activities have increasingly faced opposition from certain organizations and, in certain areas, have been restricted or banned by governmental authorities in response to concerns regarding the prevention of pollution or the protection of the environment. Moreover, some environmental laws and regulations may impose strict liability regardless of fault or knowledge, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties at sites we currently own or where we have sent wastes for disposal. To the extent future laws or regulations are implemented or other governmental action is taken that prohibits, restricts or materially increases the costs of drilling, or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected. The following is a summary of some of the environmental laws to which our operations are subject.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the Superfund law and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release or threatened release of a hazardous substance into the environment. These persons may include owners or operators of the disposal site or sites where the hazardous substance release occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, all of these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties, pursuant to environmental statutes, common law or both, to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Although petroleum, including crude oil and natural gas, is not a hazardous substance under CERCLA, several courts have ruled that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA and that releases of such wastes may therefore give rise to liability under CERCLA. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA. In addition, certain state laws also regulate the disposal of oil and natural gas wastes. New state and federal regulatory initiatives that could have a significant adverse impact on us may periodically be proposed and enacted.

Waste handling. We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state laws, which impose requirements related to the handling and disposal of non-hazardous solid wastes and hazardous wastes. Drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy are currently regulated by the EPA and state agencies under RCRA’s less stringent non-hazardous solid waste provisions. It is possible that these solid wastes could in the future be reclassified as hazardous wastes, whether by amendment of RCRA or adoption of new laws, which could significantly increase our costs to manage and dispose of such wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, may be regulated as hazardous wastes. Although the costs of managing wastes classified as hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies in our industry. In December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. As a result, on April 23, 2019, the EPA decided to retain its current position on the regulation of oil and gas waste pursuant to RCRA. Nevertheless, any future changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

We currently own or lease, and have in the past owned or leased, properties that have been used for many years for the exploration and production of crude oil and natural gas. Petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where such materials have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and comparable state laws and regulations. Under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination or to perform remedial activities to prevent future contamination.

Water discharges and use. The Federal Water Pollution Control Act, as amended (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans (also referred to as SPCC plans) in connection with on-site storage of greater than threshold quantities of oil. In November 2025, the EPA and the United States Army Corps of Engineers proposed a rule updating the definition of “waters of the United States” under the CWA. Changes in how federal jurisdictional waters and adjacent wetlands are delineated can affect whether activities require federal permits (such as Section 404 dredge‑and‑fill authorizations), the scope of permit conditions, and the timing of approvals. Regardless of federal definitional changes, our projects in Pennsylvania remain subject to the Pennsylvania’s Clean Streams Law and related programs, which may require state approvals and best management practices

based on site‑specific determinations. We regularly review our natural gas, NGLs and oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans, the costs of which are not expected to be substantial.

The Oil Pollution Act of 1990, as amended ("OPA"), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from an oil spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in substantial compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

The Underground Injection Control Program authorized by the Safe Drinking Water Act prohibits any underground injection unless authorized by a permit. In connection with our operations, Range may dispose of produced water in underground wells, which are designed and permitted to place the water into deep geologic formations, isolated from fresh water sources. However, because some states have become concerned that the disposal of produced water could, under certain circumstances, contribute to seismicity, they have adopted or are considering adopting additional regulations governing such disposal. We currently do not utilize underground injection in our operations.

Hydraulic fracturing. Hydraulic fracturing, which has been used by the industry for over 60 years, is an important and common practice to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely apply hydraulic fracturing techniques as part of our operations. This process is typically regulated by state environmental agencies and oil and natural gas commissions; however, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final regulations under the Clean Air Act (as defined below) governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; proposed effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing in May 2014. Additionally, while the Federal Bureau of Land Management released a final rule setting forth disclosure requirements and other regulatory mandates for hydraulic fracturing on federal lands in March 2015, on December 29, 2017, the United States Department of the Interior - Bureau of Land Management rescinded the 2015 rule that would have set new environmental limitations on hydraulic fracturing, or fracking, on public lands because it believed the 2015 rule imposed administrative burdens and compliance costs that were not justified. Moreover, from time to time, Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition to any actions by Congress, certain states in which we operate, including Pennsylvania, have adopted, and other states are considering adopting, regulations imposing or that could impose new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. For example, in November 2023, Pennsylvania Governor Josh Shapiro instructed the Pennsylvania Department of Environmental Protection ("DEP") to take immediate action to pursue formal rulemaking and policy changes, including new requirements for the disclosure of chemicals used in drilling, improved control of methane emissions aligned with federal policy, stronger drilling waste protections (including inspection of secondary containment) and corrosion protections for gathering lines that transport natural gas. As a result, in January 2024, the DEP announced that it would implement a policy requiring natural gas well operators to disclose chemicals they use in drilling and hydraulic fracturing operations before the chemicals are used on-site. Certain states and political subdivisions have prohibited hydraulic fracturing. Range currently does not have operations in any of those states or political subdivisions. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we currently, or in the future plan to operate, we may incur additional, more significant, costs to comply with such requirements. As a result, we could also become subject to additional permitting requirements, new setback distances (see below Land Use and Setbacks section) or experience added delays or curtailment in the pursuit of exploration, development, or production activities.

We believe that our hydraulic fracturing activities follow applicable industry practices and legal requirements for groundwater protection and that our hydraulic fracturing operations have not resulted in material environmental liabilities. We do not maintain insurance policies intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our existing insurance policies would cover any alleged third-party bodily injury and property damage caused by hydraulic fracturing including sudden and accidental pollution coverage.

Air emissions. The Clean Air Act of 1963, as amended (the “Clean Air Act”) and comparable state laws restrict the emission of air pollutants from many sources. These laws and implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or use specified equipment or technologies to control emissions. We may be required to incur certain capital expenditures for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals for emissions of pollutants. For example, effective December 10, 2022, the DEP adopted heightened permitting conditions for newly permitted or modified natural gas compressor stations, processing plants and transmission stations to regulate greenhouse gas emissions on such sites. Then, on

December 2, 2023, the EPA released a final rule on the New Source Performance Standards (“NSPS”) to reduce emissions of methane and other air pollution from oil and natural gas operations. Among other things, the final rule (i) requires states to reduce methane emissions from hundreds of thousands of existing sources nationwide for the first time, (ii) phases out routine flaring from natural gas wells, (iii) requires the deployment of innovative and advanced monitoring technologies by establishing performance requirements that can be met by a broader array of technologies, (iv) leverages data collected by certified third parties to identify and address “super emitting” sources and eliminate or minimize emissions from common pieces of equipment used in oil and gas operations such as process controllers, pumps and storage tanks and (v) requires proper documentation that wells are properly closed and plugged before monitoring is allowed to end. In response to public comments, the EPA adjusted several provisions of the proposed rule to allow extended time for compliance including a two-year phase-in period for eliminating routine flaring of natural gas emitted from new oil wells. Further, in May 2024, the EPA finalized amendments to rules in the Petroleum and Natural Gas Systems source category (subpart W) of the Greenhouse Gas Reporting Program. The final amendments are comprised of four parts intended to (i) address potential gaps in reporting of emissions data for specific sectors so that the reporting under subpart W reflects total methane emissions from applicable facilities, (ii) add new emissions-calculation methodologies based on empirical data, (iii) improve transparency of the data collected, and (iv) make technical clarifications and corrections. These amendments had a phased-in implementation schedule, with certain provisions becoming effective in July 2024 and the remainder effective January 1, 2025. However, on September 16, 2025, the EPA proposed a rule to suspend greenhouse gas reporting under subpart W until 2034. The amendments to subpart W and the finalization of the EPA proposed rule to suspend greenhouse gas reporting may impact our future greenhouse gas emissions reported to the EPA.

Also, as part of the Inflation Reduction Act of 2022, Congress amended the Clean Air Act to create the Methane Emissions Reduction Program and Congress directed the EPA to collect a waste emissions charge on waste emissions of methane from certain oil and gas facilities. In November 2024, the EPA finalized a rule to facilitate implementation of calculation procedures, flexibilities, and exemptions related to the waste emissions charge, which applies to petroleum and natural gas facilities that emit more than 25,000 metric tons of carbon dioxide equivalent per year as reported under the amended subpart W of the Greenhouse Gas Reporting Program and that are not otherwise exempt. However, in May 2025, a joint resolution by the United States Congress and President Trump became effective revoking the November 2024 EPA rule related to waste-emissions charges and the legislation commonly known as the One Big Beautiful Bill Act ("OBBBA") postponed any implementation of a waste emissions charge until 2034.

Finally, in November 2025, the EPA issued an interim final rule extending certain near‑term compliance deadlines under the 2023 methane rules for the oil and natural gas sector (including requirements applicable to new sources under the NSPS and to existing sources under state implementation of emissions guidelines). The interim extensions are intended to provide additional time for regulated parties and states to implement monitoring, control, and reporting provisions while the EPA finalizes related guidance and program elements. These timing adjustments do not eliminate underlying obligations but may shift the phasing of compliance activities and expenditures for applicable facilities.

Compliance with these or any similar subsequently enacted regulatory initiatives could directly impact us by requiring installation of new emission controls on some of our equipment, resulting in the need for additional permitting and introducing potential permitting delays and increasing our capital expenditures and operating costs, which could adversely impact our business.

Climate change. In 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment because emissions of such gases were, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted regulations under the existing Clean Air Act establishing Title V and Prevention of Significant Deterioration (“PSD”) permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. We could become subject to these Title V and PSD permitting reviews and be required to install the best available control technology to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if such facilities emitted volumes of GHGs in excess of threshold permitting levels. The EPA has also adopted rules requiring the reporting of GHG emissions from specified emission sources in the United States on an annual basis, including certain oil and natural gas production facilities, which include several of our facilities. We believe that our monitoring activities and reporting are in substantial compliance with applicable obligations.

Congress has from time to time considered legislation to reduce emissions of GHGs and there have been a number of federal regulatory initiatives to address GHG emissions in recent years, such as the establishing of Title V and PSD permitting reviews for GHG emissions, as described in more detail above. For example, Congress enacted the Inflation Reduction Act of 2022 which, among other things, adopted a waste emissions charge to be assessed against oil and gas operators. As noted above, this charge has been postponed by later legislative action, but it is possible that such charges become applicable in the future.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future federal or state laws and regulations or international compacts could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements. On an international level, the United States was one of almost 200 nations that,

in December 2015, agreed to an international climate change agreement in Paris, France (“Paris Agreement”) that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets, which agreement formally entered into force on November 4, 2016. The United States formally accepted that agreement in September 2016. In January 2025, President Trump signed an executive order directing the United States to withdraw from the Paris Agreement, which withdrawal became effective in January 2026. It is not yet clear how withdrawal from the Paris Agreement or any separately negotiated agreement could impact us.

President Biden issued numerous executive orders during his administration directing the administration’s approach to addressing climate change, including executive orders related to rulemakings, prioritizing climate change, revoking prior executive orders, and addressing leasing for oil and gas production on federal lands. Upon taking office in January 2025, President Trump issued a series of executive orders not only revoking the previously referenced executive orders issued by President Biden, but also setting the policy direction for energy development for President Trump’s administration – including pausing disbursement of funds under the Inflation Reduction Act and the Infrastructure Investment and Jobs Act, directing heads of executive departments and agencies to identify and exercise emergency authority to advance domestic energy resources, restarting reviews and approvals of liquefied natural gas export projects, pausing still ongoing Executive Branch rulemakings, and to begin to streamline energy permitting processes. Range will continue to monitor the effects, if any, of these and any future executive orders issued by President Trump, as well as any related congressional actions, on Range's operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

We believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2025, nor do we anticipate that such expenditures will be material in 2026. However, we regularly incur expenditures and undertake projects to comply with environmental laws and to optimize our emissions performance. We anticipate those costs will continue to be incurred in the future.

Occupational health and safety. We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended ("OSHA"), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements.

Endangered Species Act. The Endangered Species Act of 1973 (“ESA”) and related state laws and regulations protect plant and animal species that are threatened or endangered. Some of our operations are located in areas that are or may be designated as protected habitats for endangered or threatened species, including the Northern Long-Eared and Indiana bats, which have a seasonal impact on our construction activities and operations. The designation of previously unprotected species as threatened or endangered, or redesignation of a threatened species as endangered, in areas where our operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitation of our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

Land Use and Setbacks. Local governments or political subdivisions may seek to adopt ordinances within their jurisdiction regulating the location of drilling and/or hydraulic fracturing activities. Certain states and political subdivisions have imposed setbacks that may limit where drilling and hydraulic fracturing can take place. For instance, in November 2024, Cecil Township, located in Washington County, Pennsylvania increased the setback distance for oil and gas operations from 500 feet to 2,500 feet from protected structures like residences and businesses and 5,000 feet from schools and hospitals, which eliminates future oil and gas operations on new well pads in the Township. Following adoption of the Cecil Township ordinance, we challenged the ordinance’s expanded setback provisions before the Township Zoning Hearing Board. However, the Township Zoning Hearing Board subsequently dismissed our challenge, after which we filed an appeal with the Washington County Court of Common Pleas. These proceedings remain pending and we cannot predict their timing or outcome, which could inform how other municipalities consider similar measures. See also, Item 1A. Risk Factors, Risks related to our operations.

ITEM 1A. RISK FACTORS

While we utilize robust processes and resources to identify and manage risks, we are subject to various risks and uncertainties in the course of our business, some of which are comparable to the risks any business is exposed to and some that are unique to our operations. The following summarizes the known material risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering making or maintaining an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in the section entitled Disclosures Regarding Forward-Looking Statements and other information included and incorporated by reference into this Annual Report on Form 10-K. These risks are not the only risks we face. Our business could also be impacted by additional risks and uncertainties not currently known to us or that we believe not to be material based on the information we have at this time. If any of the events described below as risks actually occur, it could materially harm our business, financial condition or results of operations or impair our ability to implement our business plans or complete development activities as expected. In that case, the market price of our common stock could decline or, if severe enough, the entire value of an investment in our securities could become worthless.

Economic risks related to our business

Volatility of natural gas, NGLs and oil prices affects our cash flow and capital resources and could significantly hamper our ability to operate economically. Natural gas, NGLs and oil prices are volatile, and a decline in prices could adversely affect our profitability and financial condition. As a commodity business, the oil and gas industry is typically cyclical and we expect the volatility to continue. Natural gas prices are likely to affect us the most because approximately 65% of our proved reserves were natural gas as of December 31, 2025 and, at times in the past, natural gas prices have been low compared to our costs to produce. Natural gas, NGLs and oil prices fluctuate in response to changes in supply and demand, market uncertainty and other factors that are beyond our control. These factors include:

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events that impact domestic and foreign supply of, and demand for, natural gas, NGLs and oil;

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the continued operation of export facilities to supply foreign markets with natural gas and natural gas liquids and the ability to transport the product to markets due to shipping restrictions, armed conflict or terrorist threats and attacks;

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changes in weather patterns and events, including natural disasters such as hurricanes, floods, wildfires and tornadoes;

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technological advances affecting energy consumption, storage and energy supply;

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the production levels of non-OPEC countries, including production levels in the United States’ shale plays;

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general economic conditions worldwide;

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the price and availability of, and demand for, alternative and competing forms of energy, such as nuclear, geothermal, hydroelectric, wind and solar;

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the level of drilling, completion and production activities by other companies, and variability therein, in response to market conditions;

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the ability of the members of OPEC and other exporting nations to agree to and comply with production controls;

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military, economic and political conditions in natural gas, NGLs and oil producing regions;

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the cost of exploring for, developing, producing, transporting and marketing natural gas, NGLs and oil; and

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domestic (federal, state and local) and foreign governmental regulations, sanctions, tariffs and taxation, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels.

The long-term effects of these and other factors on the prices of natural gas, NGLs and oil prices are uncertain. Historical declines in natural gas, NGLs and oil commodity prices have adversely affected our business by:

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reducing the amount of natural gas, NGLs and oil that we can economically produce;

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reducing our revenues, operating income and cash flows;

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reducing the amount of cash flows available for capital expenditures;

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increasing the cost of obtaining capital, such as equity and debt financings; and

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reducing the standardized measure of discounted future net cash flows relating to natural gas, NGLs and oil.

If demand for natural gas, NGLs and oil is reduced, the prices we receive for and our ability to market and produce our natural gas, NGLs and oil may be negatively affected. Volatility in natural gas, NGLs and oil markets and the price we receive for our production is largely determined by various factors beyond our control. Production from natural gas and oil wells in some geographic areas of the United States has been or could be curtailed for considerable periods of time due to lack of local market demand and transportation and storage capacity. In the recent past, we have temporarily shut-in wells due to low commodity prices and it is possible that some of our wells may be shut-in in the future or sales terms may be less favorable than might otherwise be obtained should demand for our products decrease and/or prices decrease. Competition for markets has been vigorous and there remains uncertainty about prices purchasers will pay or the availability of sufficient storage, all of which could have a material adverse effect on our cash flows, results of operations and financial position.

We could experience periods of higher costs. These cost increases could reduce our profitability, cash flow and ability to conduct development activities as planned. We rely on third-party contractors to provide key services and equipment for our operations. Historically, our capital and operating costs have risen during periods of increasing natural gas, NGLs and oil prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling and completions activity increases; tariffs on foreign goods; and increased taxes. Increased levels of drilling activity in the natural gas, NGLs and oil industry could lead to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in our revenue, thereby negatively impacting our profitability, cash flow and ability to conduct development activities as planned and on budget.

Based on the cost inflation pressure experienced over the last few years, we continue to undertake actions and implement plans to strengthen our supply chain. Nevertheless, we expect to experience some supply chain constraints and inflationary pressure on our cost structure including steel, fuel and labor, among other items, for the foreseeable future. By continuing to focus on cost control initiatives and actions, which increase our drilling, completion and operating efficiencies, we may be able to mitigate some inflationary pressures in the future.

Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market products and secure and retain trained personnel. Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing products and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory drilling locations and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit.

None of our senior management team nor any of our other officers are subject to an employment agreement and therefore retaining them as employees is less certain than if they were parties to an employment agreement. The unanticipated loss of one or more of these individuals could have a material adverse effect on our business. Further, the loss of key technical professionals with extensive experience in our core operating area could be difficult to replace if they were to leave and the loss of such employees could adversely affect the costs of drilling, completing and operating our wells. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. We may not be able to successfully compete in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining trained personnel and raising additional capital, which could have a material adverse effect on our business.

Our debt obligations may limit our liquidity and financial flexibility. We are a borrower under fixed rate senior notes and maintain a floating rate bank credit facility which had $118.0 million of borrowings as of December 31, 2025. Our exploration and development program requires substantial capital resources depending on the level of drilling and the expected cost of services. Existing operations also require ongoing capital expenditures. Increases in our level of debt may:

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require us to dedicate a greater portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations or return of capital to stockholders;

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make us vulnerable to increases in interest rates;

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increase our vulnerability to a downturn in commodity prices or the general economy;

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place us at a competitive disadvantage compared to our competitors with lower debt service obligations;

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limit our operating flexibility due to financial and other restrictive covenants;

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limit our flexibility to maintain or grow our business and plan for, or react to, changes in our business and the industry in which we operate; and

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limit or prevent our ability to pay dividends and other restricted payments (as defined in our bank credit facility).

Historically, we have funded our capital expenditures through a combination of cash flow from operations and our bank credit facility and, in limited circumstances, debt and equity issuances. We have also engaged in asset monetization transactions. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of natural gas, NGLs and oil and our success in developing and producing our reserves. If our access to capital were limited as a result of various factors, which could include a decrease in revenues due to lower natural gas, NGLs and oil prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to fund our operations and replace our reserves resulting in reduced financial flexibility.

The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lenders, taking into account our estimated proved reserves and is subject to periodic re-determinations based on pricing models determined by the lenders at such time. Declines in natural gas, NGLs and oil prices adversely impact the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base and could result in a determination to lower our borrowing base, reducing our financial flexibility.

Disruptions or volatility in the global finance markets may lead to a contraction in credit availability impacting our ability to finance our operations. We benefit from continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to conduct our planned operations, our ability to manage our debt maturities and our flexibility to react to changing economic and business conditions. We are also exposed to some credit risk related to our bank credit facility to the extent that one or more of our lenders experiences liquidity problems and is unable to provide necessary funding to us under our existing revolving line of credit.

Any failure to meet our debt obligations could harm our business, financial condition and results of operations. Our earnings and cash flow will fluctuate from year-to-year due to the variable nature of commodity prices. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek equity sales or restructure our debt. Our ability to restructure our debt will depend on the condition of the capital markets and our financial condition at such time. Any restructuring of debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our operations and our financial flexibility. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives.

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term cash flow relative to debt balances. Liquidity, asset quality, cost structure, product mix (natural gas, NGLs and oil) and projected commodity pricing levels are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt and could require us to post letters of credit or other forms of collateral for certain obligations. We cannot provide assurance that our current ratings will remain in effect for any given period of time or that a rating will not be downgraded in the future.

As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part. The terms of our senior indebtedness, including our revolving credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under our indentures or other loan agreements. Accordingly, should an event of default above certain thresholds occur under any of those agreements, we face the prospect of being in default under all of our debt agreements, obligated in such instance to satisfy all of our outstanding indebtedness but in all probability unable to satisfy all of our outstanding obligations simultaneously. In such an event, we

might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to continue our business plan, make capital expenditures and finance our operations.

Derivative transactions may limit our potential gains and involve other risks. To manage our exposure to commodity price volatility, we currently, and likely will in the future, enter into derivative arrangements, utilizing commodity derivatives ("hedges") with respect to a portion of our future production. Hedges are generally designed to lock in future prices for commodities to limit volatility and increase the predictability of cash flow. These hedging transactions can limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge. In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

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our production is less than expected;

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the counterparties to our futures contracts fail to perform on their contract obligations; or

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an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index and the natural gas, NGLs or oil sales prices we receive.

We cannot be certain that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas, NGLs or oil. Furthermore, if we choose not to engage in derivative transactions in the future, we may be more adversely affected by decreases in natural gas, NGLs or oil prices than our competitors who utilize derivative transactions. Lower natural gas, NGLs and oil prices over a longer term will also negatively impact our ability to enter into derivative contracts at prices that exceed our costs of production.

We are exposed to a risk of financial loss if a counterparty fails to perform under a derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict such changes, our ability to mitigate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge counterparties, or some other similar proceeding or liquidity constraint, would make it unlikely we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices, our derivative receivable positions increase, which increases our exposure to the counterparties. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Risks related to our operations

Drilling is an uncertain and costly activity. The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough natural gas, NGLs and oil to be commercially viable after drilling, operating and other costs. There is no way to conclusively know in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in commercially viable quantities. Furthermore, our drilling and producing operations may be curtailed, delayed, or canceled as a result of a variety of factors, including, but not limited to:

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increases in the costs, shortages or delivery delays of drilling rigs, equipment, water for hydraulic fracturing services, labor, or other services;

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unexpected operational events and drilling conditions;

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reductions in natural gas, NGLs or oil prices;

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limitations in the market for natural gas, NGLs or oil;

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facility or equipment malfunctions or operator error;

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equipment failures or accidents;

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loss of title and other title-related land issues;

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pipe or cement failures and casing collapses;

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compliance with, or changes in, permitting, environmental, tax and other governmental requirements;

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environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, and unauthorized discharges of hazardous materials;

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lost or damaged oilfield drilling and service tools;

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unusual or unexpected geological formations;

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loss of drilling fluid circulation;

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pressure or irregularities in geological formations;

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fires, surface craterings, blowouts or explosions;

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uncontrollable flows of oil, natural gas or well fluids;

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availability and timely issuance of required governmental permits and licenses; and

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civil unrest or protest activities.

If any of these factors were to occur, we could lose all or a part of our investment or we could fail to realize the expected benefits, either of which could materially and adversely affect our revenue and profitability. Our operations involve utilizing drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

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landing the wellbore in the desired drilling zone;

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drilling the wellbore to the full planned length;

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staying in the desired drilling zone while drilling horizontally through the formation;

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running casing the entire length of the wellbore; and

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being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing horizontal wells include, but are not limited to, the following:

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the ability to fracture and stimulate the planned number of stages;

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the ability to run tools the entire length of the wellbore during completion operations; and

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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. Our management team has specifically identified and scheduled certain drilling locations for future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, obtaining lease agreements and managing lease expirations, transportation constraints, permits, regulatory and zoning approvals and other factors. Unless production is established within the spacing units covering acreage subject to an expiration, the leases for such acreage will expire. Because of these uncertain factors, our actual drilling activities may materially differ from those presently identified. In addition, we will require significant capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our business and results of operations and financial condition.

Our business is subject to operating hazards that could result in substantial losses or liabilities that may not be fully covered under our insurance policies. While we have processes and procedures that we utilize to mitigate operational risks, natural gas, NGLs and oil operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids (especially those that reach surface water or groundwater), fires, pipe or cement failures, pipeline ruptures or spills, vandalism, pollution, releases of toxic gases, geological formations with abnormal or unexpected pressures, adverse weather conditions or natural disasters and other environmental hazards and risks. In addition, our operations are sometimes near populated commercial or residential areas. If any of these hazards occur, we could sustain substantial losses as a result of:

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personal injury or loss of life;

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damage to or destruction of property, natural resources and equipment;

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pollution or other environmental damage;

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investigatory and cleanup responsibilities;

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regulatory investigations and penalties or lawsuits;

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suspension of operations by regulatory authorities; and

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repairs and remediation to resume operations.

We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. Our insurance includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our insurance coverage will adequately protect us against liability from all potential consequences, damages and losses.

We may elect not to purchase insurance in instances where we determine that the cost of available insurance is excessive relative to the risks we believe are presented. However, such determinations may prove to be incorrect. Further, some forms of insurance may become unavailable in the future. If we incur liability from a significant event and the damages are not covered by insurance or are in excess of policy limits, then we would have lower revenues and funds available to us for our operations, that could, in turn, have a material adverse effect on our business, financial condition and results of operations.

Additionally, we rely to a large extent on facilities owned and operated by third parties, in particular gas transportation and processing facilities, and damage to, or destruction of, those third-party facilities could affect our ability to process, transport and sell our production. To a limited extent, we maintain business interruption insurance related to key facilities and connecting lines for our wells in Pennsylvania where we are insured for potential catastrophic losses from the interruption of production caused by a covered loss of or damage to the processing plants; however, such insurance is limited and may not adequately protect us from all potential consequences, damages and losses.

Our producing properties are concentrated in Pennsylvania, making us vulnerable to risks associated with operating in one geographic and political region. Essentially 100% of our total estimated proved reserves are located in Pennsylvania. We are additionally vulnerable to processing and transportation constraints for our products in this area. We are more heavily exposed to the extensive and evolving regulatory environment in Pennsylvania which may lead to additional costs, delays or interruptions of construction, development and production from our wells. See also, below, The natural gas industry is subject to extensive regulation.

Additionally, local governments in Pennsylvania are authorized to adopt and implement ordinances and impose certain restrictions regarding siting of well sites, tank pads and other related facilities. Approval from one or more local governmental bodies, some following a public hearing, may be required before commencing construction of facilities which can result in delay, increased expense or, in some cases, prevention of development. Moreover, new initiatives or regulations could propose new setback distances or further restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of substances generated by our operations, including, but not limited to, produced water, drilling fluids and other wastes associated with our operations. For example, in January 2024, the DEP announced that it would implement a policy requiring natural gas well operators to disclose chemicals they use in drilling and hydraulic fracturing operations before the chemicals are used on-site. Further, in November 2024, Cecil Township, located in Washington County, Pennsylvania, adopted an ordinance that increased the setback distance for oil and gas operations from 500 feet to 2,500 feet from protected structures like residences and businesses and 5,000 feet from schools and hospitals. See also above Land Use and Setbacks. Separately, the DEP received a citizen petition for rulemaking to expand setback distances from natural gas operations across Pennsylvania. On December 9, 2025, the Pennsylvania Environmental Quality Board (PEQB) accepted the citizen petition for rulemaking moving the petition forward for the DEP’s review and study of the requested rulemaking. We do not expect action on the requested rulemaking for the foreseeable future and believe that the petition and requested rulemaking are unlawful. We will continue to monitor this petition, the requested rulemaking and any related developments to assess potential impacts to our operations. Currently there are a few states that have elected to ban or severely limit hydraulic fracturing. Should Pennsylvania or the federal government ban hydraulic fracturing, it would preclude economic development of our Marcellus Shale reserves potentially resulting in severe negative financial consequences to us.

We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water or dispose of or recycle water used in our operations may have a material adverse effect on our financial condition, results of operations and cash flows. Water is an essential component of our drilling and hydraulic fracturing processes. Limitation or restrictions on our ability to secure sufficient amounts of water (including limitations from natural causes such as drought) and transport it could impact our operations. If we are unable to obtain water to use in our operations from local sources, we may need to obtain it from new sources and transport the water to drilling sites, resulting in increased costs. We must either dispose of or recycle water used in our operations. Compliance with environmental and permit requirements governing the withdrawal, storage and use of recycled water, surface water or groundwater may increase costs and cause delays, interruptions or termination of our operations.

Unless we replace our reserves, our reserves and production will decline, which could adversely affect our business, financial condition and results of operations. Unless we successfully replace the reserves that we produce, our reserves will decline as reserves are depleted, eventually resulting in a decrease in natural gas, NGLs and oil production and lower revenues and cash flow from operations. Our future production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and extraction activities or by acquiring properties at acceptable costs which would result in a reduction in proved reserves and production over time. If we are unable to

replace our current and future production, our revenues will decrease and our business, financial condition and results of operations may be adversely affected.

Our business depends on natural gas and oil transportation and NGLs processing facilities, which are owned by others and depends on our ability to contract with those parties. Our ability to sell our natural gas, NGLs and oil production depends in part on the availability, proximity and capacity of gathering and transportation pipeline systems, processing facilities, rail cars, trucks or vessels owned by third parties and our ability to contract with those third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Changes in intrastate pipeline rate design for Section 311 service could increase fixed transportation costs and reduce flexibility. If intrastate pipelines that provide interstate transportation under the Natural Gas Policy Act Section 311 adopt or maintain rate designs with higher fixed (reservation) charges, our transportation costs could increase and our flexibility to manage volumes through variable charges could decline. Because we depend on third‑party systems to gather and transport our production, higher fixed fees or related tariff changes could reduce our netbacks, contribute to curtailments in constrained periods, and adversely affect our results of operations and cash flows. See also above, Our producing properties are concentrated in Pennsylvania, making us vulnerable to risks associated with operating in one geographic and political region.

Although we have some contractual control over the transportation of our products, material changes in these business relationships, including the financial condition of the contractual counterparties, could materially affect our operations. In some cases, we do not purchase firm transportation on third-party facilities and, as a result, our production transportation can be interrupted by those having firm arrangements. In other cases, we have entered into firm transportation arrangements where we are obligated to pay fees on minimum volumes regardless of actual volume throughput. If production decreases due to reduced or delayed developmental activities, the current commodity price environment, production related difficulties or otherwise, we may be unable to utilize all of our rights under existing firm transportation contracts, resulting in obligations to pay fees without receiving revenue from sales. Such fees may be significant and may have a material adverse effect on our operations. We have also entered into long-term agreements with third parties to provide natural gas gathering and processing services. In some cases, the capacity of gathering systems and transportation pipelines may be insufficient to accommodate production from existing and new wells. Federal and state regulation of natural gas and oil production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, obstacles or impediments due to coal or other mineral extraction activities and general economic conditions could adversely affect our ability to produce, gather and transport natural gas, NGLs and oil. If any of these third-party pipelines or other facilities become partially or fully unavailable to transport or process our product, or if the natural gas quality specifications for a natural gas pipeline or facility change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues could be adversely affected.

The disruption of third-party facilities due to maintenance, mechanical failures, accidents, weather and/or other reasons could negatively impact our ability to market and deliver our products. In particular, the disruption of certain third-party natural gas processing facilities that support our core operating area in southwest Pennsylvania could materially affect our ability to market and deliver natural gas production in that area especially if such disruption were to last for more than a short duration which could result in the necessity to curtail a significant amount of our production. We have no control over when or if such facilities are restored and generally have no control over what prices will be charged. A total shut-in of production could severely affect us due to a lack of cash flow, and if a substantial portion of the production volume is hedged at lower than market prices, our obligation to the counterparty under those financial hedges might have to be paid from borrowings thus further adversely affecting our financial condition.

Risks related to the industry in which we operate

The natural gas industry is subject to extensive regulation. Natural gas, NGLs, oil and other hydrocarbons, as well as our operations to produce these products, are subject to extensive laws, regulations, and ordinances at the federal, state and local level. Further, new legislation, proposed rulemaking and ordinance amendments affecting the industry are under constant review often with more expansive requirements and rules on our products and operations. Compliance with new and expanding laws from numerous governmental departments and agencies often increases our cost of doing business, delays our operations and decreases our profitability and additional uncertainty can be introduced through varying court interpretations of such laws. Certain potential legislation, such as a ban on hydraulic fracturing, could even preclude our ability to economically develop our reserves.

Matters subject to laws and regulations affecting our business include, but are not limited to: the amount and types of substances and material that may be released into the environment, including GHGs; responding to unexpected releases of regulated substances or materials to the environment; the sourcing, transportation and disposal of water used in the drilling and completions process; permits, performance rules and reporting obligations concerning drilling, completion and production operations; threatened or endangered species and waterway protection efforts; and climate related initiatives.

Environmental regulations and pollution liability could expose us to significant costs and penalties. We may incur significant costs and liabilities in complying with existing or future environmental laws, regulations and enforcement policies or initiatives. Some of these environmental laws and regulations may impose strict, joint and several liability regardless of fault or knowledge, which could subject us to liability for conduct that was lawful at the time it occurred, or conditions caused by prior owners or operators or

which relate to third-party sites where we have taken materials for recycling or disposal. Pennsylvania law also imposes criminal liability for certain releases of substances, regardless of fault or intent. Failure to comply with these laws and regulations may result in the occurrence of delays, cancellations or restrictions in permitting or performance of our projects or other operations and subject us to administrative, civil and/or criminal penalties, corrective actions and orders enjoining some or all of our operations. Our operations may be impacted by new and amended laws and regulations, reinterpretations of existing laws and regulations or increased government enforcement relating to environmental laws. For example, properly handled drilling fluids and produced water are currently exempt from regulation as hazardous waste under RCRA, and instead are regulated under RCRA’s non-hazardous waste provisions. It is possible that the EPA may in the future propose rulemaking that designates such wastes as hazardous rather than non-hazardous, and a similar designation may be made at the state level. Should this occur at the federal and/or state level it could result in significant costs to attain and maintain compliance.

We may also be exposed to liability and costs for handling of hydrocarbons, air emissions and wastewater or other fluid discharges related to our operations and waste disposal practices. Spills or other unauthorized releases of hazardous or regulated substances by us, our contractors or resulting from our operations could expose us to material losses, expenditures and liabilities, including civil and criminal liabilities, in each case under environmental laws and regulations and we are currently and have in the past been involved in such investigations, remediation and monitoring activities. The Pennsylvania Office of the Attorney General has previously announced investigations and charges generally related to our industry in Pennsylvania. Additionally, neighboring landowners and other third parties may assert claims or file lawsuits against us for personal injury and/or property damage allegedly caused by the release of substances into the environment, with or without evidence of an impact from our operations, all of which could also result in significant litigation or settlement costs as well as reputational harm.

Laws and regulations pertaining to threatened and endangered species and protection of waterways could delay or restrict our operations and cause us to incur substantial costs. Various federal and state statutes prohibit actions or operations that adversely affect endangered or threatened species and their habitats. These statutes include the federal ESA, the Migratory Bird Treaty Act, the CWA, CERCLA and similar state programs, including the Pennsylvania Oil and Gas Act and the Clean Streams Law and related regulations. For example, the United States Fish and Wildlife Service as well as state agencies may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in material restrictions to land use and delay, restrict or even prevent our operations. For additional details, please refer to Governmental Regulation in Item 1, Environmental and Occupational Health and Safety Matters, specifically the Endangered Species Act section above. Similarly, operations may be impacted, delayed or even prevented by the existence of wetlands or other environmentally sensitive areas based upon the scope of the CWA and its protection of waters of the United States as well as state laws such as the Pennsylvania Clean Streams Law and related regulations and permitting requirements. We will continue to monitor changes to the federal definition of “waters of the United States,” proposed in November 2025 since jurisdictional shifts can affect permitting scope, timing, and mitigation requirements for certain of our activities.

Climate related regulations and initiatives could expose us to significant costs and restrictions on operations. There is an ongoing public debate as to the extent to which our climate is changing, the potential causes of climate change and its potential impacts. As part of that debate, there is general belief that increased levels of GHGs, including carbon dioxide and methane, have contributed to and continue to contribute to climate change which has led to numerous regulatory, political, litigation and financial risks associated with the production of fossil fuels and emissions of GHGs. Oil and natural gas development generates GHG emissions.

Federal and state governments have from time to time considered legislation and regulations to reduce GHG emissions, including, but not limited to the implementation of GHG monitoring and reporting for the natural gas industry which includes certain of our operations. For additional details please refer to Governmental Regulation in Item 1, Environmental and Occupational Health and Safety Matters, specifically the Air emissions and Climate change sections above. There have also been a number of state and regional efforts that have emerged that seek to track and reduce GHG emissions by means of cap and trade programs where emitters would be required to acquire and surrender emission allowances in return for emitting GHGs. The Pennsylvania Environmental Quality Board approved a rule in 2020 to participate in the Regional Greenhouse Gas Initiative (“RGGI”), a multi-state program capping CO2 emissions from fossil-fuel-fired power plants. Subsequent legal challenges resulted in a July 2022 Commonwealth Court of Pennsylvania order staying Pennsylvania’s participation in RGGI, and, in November 2023, the Commonwealth Court ruled that funds generated through the RGGI are an unconstitutional tax, effectively preventing the state from participating in RGGI. Pennsylvania Governor Josh Shapiro then appealed to the Pennsylvania Supreme Court. In parallel, throughout 2024 and 2025 the Pennsylvania General Assembly advanced legislation to repeal the RGGI regulation and to bar participation absent specific legislative authorization while executive-branch policymakers pursued alternative, Pennsylvania-specific cap-and-invest concepts. However, in November 2025, Governor Shapiro signed a bill as part of a deal to resolve an ongoing budget impasse that, among other things, withdrew the Commonwealth of Pennsylvania from the RGGI (and rendered moot the related legislation in the Pennsylvania General Assembly), ending years of political and legal conflict over whether the state should join the multistate cap and trade program. We will continue to monitor these developments because any carbon-pricing program applicable to in-state generators could influence in-state power-sector gas demand, basis differentials, and, indirectly, our price realizations and development plans. We also initiated our

own internal goals to reduce GHG emissions to net zero Scope 1 and 2 GHG emissions by 2025, which we achieved in 2024 and maintained in 2025.

The outcome of federal, state and regional actions to address global climate change could result in a variety of new laws and regulations to control or restrict emissions including taxes or other charges to deter or restrict emissions of GHGs. This may also depend upon political outcomes as there have been certain candidates seeking election to various state and federal offices or their appointees, who have made pledges to restrict GHG emissions, ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of natural gas, NGLs and oil on federal lands. Our reserves development is critically dependent upon the use of hydraulic fracturing and we cannot economically develop any of our reserves without using such technology (which we believe has been safely conducted for many decades) and a ban of such technology could result in severe economic harm to us.

There are also increasing litigation risks associated with climate change concerns as a number of cities and local governments have initiated lawsuits against fossil fuel producers in state and federal court asserting claims for public nuisance and seeking damages for climate change impacts to roadways and infrastructure. Such lawsuits have also alleged that fossil fuel producers have been aware of the adverse effects of climate change and defrauded their investors by failing to adequately disclose those impacts.

Financial risks exist for fossil fuel energy companies, including natural gas producers, as in recent years, stockholders and bondholders are concerned about the potential effects of fossil fuels on climate change and may elect to shift some or all of their investments away from fossil fuel based energy. Institutional lenders who provide financing to fossil fuel energy companies are at times under pressure from activists and are the subject of lobbying to not provide funding for fossil fuel production, although this trend has recently decreased. For example, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network of Greening the Financial System, of which the Federal Reserve is a member, to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. However in January 2025, the Federal Reserve issued a statement announcing it has withdrawn from the Network of Central Banks and Supervisors for the Greening of the Financial System. Despite the declining trend, some institutional lenders may elect not to provide funding for us which could result in restriction, delay or cancellation of drilling programs, development or production activities or impair our ability to operate economically.

On March 6, 2024, the SEC adopted rules that would require public companies to disclose extensive climate change-related information in certain of their SEC filings. However, on March 15, 2024, a federal appellate court imposed a temporary stay pending judicial review of such new rules, and in response, on April 4, 2024, the SEC issued an order staying any amendments to such rules pending the completion of judicial review of the federal appellate court petitions. On February 11, 2025, the acting chairman of the SEC released a statement that he has directed the SEC staff to request that the court not schedule the case for argument to provide time for the SEC to deliberate the appropriate next steps in litigation related to The Enhancement and Standardization of Climate-Related Disclosures for Investors rule. On March 27, 2025, the SEC commissioners voted to end the defense of The Enhancement and Standardization of Climate-Related Disclosures for Investors rule. While the SEC has ceased defending the previously approved climate disclosure rules and notified the court accordingly (leaving them stayed and unlikely to take effect under the current administration), other state-level jurisdictions have already implemented or are currently developing climate disclosure requirements for large companies that operate in their jurisdictions.

Certain organizations that provide corporate governance and other corporate risk information to investors and stockholders have developed scores and ratings to evaluate companies and investment funds based on sustainability or environmental, social and governance ("ESG") metrics. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through investment and voting practices of investment advisors, public pension funds, universities and other members of the investing community. As a result, many investment funds focus on positive ESG business practices and sustainability scores when making investments. Companies which do not adapt to or comply with investor or stockholder ESG expectations and standards or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the financial condition, results of operations or cash flows of such a company could be materially and adversely affected, or could also have limited access to certain capital markets.

Moreover, we may from time-to-time create and publish voluntary disclosures regarding ESG matters. Many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.

At this time, we cannot predict the potential impact of such laws, regulations, regional or international initiatives or compacts, litigation, ESG ratings or financing restrictions due to climate concerns on our future consolidated financial condition, results of operations or cash flows; however, such impacts could be material and have material negative consequences to our business.

Information concerning our reserves and future net cash flow are estimates and may not match our results. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs and oil reserves and their values, including many factors beyond our control. Estimates of proved reserves depend on many assumptions relating to current and future economic conditions and commodity prices as well as the projected productivity of our wells and infrastructure to gather, process, store and/or transport our products to market. To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Although we utilize robust processes and procedures to evaluate and estimate our reserves, they are estimates and the actual production, revenues and costs to develop our estimated reserves will vary from estimates and these variances could be material and/or negative.

Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of natural gas, NGLs and oil that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may calculate different estimates of reserves and future net cash flows based on the same available data. Because of the subjective application of engineering principles to natural gas, NGLs and oil reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

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the amount and timing of natural gas, NGLs and oil production;

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the revenues and costs associated with that production;

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the amount and timing of future development expenditures; and

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future commodity prices.

The discounted future net cash flows from our proved reserves included in this report are not the same as the market value of the reserves attributable to our properties. As required by United States generally accepted accounting principles ("U.S. GAAP"), the estimated discounted future net revenues from our proved reserves are based on a twelve month average price (first day of the month) while cost estimates are based on current year-end economic conditions. Actual future prices and costs may be materially higher or lower. In addition, the ten percent discount factor that is required to be used to calculate discounted future net cash flows for reporting purposes under U.S. GAAP is not necessarily the most appropriate discount factor based on the cost of capital, which varies from time to time, and risks associated with our business and the oil and gas industry in general.

We may face various risks associated with the long-term trend toward increased activism against oil and gas exploration and development activities. Opposition toward oil and gas drilling and development activity has been growing over time. Companies in the oil and gas industry are often the target of activist efforts to delay or prevent oil and gas development from both individuals and non-governmental organizations who use safety, environmental compliance and business practices to support their opposition to oil and gas drilling. Anti-development activists are working to, among other things, reduce access to federal and state government lands, delay or cancel certain projects such as the development of oil and gas drilling or export facilities, as well as the pipeline infrastructure needed to transport and process oil and gas production. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling and hydraulic fracturing in the United States, even in jurisdictions like Pennsylvania that are among the most stringent in their regulation of the industry. Such activist efforts could result in the following:

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delay or denial of drilling permits or leases;

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restrictions on or prevention of installation or operation of production, gathering or processing facilities;

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restrictions on or prevention of the use of certain operating practices, such as hydraulic fracturing, or the disposal of related materials, such as hydraulic fracturing fluids and produced water;

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additional regulatory burdens;

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increased severance and/or other taxes;

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cyberattacks;

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legal challenges or lawsuits;

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negative publicity about our business or the oil and gas industry in general;

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increased costs of doing business;

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reduction in demand for our products; and

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other adverse effects on our ability to develop our properties and expand production.

We may incur significant costs associated with responding to these initiatives and such actions may materially adversely affect our financial results. Complying with any resulting additional legal or regulatory requirements that are substantial or prevent our activity could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Conservation measures and technological advances could reduce demand for oil and natural gas. Fuel conservation measures, alternative fuel requirements, governmental requirements for renewable energy resources, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation or storage devices (such as battery technology) may in the future reduce the demand for, and in turn the prices of, the natural gas, NGLs and oil that we sell. In addition, these measures may reduce the availability to us of necessary third-party services and facilities that we rely on which could increase our operational costs and adversely impact our ability to produce, transport and process natural gas, NGLs and oil. The impact of changing demand for natural gas, NGLs and oil services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Legal, tax and regulatory risks

U.S. or state tax legislation may adversely affect our business, results of operations, financial condition and cash flow. Legislation is periodically proposed that could make significant changes to United States federal income tax laws and could include the elimination of certain United States federal income tax benefits currently available to oil and gas exploration and production companies including, but not limited to, (i) the repeal of percentage depletion allowances for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs and; (iii) an extension of the amortization period for certain geological and geophysical expenditures. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced consumer demand for our products. The passage of any such legislation or any other similar change in United States federal income tax law could increase costs or eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development and any such changes could have an adverse effect on our financial condition, results of operations and cash flows.

In July 2025, OBBBA was signed into law which includes, among other things, a permanent reinstatement of 100% bonus depreciation on certain property, plant and equipment assets in the first year placed in service and a domestic research and experimental expenditures deduction. These provisions generally extend or replace provisions within the Tax Cuts & Jobs Act passed in 2017 that were previously set to expire at the end of 2025. While we believe the provisions of OBBBA are largely beneficial to our financial condition and cash flows, compliance with the provisions may result in additional costs and our cash flow may be negatively affected.

In 2022, legislation commonly known as the Inflation Reduction Act was signed into law, which includes, among other things, a corporate alternative minimum tax (the "CAMT") and a one percent excise tax on corporate stock repurchases. The CAMT generally treats a corporation as an applicable corporation in any taxable year in which the average annual adjusted financial statement income for a three taxable-year period ending prior to such taxable year exceeds $1.0 billion. If we become subject to CAMT, our cash obligations for U.S. federal income taxes could be significantly accelerated. To the extent the 1% excise tax applies to repurchases of shares under our common stock repurchases program, the number of shares we repurchase and our cash flow may be affected.

In 2012, Pennsylvania enacted legislation creating a tax referred to as the natural gas impact fee applicable to production in Pennsylvania, where essentially all of our acreage is located. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. Much like a severance tax, the fee is on a sliding scale set by the Pennsylvania Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices on the last day of each month. The impact fee increases the financial burden on our operations in the Marcellus Shale. There can be no assurance that the impact fee will remain as currently structured or that additional taxes will not be imposed. From time to time, the Pennsylvania Governor and various Pennsylvania state lawmakers have proposed legislation to enact a severance tax in substitution for, or as an addition to, the impact fee already in place. The structure of and ultimate effect of any additional tax burden cannot be estimated at this time but could be material.

Legal proceedings brought against us could result in substantial liabilities and materially and adversely impact our financial condition. Like many oil and gas companies, we are involved in various legal proceedings, including threatened claims, such as title, royalty, and contractual disputes. The cost to settle legal proceedings (asserted or unasserted) or satisfy any resulting judgment against us in such proceedings could result in a substantial liability or the loss of interests, which could materially and adversely impact our cash flows, operating results and financial condition. Judgments and estimates to determine accruals or range of losses related to legal proceedings could change from one period to the next, and such changes could be material. Current accruals may be insufficient to satisfy any such judgments. Legal proceedings could also result in negative publicity about Range. In addition, legal proceedings distract management and other personnel from their primary responsibilities. At this time, based on the information available to management, there are no pending claims or litigation which appear likely to result in a material financial impact. However, management’s assessment of pending claims and litigation could be inaccurate and subsequent events could result in material liabilities from such claims or litigation.

Risks related to our common stock

Common stockholders may be diluted if additional shares are issued. In order to align interests and encourage ownership, we issue restricted stock, restricted stock units and performance share units to our employees and directors as part of their compensation. In addition, we may issue additional shares of common stock, additional senior notes or other securities or debt convertible into common stock to extend maturities or fund capital expenditures, including acquisitions. The issuance of additional shares of common stock results in dilution of the interests of existing stockholders. One way to reverse the effects of dilution is by the acquisition of our stock. On December 31, 2025, our share repurchase program had $785.5 million remaining authorization. However, this program may be suspended, modified or discontinued by our board of directors at any time.

Our stock price may be volatile and stockholders may not be able to resell shares of our common stock at or above the price they paid. The price of our common stock fluctuates significantly, which may result in losses for investors. The market price of our common stock has been volatile. From January 1, 2023 to December 31, 2025, the price of our common stock reported by the New York Stock Exchange ranged from a low of $22.61 per share to a high of $43.50 per share. We expect our stock price to continue to be subject to volatility as a result of a variety of factors, including factors beyond our control. These factors include:

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most significantly, changes in natural gas, NGLs and oil prices;

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global economic conditions;

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fluctuations in the broader equity market;

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variations in drilling, recompletions, acquisitions and operating results;

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changes in governmental regulation and/or taxation;

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changes in financial estimates by securities analysts;

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changes in market valuations of comparable companies;

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expectations regarding our capital program, including any determination by our board of directors regarding repurchasing stock or paying dividends;

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changes in key personnel; or

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future sales of additional stock and changes in our capital structure.

We may fail to meet expectations of our stockholders or of securities analysts at some time in the future and our stock price could decline as a result. Payment of dividends may be limited or prevented due to the restrictions that are defined within our bank credit facility.

General risk factors

Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions. The United States government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. As a natural gas, NGLs and oil producer, we face various security threats, including:

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cybersecurity threats to gain unauthorized access to sensitive information or to render data or computer systems unusable, which may become more sophisticated with the use of artificial intelligence;

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threats to the security or operations at our physical facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; or

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threats from terrorist acts or other geopolitical events.

Digital technologies are an integral part of our business and are used to support our exploration, development and production activities and our key accounting and financial reporting functions. We use these systems to analyze and store financial and operating data and to communicate internally and with outside business counterparties. Cyberattacks could compromise our core infrastructure and digital technologies and result in disruptions to our business operations or the loss of our data and proprietary information. In addition, digital technologies control oil and gas production, processing equipment, and distribution systems globally and are necessary to deliver our production to market. A cyberattack against these operating systems, or the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets, cause accidental discharge and/or make it difficult or impossible to accurately account for production and settle transactions. A cyberattack on a vendor or a service provider could result in supply chain disruptions, which could delay or halt development projects. A cyberattack on our accounting or human resources systems could expose us to liability if confidential and/or personal information is obtained. Furthermore, the shift to a hybrid systems model including on-premises and cloud environments has transformed how

systems interconnect, how data is stored, how users interact with applications and what end user devices are utilized. This shift has resulted in additional cybersecurity risk.

Security threats have subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to harm to our employees or losses of sensitive information, losses of critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Attackers are becoming more sophisticated and both the frequency and magnitude of cyberattacks in particular are expected to increase and include, but are not limited to, malicious software, phishing, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from unauthorized disbursement of funds, remedial actions, loss of business and/or potential liability. We may be unable to anticipate, detect or prevent future attacks, particularly as methodologies utilized by attackers change frequently and are not recognized until launched. Additionally, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, which could require us to expend significant additional resources to meet such requirements. While we utilize extensive processes and procedures that we deem appropriate to counter cybersecurity risks and to date have not suffered any material losses relating to such attacks, there can be no assurance that we will not suffer such losses in the future. Any losses, costs or liabilities directly or indirectly related to cyberattacks or similar incidents may not be covered by, or may exceed the coverage limits of, any of our insurance policies.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in areas around the world and the occurrence or threat of terrorist attacks in the United States, other countries or international waters could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism and, in turn, could materially and adversely affect our business and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

We have a comprehensive approach to mitigate cybersecurity risk which primarily focuses on three key elements:

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people – security awareness education and readiness-testing throughout the year for employees;

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process – incorporating cyber awareness in our day-to-day processes which includes oversight of systems that detect and alert trained personnel of cybersecurity threats, regular review of security posture and security roadmap to ensure alignment throughout the organization, physical and digital asset protection and cybersecurity vulnerability remediation via preventable and detective measures; and

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technology – investing in industry aligned security technology and threat intelligence capabilities.

Cybersecurity governance is supported by our information technology department which includes certified security professionals and seasoned security analysts. This department conducts extensive ongoing reviews of our security initiatives to assess the current state of our program (using a cybersecurity framework) and potential evolution based on current business risks along with detection and communication of cybersecurity threats and actions to mitigate those threats. Our Director of IT Security is responsible for assessing, monitoring and managing risks from cybersecurity threats, overseeing our overall cybersecurity risk management program which includes prevention, mitigation, detection and remediation of cybersecurity incidents and supervises a team of cybersecurity personnel. Our Director of IT Security reports to our VP – Information Technology and is responsible for reporting material incidents to our Cybersecurity Risk Management Committee (“CRMC”) that includes officers charged with reporting responsibilities. Cybersecurity incidents that meet a pre-determined minimum threshold are communicated upward to executive officers to determine overall materiality and disclosure obligations. Our Director of IT Security keeps the CRMC apprised of our processes to prevent, detect, mitigate and remediate cybersecurity incidents at least annually. Our internal cybersecurity team led by our Director of IT Security has over 75 years of combined experience in information security and maintains several cybersecurity certificates.

We conduct security assessments, manage user access, perform vulnerability scanning and patching, oversee monitoring and carry out annual penetration testing, in addition to other critical security functions. In conjunction with our internal team, we utilize an independent third-party operations center that is focused on, but not limited to, monitoring alerts, logs, behavior analytics, vulnerability notifications and remediation guidance. Critical infrastructure is continuously monitored to ensure accessibility and appropriate security posture. We also perform reviews and risk analysis for third-party software and platforms which sets a standardized security baseline. We monitor known third-party breaches, known software vulnerabilities that may affect third-party vendors and communicate as necessary with those vendors, allowing us to increase security of our technology assets and our data. In addition, we perform an annual cybersecurity risk assessment of critical third-party systems.

Our board of directors oversees our cybersecurity risk and receives, at a minimum, a quarterly cybersecurity report and a biannual update from IT leadership, which includes additional discussions of any relevant issues related to the understanding of technology and cybersecurity risk that may be relevant at any given time. This report includes, among other things, information regarding our current security posture and ongoing cybersecurity events. Cybersecurity incidents meeting a pre-determined minimum threshold are communicated to our board of directors.

To date, there have been no risks from cybersecurity incidents which have materially affected, or have been reasonably likely to materially affect us, including our business strategy, results of operations or financial condition. Notwithstanding the extensive approach we take to cybersecurity, we may not be successful in preventing or mitigating a cybersecurity incident that could have a material adverse effect on us. For more information on our cybersecurity related risks, see Item 1A. Risk Factors of this Annual Report on Form 10-K.

ITEM 3. LEGAL PROCEEDINGS

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

Environmental Proceedings

From time to time, we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $250,000.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market for Common Stock

Our common stock is listed on the NYSE under the symbol "RRC." During 2025, trading volume averaged approximately 2.9 million shares per day.

Holders of Record

Pursuant to the records of our transfer agent, as of February 20, 2026, there were approximately 795 registered holders of record of our common stock.

Dividends

The payment of dividends is subject to the formal declaration by the board of directors. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of our board of directors and will depend upon, among other things, our earnings, financial condition, capital requirements, levels of indebtedness and other considerations our board of directors deems relevant. For more information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Equity Compensation Plan Information

The information required by this item is incorporated herein by reference to our 2026 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2025.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

In 2019, our board of directors authorized a common stock repurchase program. In 2022, our board of directors increased the authorization under the program. Shares repurchased as of December 31, 2025, were held as treasury stock and we have approximately $785.5 million of remaining authorization under the program. These repurchases are based on trade date, although certain repurchases may not have settled until the following month. Purchases of our common stock in fourth quarter 2025 were as follows:


Period	Total Number of Shares Purchased		Average Price Paid Per Share (a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Amount of Shares that May Yet Be Purchased Under Plans or Programs
October 2025		239,289	$	35.25		239,289	$	831,049,000
November 2025		247,400	$	37.95		247,400	$	821,659,000
December 2025		1,002,600	$	36.04		1,002,600	$	785,530,000
		1,489,289				1,489,289


(a)	Includes any fees, commissions, or other expenses associated with the share repurchases.

Stockholder Return Performance Presentation

The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the cumulative total return of Range’s common stock, the S&P Oil and Gas Exploration and Production Index, the S&P Small Cap 600 Index and a customized peer group which matches the peer group selected by our compensation committee of the board of directors which is used in our performance unit program. The graph assumes that $100 was invested in the Company’s common stock and each index on December 31, 2020 and that dividends were reinvested.


	2020		2021		2022		2023		2024		2025
Range Resources Corporation	$	100	$	266	$	375	$	462	$	551	$	545
S&P Oil & Gas Exploration & Production Index		100		167		242		251		248		243
S&P Small Cap 600 Index		100		127		106		123		134		142
2025 Self-Constructed Peer Group (a)		100		169		248		253		301		319

     (a)

     The 2025 Self-Constructed Peer Group includes the SPDR S&P Midcap 400 and the SPDR S&P Oil and Gas E&P ETF and the following thirteen companies: Antero Resources Corporation, Civitas Resources, Inc., Chord Energy Corporation, CNX Resources Corporation, Comstock Resources, Inc., Coterra Energy, Inc., EQT Corporation, Expand Energy Corporation, Magnolia Oil & Gas Corporation, Matador Resources, Murphy Oil, Ovintiv Inc. and SM Energy Company. The 2025 Self-Constructed Peer Group is a market capitalization-weighted index in which each of the six Compensation Peer Group companies with the highest percentage of dry gas reserves are included twice. The six companies included twice are Antero Resources Corporation, CNX Resources Corporation, Comstock Resources, Inc., Coterra Energy Inc., EQT Corporation and Expand Energy Corporation.

The above performance graph shall not be deemed "filed" for purposes of Section 18 Exchange Act, or otherwise subject to the liabilities under that section and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

ITEM 6. RESERVED

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

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;

•

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	%

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	)

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

RANGE RESOURCES CORP 10-K