Diversified Energy Co: Form 10-K for the period ended Dec 31, 2025

Business Overview

We are engaged in the production, transportation, and marketing of natural gas, NGLs, and oil, managing a diversified portfolio of

mature, long-life assets. Our assets are located in the United States within the following geographical operating areas:

• Appalachian Region, which spans Ohio, Pennsylvania, Virginia, West Virginia, Kentucky, Tennessee and Alabama;
• Central Region, which includes Texas, Oklahoma, New Mexico, Louisiana and Arkansas;
• Other, which includes Florida and Wyoming.

Our business model emphasizes responsible stewardship and operational excellence, focusing on maximizing value from existing

reserves.

Our disciplined, full-lifecycle asset management approach is central to our success. We focus on optimizing and extending the

productive life of existing wells, using advanced monitoring technologies and data analytics to drive operational efficiency and safety.

In addition to our work on our producing wells, we have an extensive and innovative asset retirement program that consists of a

vertically integrated plugging company based in our Appalachian Region. With over 69,000 total net productive wells, we produced

an annual average of 1,086 MMcfepd during the year ended December 31, 2025, and we are well-positioned to maximize asset value

while maintaining a sound balance sheet and upholding high standards for safety and environmental responsibility.

Our strategy is designed to deliver consistent shareholder returns and long-term value through disciplined growth and operational

excellence.

• We maintain a diversified asset base that supports stable and predictable production.
• Our efficient capital investment process enables us to pursue growth opportunities and optimize returns.
• Operational reliability is enhanced by robust infrastructure and a focus on preventative maintenance.
• We execute a disciplined commodity hedging program that is designed to mitigate price volatility.
• Our experienced leadership team drives disciplined execution and strategic decision-making.
• We have a proven track record of integrating new assets efficiently and realizing operational synergies.

2025 Highlights

• Average daily production of 1,086 MMcfepd representing an increase of 37% when compared to 791 MMcfepd for the same

period in 2024;

• In November 2025, we acquired Canvas Energy Inc. (“Canvas”) for total consideration of approximately $533 million. The

transaction was funded through the issuance of 3,718,209 shares of common stock and approximately $399 million in cash. The

cash portion of the consideration was primarily funded through the issuance of the ABS XI Notes with a total principal amount of

$400 million. The ABS XI Notes are secured by certain upstream producing assets acquired in the Canvas acquisition;

• In November 2025, we completed the U.S. Domestication, resulting in Diversified Energy Company, a Delaware corporation,

becoming our publicly traded parent company;

• In October 2025, we launched a well plugging fund with the state of West Virginia dedicated to retiring oil and gas wells. Over

the initial 20 year period of the agreement, we plan to invest $70 million, which is held and guaranteed by OneNexus, an

insurance provider for asset retirement obligations, to ensure we have provided financial assurance so that all of our wells in the

state are safely retired. The State of West Virginia is a third party beneficiary of the plugging fund;

• In April 2025, we issued $300 million of new senior secured notes in the Nordic bond market at a 2% discount, resulting in net

proceeds of $294 million (the “Nordic Bonds”);

• In March 2025, we acquired Maverick Natural Resources, LLC (“Maverick”) for net consideration of $666 million. The gross

value of the transaction was approximately $1.3 billion and was funded through the issuance of 21,194,213 shares of common

stock direct to the unitholders of Maverick, and approximately $211 million in cash. The transaction also included the assumption

of approximately $518 million of ABS Maverick Notes outstanding and the payoff of $202 million outstanding on Maverick’s

credit facility on the acquisition date;

• In March 2025, concurrent with the Maverick acquisition, we amended and restated the credit agreement governing our revolving

loan facility (the “Credit Facility”), increasing the borrowing base to $900 million and extending the maturity to March 2029.

During our semi-annual redetermination in October 2025, the borrowing base was reduced to $825 million;

• In February 2025, we formed Diversified ABS Phase X LLC, a limited-purpose, bankruptcy-remote, wholly-owned subsidiary

(“ABS X”), to issue asset-backed securities with a total principal amount of $530 million (the “ABS X Notes”);

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• In February 2025 , we issued 8,500,000 shares of common stock at $14.50 per share to raise gross proceeds of $123 million;
• In February 2025, we acquired certain upstream assets and related infrastructure in the Appalachian Region from Summit Natural

Resources, LLC (“Summit”) for $42 million; and

• In 2025, we divested certain non-core undeveloped acreage across our operating footprint for consideration of approximately

$160 million.

Refer to Notes 3, 11, and 15 in the Notes to the Consolidated Financial Statements for additional information regarding acquisitions,

common stock, and debt.

Geographical Operating Areas

Our operations are primarily concentrated within the Appalachian and Central regions of the United States. Our Appalachian Region

spans Pennsylvania, Ohio, Virginia, West Virginia, Kentucky, Tennessee and Alabama and consists of multiple productive, shallow

conventional formations and two productive, deeper unconventional shale formations, the Marcellus Shale and the slightly deeper

Utica Shale. Our Central Region consists of the Bossier and Haynesville shale formations and the Cotton Valley sandstones in East

Texas and West Louisiana, the Barnett Shale in North Texas and the Mid-Continent producing areas across Central Texas, along with

the Anadarko Basin across North Texas and Oklahoma and Permian Basin in West Texas and New Mexico.

Reserve Data

Summary of Reserves

The following table sets forth summary information with respect to our estimated proved reserves, standardized measure of discounted

future net cash flows (“Standardized Measure”) and PV-10 as of December 31, 2025. Our estimated proved reserves were prepared by

Netherland, Sewell & Associates, Inc. (“NSAI”), our independent third-party reserve engineers. A copy of the reserve report is

included as an exhibit to this Annual Report on Form 10-K. We used SEC pricing in the calculation of our estimated proved reserves

and PV-10.

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(a) The basis for converting oil and NGL volumes (MBbls) to natural gas equivalent volumes (MMcfe) is determined by using the

ratio of one Bbl of oil or NGLs to six Mcf of natural gas.

(b) Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in

accordance with SEC guidance. For natural gas, NGLs, and oil volumes, the average Henry Hub spot price and WTI price were

adjusted for gravity, quality, local conditions, gathering and transportation fees, and distance from market. All prices are held

constant throughout the lives of the properties.

(c) The PV-10 of our proved reserves were prepared without giving effect to taxes or hedges. PV-10 is a non-GAAP financial

measure and generally differs from Standardized Measure, the most directly comparable GAAP measure, because it does not

include the effects of income taxes on future net cash flows. We believe that the presentation of PV-10 is relevant and useful to our

investors as supplemental disclosure to the Standardized Measure because it presents the discounted future net cash flows

attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. While the

Standardized Measure is free cash dependent on the unique tax situation of each company, PV-10 is based on a pricing

methodology and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry

and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis.

Investors should be cautioned that neither PV-10 nor the Standardized Measure represents an estimate of the fair market value of

our proved reserves.

Reconciliation of Standardized Measure (GAAP) to PV-10 (Non-GAAP)

(in thousands)

Proved Reserves

As of December 31, 2025, our estimated proved reserves totaled 6,082,483 MMcfe, an increase of 68% from the prior year-end, with a

Standardized Measure of $4.2 billion. Natural gas constituted approximately 73% of our total estimated proved reserves and 74% of

our total estimated proved developed reserves. The following table provides a summary of the changes in our proved reserves during

the year ended December 31, 2025.

(a) The basis for converting oil and NGL volumes (MBbls) to natural gas equivalent volumes (MMcfe) is determined by using the

ratio of one Bbl of oil or NGLs to six Mcf of natural gas.

Revisions to Previous Estimates

During 2025, we recorded 793,516 MMcfe in revisions to previous estimates. The upward revisions were primarily associated with

changes in the trailing 12-month average realized Henry Hub first day of the month spot price, which increased approximately 59% as

compared to December 31, 2024.

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Purchase of Reserves in Place

During 2025, 2,041,296 MMcfe of purchases of reserves in place were associated with the Summit, Maverick, and Canvas

acquisitions. Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional information about acquisitions and

divestitures.

Proved Undeveloped Reserves (“PUDs”)

We aim to obtain proved developed producing wells through acquisitions in accordance with our growth strategy rather than through

development activities. We accordingly contribute limited capital to development activities. From time to time, when acquiring

packages of wells, we also acquire certain locations that are in development by the acquiree at the time of the acquisition or could be

developed in the future. When economic, we may engage third parties to complete the existing development activities or may

participate in the development of acquired non-operated locations, and such reserves are included below as PUDs. As of December 31,

2025, we are actively engaged or have plans to engage in developing certain locations acquired in the Maverick and Canvas

acquisitions. Therefore, we have classified these undrilled locations as PUDs.

The following table summarizes the changes in our estimated PUDs during the year ended December 31, 2025:

Purchase of Reserves in Place

During 2025, there were 365,634 MMcfe of purchases of PUDs in place related to the Maverick and Canvas acquisitions. Refer to

Note 3 in the Notes to the Consolidated Financial Statements for additional information about acquisitions and divestitures.

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2025 included in this Annual Report on Form 10-K were prepared by our independent

reserves auditors, Netherland, Sewell & Associates, Inc. (“NSAI”), in accordance with petroleum engineering and evaluation

standards published by The Petroleum Resources Management System jointly sponsored by the Society of Petroleum Engineers, the

World Petroleum Council, the American Association of Petroleum Geologists and the Society of Petroleum Evaluation Engineers.

These estimates have been prepared in accordance with the definitions and regulations of the SEC.

Our internal staff of petroleum engineers and geoscience professionals work diligently to ensure the integrity, accuracy and timeliness

of data furnished to our independent reserves auditors for their reserve evaluation process. Our technical team regularly meets with the

independent reserves auditors to review properties and discuss methods and assumptions used to prepare reserve estimates. The

reserve estimates and related reports are reviewed and approved by our Vice President of Reservoir Engineering. The Vice President

of Reservoir Engineering holds a Bachelor of Science in Petroleum Engineering and has been with the Company since 2018 with 27

years of experience in petroleum engineering and over 24 years of experience evaluating natural gas and oil reserves. Prior to joining

the Company in 2018, our Vice President of Reservoir Engineering, who is an active member of the Society of Petroleum Engineers,

served in various reservoir engineering roles for public companies engaged in exploration and production operations.

Estimation of Proved Reserves

Proved reserves are quantities of natural gas or oil which, by analysis of geoscience and engineering data, can be estimated with

reasonable certainty to be commercially recoverable from known reservoirs under existing economic and operating conditions. The

term “reasonable certainty” implies a high degree of confidence that the quantities of natural gas or oil actually recovered will equal or

exceed the estimate. To achieve reasonable certainty, DEC and the independent reserves auditors employed technologies that have

been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of

our proved reserves may include, but are not limited to, well logs, geologic maps and available downhole and production data, and

well-test data.

Reserves engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and

natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available

data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the

results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the

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quantities of natural gas, NGLs and oil that are ultimately recovered. Estimates of economically recoverable natural gas, NGLs and oil

and of future net cash flows are based on a number of variables and assumptions, all of which may vary from actual results, including

geologic interpretation, prices and future production rates and costs. See Item 1A. Risk Factors for additional information.

Developed and Undeveloped Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an

interest as of December 31, 2025. Developed acres are acres spaced or assigned to productive wells and do not include undrilled

acreage held by production under the terms of the lease. Undeveloped acres are acres on which wells have not been drilled or

completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such

acreage contains proved reserves. Approximately 99.5% of our acreage was held by production at December 31, 2025.

(a) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a

working interest is owned.

(b) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of

net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

The undeveloped acreage numbers presented in the table above have been compiled using best efforts to review and determine acreage

that is not currently drilled but may be available for drilling at the current time under certain circumstances. Whether or not undrilled

acreage may be drilled and thereafter produce economic quantities of oil or gas is related to many factors which may change over

time, including natural gas and oil prices, service vendor availability, regulatory regimes, midstream markets, end user demand, and

macro and micro financial conditions; the undeveloped acreage described herein is presented without an opinion as to economic

viability, as a result of the aforesaid factors. Additionally, it is noted that certain formations on a land tract may be already developed

while other formations are undeveloped.

The following table sets forth the number of total gross and net undeveloped acres as of December 31, 2025 that will expire in 2026,

2027 and 2028 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless

such acreage is extended or renewed.

Our primary focus is to operate our existing producing assets safely, efficiently and responsibly. However we also evaluate areas

nearing lease expiration for potential development opportunities when it is prudent to do so.

Productive Wells

Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross

wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of

our fractional working interest owned in gross wells. The following table summarizes our productive natural gas and oil wells as of

December 31, 2025.

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Exploratory and Development Drilling Activities

Information regarding our drilling and development activities for the year ended December 31, 2025 is set forth below:

We drilled no exploratory wells (productive or dry) during the years ended December 31, 2025, 2024 and 2023.

During 2023, we completed the development of two of the seven Appalachian wells that were under development as of December 31,

2022. The remaining five Appalachian wells were divested in connection with the sale of 80% of the equity interest in DP Lion Equity

Holdco LLC in December 2023. On March 1, 2023, we also completed the Tanos II acquisition, which included five wells in the

Central Region that were under development at the date of acquisition. During 2023, we completed one of these five wells. Four

Central Region development wells remained in progress as of December 31, 2023.

During 2024, we completed the development of the four remaining wells acquired in the Tanos II acquisition that had been under

development as of December 31, 2023. As of December 31, 2024, we had zero development wells in progress.

In March 2025, we completed the Maverick acquisition, which included 71 wells that were under development at the time of purchase.

During 2025, through a joint development agreement with an experienced development company, we brought 57 of these wells to

completion. In addition, we completed two wells located adjacent to the Maverick acquisition wells. As of December 31, 2025, 14

development wells from the acquisition remained in progress.

Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional information regarding the acquisitions and

divestitures.

Production Volumes, Average Sales Prices and Operating Costs

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Significant Fields

We operate in three primary producing areas:

(i) Appalachian Region, covering Pennsylvania, Ohio, Virginia, West Virginia, Kentucky, Tennessee, and Alabama;

(ii) Central Region, covering Oklahoma, Texas, New Mexico, Louisiana, and Arkansas; and

(iii) Other, includes Florida and Wyoming.

The following tables present production volumes, realized prices, and per-unit operating costs for our significant fields that account for

15% or more of our total proved reserves. Both the Appalachian Region and the Mid-Continent field, which is one of four separate

fields within the Central Region, meet the criteria for significance.

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(a) Processing fees of approximately $0.85-$1.25 per Mcfe are classified as revenue deductions as opposed to operating expenses.

Delivery Commitments

We have contractually agreed to deliver firm quantities of natural gas to various customers, which we expect to fulfill with production

from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet these

commitments. The following table summarizes our total gross commitments, compiled using best estimates based on our sales

strategy, as of December 31, 2025.

Transportation and Marketing

Diversified Energy Marketing, LLC, our wholly owned marketing subsidiary, focuses on commodity marketing, asset optimization,

producer services and strategic management of our transportation portfolio. The focus of our marketing team is to enhance operational

efficiency and profitability by leveraging market insights, operational expertise and strategic asset management to ensure reliable flow

of our products to attractive available markets.

We offer a comprehensive suite of services, including the marketing of natural gas, NGL’s and oil, risk management, logistical

support and strategic transportation management. This approach maximizes market presence, financial outcomes and consistent

product flow, capitalizing on our transportation infrastructure and vertically integrated midstream systems. Our midstream

infrastructure and strategic arrangements provide access to high-demand markets, particularly in the U.S. Gulf Coast, while utilizing

low-cost transportation in Appalachia. This synergy with our asset profile provides advantageous pricing and flow assurance

supported by strategic firm transportation agreements. As of December 31, 2025, our transportation arrangements provide access to

375 MMcfepd of takeaway capacity.

As a dedicated arm of DEC, our marketing team aligns closely with our broader goals of optimizing free cash flow generation. With

experienced professionals and a deep understanding of the energy market, we are committed to delivering value and reliability to our

stakeholders, navigating industry complexities to achieve operational excellence.

Competition

The natural gas and oil industry is highly competitive, and we compete with other companies in all aspects of our business to acquire,

operate, and market our production. Operating conditions may be affected by future legislation and regulations as the United States

regulatory environment modernizes. In addition, some of our competitors may have a competitive advantage when responding to

factors that affect demand for natural gas and oil production, such as changing prices, domestic and foreign political conditions,

weather conditions, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic

conditions. Our industry and our company can also be impacted by alternative energy sources, including wind, solar, and electric

power. Our ability to acquire properties in the future will depend on our ability to evaluate and select suitable properties and to finalize

transactions in a highly competitive environment.

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Major Customers

Our production is generally sold on month-to-month contracts at prevailing market prices.

During the years ended December 31, 2025, 2024 and 2023, no customers individually comprised more than 10% of total revenues.

Given the availability of alternative purchasers for oil and natural gas, we believe that losing any single purchaser would not

materially impact our ability to sell future production. To mitigate potential credit risk, we may occasionally require customers to

provide financial security.

Seasonality

Demand for natural gas typically decreases in spring and fall, and increases in summer and winter. However, seasonal anomalies and

consumer procurement initiatives can mitigate these fluctuations. Seasonal anomalies can also heighten competition for equipment,

supplies, and personnel, potentially causing shortages, increased costs or, operational delays.

Title to Properties

We believe we hold satisfactory title to our active properties, adhering to industry standards. Our properties are subject to customary

royalties, contracts, consents, preferential purchase rights, tax liens, laws and other encumbrances, which we believe do not materially

affect their use or value. Before acquiring producing wells, we conduct title investigations consistent with industry standards. For

properties we operate, we address significant title defects as needed. We believe our title reviews are reasonable and protective for a

representative cross-section of our wells.

Human Capital Resources

As of December 31, 2025, the Company employed 1,987 full-time individuals across 23 U.S. states. Our employees are fundamental

to the execution of our operational strategy, and we focus on maintaining robust operating standards with an emphasis on EHS

practices to promote the well‑being of our workforce and the communities in which we operate.

We are committed to fostering an inclusive work environment and making recruitment, development, and promotion decisions based

solely on merit, qualifications, and business needs. We are an equal opportunity employer and do not discriminate against legally

protected classes. Employees have access to a confidential, externally managed whistleblower hotline and a compliance website that

enables direct reporting of concerns to senior leadership.

Our employees are our most important asset. We invest in employee engagement and development through regular communication,

site visits, structured feedback mechanisms, and regular training. We offer a comprehensive compensation package with base pay,

discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan

and an affordable and comprehensive health insurance program, among other benefits. In 2025, our CEO and senior leadership team

met directly with approximately 950 employees through our “Winning Language” town halls. Additionally, the Company conducted

its annual Employee Engagement Survey, which received an 80% participation rate from the 1,922 surveys distributed. The survey

assesses organizational alignment, communication effectiveness, leadership, and overall employee engagement. Results from our

Employee Engagement Survey will be used to inform our human capital initiatives and priorities for 2026.

We offer a comprehensive suite of employee benefits designed to support physical, mental, and financial well‑being. In 2025, we

expanded our benefits program to include paid adoption assistance and launched an integrated wellness platform that provides

individualized tools for health tracking, fitness goal setting, and preventive care. Our financial wellness resources include bi‑monthly

educational seminars and complimentary one‑on‑one consultations through our third‑party investment advisors. Participation in the

Company’s 401(k) retirement savings plan reached 93% in 2025, with the Company providing a dollar‑for‑dollar match on employee

contributions up to 7%. Employees also have access to the Company’s Employee Stock Purchase Plan, which allows participants to

purchase Company stock at a discounted rate.

The Company is committed to supporting the communities in which we operate. In 2025, we contributed approximately $1.8 million

to local organizations, programs, and initiatives focused on health, education, student athletics, public safety, and municipal services.

Our community impact efforts included distributing winter coats and shoes to more than 4,240 children and providing support to foster

care organizations. Our Community Relations Committee oversees these initiatives and promotes employee volunteerism throughout

our operating areas. We remain committed to maintaining a safe, inclusive workplace and to positively contributing to the

communities we serve.

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Government Regulation

General

Our operations in the United States are subject to various U.S. federal, state and local (including county and municipal level) laws and

regulations. These laws and regulations cover virtually every aspect of our operations including, among other things: use of public

roads; construction of well pads, impoundments, tanks and roads; pooling and unitizations; water withdrawal and procurement for well

stimulation purposes; wastewater discharge, well drilling, casing and hydraulic fracturing; stormwater management; well production;

well plugging; venting or flaring of natural gas; pipeline construction and the compression and transportation of natural gas and

liquids; reclamation and restoration of properties after natural gas and oil operations are completed; handling, storage, transportation

and disposal of materials used or generated by natural gas and oil operations; the calculation, reporting and payment of taxes on

natural gas and oil production; and gathering of natural gas production. Various governmental permits, authorizations and approvals

under these laws and regulations are required for exploration and production as well as midstream operations. These laws and

regulations, and the permits, authorizations and approvals issued pursuant to such laws and regulations are intended to protect, among

other things: air quality; ground water and surface water resources, including drinking water supplies; wetlands; waterways; protected

plants and animal species; natural resources; and the health and safety of our employees and the communities in which we operate.

We endeavor to conduct our operations in compliance with all applicable U.S. federal, state and local laws and regulations. However,

because of extensive and comprehensive regulatory requirements against a backdrop of variable geologic and seasonal conditions,

non-compliance during operations can occur. Certain non-compliance may result in fines or penalties, but depending on the nature of

the non-compliance could also result in civil or criminal enforcement actions, additional restrictions on our operations, or make it

more difficult for us to obtain necessary permits in the future. The possibility exists that new laws or regulations may be adopted

which could have a significant impact on our operations or on our customers’ ability to use our natural gas, natural gas liquids and oil,

and may require us or our customers to change their operations significantly or incur substantial costs.

Environmental Laws

Many of the U.S. laws and regulations vary according to the jurisdiction in which we conduct our operations. In addition to state or

local laws and regulations, our operations are also subject to numerous federal environmental laws and regulations. Below is a

discussion of some of the more significant federal laws and regulations applicable to our operations.

Clean Air Act

The federal Clean Air Act and associated federal and state regulations regulate air emissions through permitting and/or emissions

control requirements. These regulations affect the entire value chain from oil and natural gas production, to gathering, to processing, to

transmission and storage, and then to distribution operations. Various equipment and activities in our assets are subject to regulation,

including compressors, engines, dehydrators, storage tanks, pneumatic devices, fugitive components, and blowdowns. We obtain

permits, typically from state or local authorities, or document exemptions necessary to authorize these activities. Further, we are

required to obtain pre-approval for construction or modification of certain facilities, and/or to use specific equipment, technologies or

best management practices to control emissions. Some states also require a separate operating permit to be obtained for on-going

operations.

Federal and state governmental agencies continue to review and revise the air quality regulations affecting oil and natural gas

activities, and expanded regulations could increase our cost or otherwise affect our ability to produce.

Clean Water Act

The federal Clean Water Act (“CWA”) and corresponding state laws affect our operations by regulating storm water or other

discharges of substances, including pollutants, sediment, and spills and releases of oil, brine and other substances, into surface waters,

and in certain instances imposing requirements to dispose of produced wastes and other oil and gas wastes at approved disposal

facilities. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by

the EPA, the U.S. Army Corps of Engineers, or a delegated state agency. These permits require regular monitoring and compliance

with effluent limitations, and include reporting requirements. Federal and state regulatory agencies can impose administrative, civil

and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and

regulations.

Endangered Species and Migratory Birds

The Endangered Species Act and related state laws and regulations protect plant and animal species that are threatened or endangered.

The Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act provide similar protections to migratory birds and bald

and golden eagles, respectively. Some of our operations are located in areas that are or may be designated as protected habitats for

endangered or threatened species, or in areas where migratory birds or bald and golden eagles are known to exist. Laws and

regulations intended to protect threatened and endangered species, migratory birds, or bald and golden eagles could have a seasonal

impact on our construction activities and operations. New or additional species that may be identified as requiring protection or

consideration could also lead to delays in obtaining permits and/or other restrictions, including operational restrictions.

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Safety of Gas Transmission and Gathering Pipelines

Natural gas pipelines serving our operations are subject to regulation by the U.S. Department of Transportation’s Pipeline and

Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), as

amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety

Improvement Act of 2002 (“PSIA”), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and the 2011 Pipeline

Safety Act. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline

facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence

areas. Additionally, certain states, such as West Virginia, also maintain jurisdiction over intrastate natural gas lines. PHMSA has over

the years finalized rules that, collectively, impose additional safety requirements on natural gas transmission pipelines and certain

onshore gas gathering pipelines.

The adoption of laws or regulations that apply more comprehensive or stringent safety standards can increase the expenses we incur

for gathering service.

Resource Conservation and Recovery Act

The Federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws and regulations impose requirements

for the management, treatment, storage and disposal of hazardous and non-hazardous wastes, including wastes generated by our

operations. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production

of natural gas and oil are currently regulated under RCRA’s solid (non-hazardous) waste provisions. Future changes in the law could

result in the reclassification of certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make

such wastes subject to much more stringent handling, disposal and clean-up requirements. A change in the RCRA exclusion for

drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes,

which could have a material adverse effect on the industry as well as on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or “Superfund”) imposes joint and

several liability for costs of investigation and remediation, and for natural resource damages without regard to fault or the legality of

the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under

CERCLA as hazardous substances. These classes of persons, called potentially responsible parties (“PRP”), include the current and

past owners or operators of a site where the release occurred and anyone who disposed, transported, or arranged for the disposal,

transportation, or treatment of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third

parties to take actions in response to threats to public health or the environment, and to seek to recover from PRPs for the costs of such

action. Many states, including states in which we operate, have adopted comparable state statutes.

Although CERCLA generally exempts “petroleum” from regulation, in the course of our operations we have generated and will

generate wastes that may fall within CERCLA’s definition of hazardous substances, and may have disposed of these wastes at disposal

sites owned and operated by others. We may also be the owner or operator of sites on which hazardous substances have been released.

In the event contamination is discovered at a site on which we are or have been an owner or operator, or to which we have sent

hazardous substances, we could be jointly and severally liable for the costs of investigation and remediation, and for natural resource

damages. Further, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and

property damage allegedly caused by hazardous substances or other pollutants released into the environment.

Oil Pollution Act

The primary federal law related to oil spill liability is the Oil Pollution Act (“OPA”), which amends and augments oil spill provisions

of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and

damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. A liable “responsible party”

includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of

discharge. The OPA assigns joint and several liability, without regard to fault, to each responsible party for oil removal costs and a

variety of public and private damages. Although defenses exist to the liability imposed by the OPA, they are limited. In the event of an

oil discharge or substantial threat of discharge, we may be liable for costs and damages.

Regulation of the Sale and Transportation of Natural Gas, NGLs and Oil

The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory

Commission (“FERC”) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and regulations issued under those

statutes. FERC regulates interstate natural gas transportation rates, and the terms and conditions of service, which affects the

marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. FERC regulations require that

rates, terms and conditions of service for interstate service pipelines that transport crude oil and refined products and certain other

liquids be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC

regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their

interstate transportation rates, terms and conditions of service.

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Section 1(b) of the Natural Gas Act exempts from regulation by FERC facilities used for the production and gathering of natural gas.

However, the distinction between federally unregulated gathering facilities and FERC regulated transmission facilities is a fact-based

determination, and the classification of facilities has recently been the subject of regulatory dispute. We own certain natural gas

pipeline facilities that we believe meet the traditional tests FERC has used to establish a pipeline’s primary function as “gathering,”

thus exempting it from the jurisdiction of FERC under the Natural Gas Act.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of

natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services

varies from state to state. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects

the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

FERC regulates the rates and terms and conditions of service for transportation of oil and NGLs on interstate pipelines under the

provisions of the Interstate Commerce Act, the Energy Policy Act of 1992 and amendments to and regulations issued under those

statutes. Intrastate transportation of oil, NGLs and other products is dependent on pipelines whose rates, terms and conditions of

service are subject to regulation by state regulatory bodies under state statutes.

The price of natural gas, NGLs, and crude oil are currently not directly regulated, but Congress historically has been active in the area

of natural gas, NGLs and crude oil regulation. We cannot predict whether new legislation to regulate sales and commodity prices

might be enacted in the future or what effect, if any, such legislation might have on our operations.

Health and Safety Laws

Our operations are subject to regulation under the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws in

some states, all of which regulate health and safety of employees at our operations. Additionally, OSHA’s hazardous communication

standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act,

and comparable state laws require that information be maintained about hazardous materials used or produced by our operations and

that this information be provided to employees, state and local governments and the public.

Emissions Laws and Regulations

There are a number of proposed and recently-enacted laws and regulations at the international, federal, state, regional and local level

that seek to limit or require disclosure regarding greenhouse gas emissions (“GHG”) and other climate-related matters. Such laws and

regulations could increase our costs, including requirements that necessitate the installation of new equipment or the purchase of

emission allowances. These laws and regulations could also impact our customers, including the electric generation industry, making

alternative sources of energy more competitive and thereby decreasing demand for the natural gas and oil we produce. Additional

regulation could also lead to permitting delays and additional monitoring and administrative requirements, in turn impacting electricity

generating operations.

At the international level, the UN-sponsored “Paris Agreement,” for nations to limit their GHG emissions through non-binding,

individually-determined reduction goals every five years after 2020. In November 2021, the international community gathered in

Glasgow at the 26th Conference of the Parties to the UN Framework Convention on Climate Change, during which multiple

announcements were made, including a call for parties to eliminate certain natural gas and oil subsidies and pursue further action on

non-carbon dioxide GHGs. In a related gesture, the United States and the European Union jointly announced the launch of the “Global

Methane Pledge,” which aims to cut global methane pollution by at least 30% by 2030 relative to 2020 levels, including “all feasible

reductions” in the energy sector. Such commitments were re-affirmed at the 27th Conference of the Parties in Sharm El Sheikh.

However, on January 2025, President Trump issued an Executive Order directing the U.S. Ambassador to the United Nations to

withdraw from the Paris Agreement. Accordingly, the UN Secretary General issued a depositary notification of the U.S. withdrawal

from the Paris Agreement, effective January 27, 2026. More recently, in February 2026, the U.S. Environmental Protection Agency

finalized a regulation rescinding its prior finding that certain GHG emissions endangered public health and welfare, which had served

as the basis for certain GHG emission regulation by the agency. This and other changes undertaken by the Trump Administration have

or may in the future reverse or rescind climate-related initiatives and regulations and focus on driving increased U.S. energy

production. In response, several U.S. states separately expressed their commitment to the Paris Agreement and its goals, while others

have pursed emissions reporting regulations. Although it is not possible at this time to predict how legislation or new regulations that

may be adopted pursuant to the Paris Agreement to address GHG emissions, including state emission reduction targets or reporting,

would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs

from, our equipment and operations could require us to incur costs to implement such measures associated with our operations.

In addition, activists that are not supportive of our energy producing products have directed their attention at sources of funding for

energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their

investment in natural gas and oil activities. Ultimately, this could make it more difficult to secure funding for exploration and

production activities. Litigation risks are also a potential concern, as a number of cities and other local governments have sought to

bring suits against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other

things, that such companies created public nuisances by producing fuels that contributed to global weather events, and therefore are

responsible for roadway and infrastructure and other damages, or alleging that the companies have been aware of the unsubstantiated

effects of weather pattern changes for some time.

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Available Information

Our corporate office is located at 1600 Corporate Drive, Birmingham, Alabama 35242, and our telephone number at that location is

(205) 408-0909. Our website address is www.div.energy (http://www.div.energy). The information contained on our website is not incorporated by reference

into this Annual Report on Form 10-K and should not be considered part of this report.

We make available, free of charge, through our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current

reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange

Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and

Exchange Commission (“SEC”). The SEC maintains an internet site that contains reports, proxy and information statements, and other

information regarding issuers that file electronically with the SEC at www.sec.gov (http://www.sec.gov) (Commission File Number: 001-41870).

Required UK Regulatory Disclosures

As required as a result of our membership on the London Stock Exchange, we make the following disclosures:

Board Composition

The Board’s composition prioritizes a broad range of perspectives, emphasizing relevant professional experience and industry

knowledge aligned with our strategic objectives.

As required to be presented in accordance with UK Listing Rule 14.3.30R, as of December 31, 2025, the Board’s composition did not

align with the UK Listing Rules’ numerical targets relating to gender and ethnic representation. At that date, women comprised 17%

of the Board, no woman held a senior Board position (defined as Chief Executive Officer, Senior Independent Director, Chair of

Board, or Chief Financial Officer; although it is noted that a woman chaired two of the Company’s committees), and there was no

director from a minority ethnic background.

Board and Executive Management Composition

As required to be presented in accordance with UK Listing Rule 14.3.30R(2) as of December 31, 2025:

(a) Data reported on the basis of gender identity.

The Board’s Directors are from the U.S. as well as the UK, bringing a range of domestic and international experience to the Board.

The Board’s diverse range of experience and expertise covers not only a wealth of experience of operating in the natural gas and oil

industry but also extensive technical, operational, financial, legal and environmental expertise.

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Other Regulatory UK Disclosures

As a company admitted to listing on the Equity Shares (International Commercial Companies Secondary Listing) category of the

Official List of the Financial Conduct Authority and to trading on the Main Market of the London Stock Exchange, the Company is

required to make certain disclosures under the U.K. Listing Rules (the “UKLRs”) and the Disclosure, Guidance and Transparency

Rules (the “DTRs”).

Set out below are details of where such disclosures can be found:

• As required under DTR 7.2, the Company’s Corporate Governance Statement is available on its website at https://

www.div.energy/about-us/corporate-governance/ (http://www.div.energy/about-us/corporate-governance/);

• As required under UKLR 14.3.30R, the UK Board Diversity Statement and associated numerical data can be found in the

Board and Executive Management Composition section herein;

• In accordance with UKLR 14.3.24R, the Company will include in its 2025 Sustainability Report weather-related disclosures

consistent with the four recommendations and the eleven recommended disclosures set out in Figure 4 of Section C of the

report entitled “Recommendations of the Task Force on Climate-related Financial Disclosures” published in June 2017 by the

Task Force on Climate-related Financial Disclosures. For ease of review and given the detailed and technical content of these

disclosures, the Company considered the 2025 Sustainability Report to be the most appropriate location for the disclosures.

• The 2025 Sustainability Report provides an overview of our commitments to responsible conduct and sustainable business

practices, as well as our sustainability priorities. It will be made available on our website; and

• As required under DTR 4.1.12R, each member of the Board of Directors of the Company confirms that to the best of their

knowledge:

(a) The consolidated financial statements, prepared in accordance with U.S. GAAP, give a true and fair view of the

assets, liabilities, financial position and profit or loss of the Company and its wholly-owned subsidiaries taken as a

whole; and

(b) Management’s discussion and analysis of financial condition and results of operations includes a fair review of the

development and performance of the business and the position of the Company and its wholly-owned subsidiaries

taken as a whole, together with a description of the risks and uncertainties that they face.

You should carefully consider the risks described below, together with all of the other information in this Annual Report on Form 10-

K. The risks and uncertainties below are not the only ones we face. Additional risks and uncertainties not presently known to us or that

we believe to be immaterial may also adversely affect our business. If any of the following risks occur, our business, financial

condition, and results of operations could be seriously harmed and you could lose all or part of your investment. This Annual Report

on Form 10-K also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially

from those anticipated in these forward-looking statements as a result of various factors, including the risks described below and

elsewhere in this Annual Report on Form 10-K.

Summary of Risk Factors

We are subject to a variety of risks and uncertainties which could have a material adverse effect on our business, financial condition,

and results of operations. The summary below is not exhaustive and is qualified by reference to the full set of risk factors set forth in

this “Risk Factors” section.

• Volatility and future changes in natural gas, NGLs and oil prices could materially and adversely affect our business, results of

operations, financial condition, cash flows or prospects.

• We face production risks and hazards that may affect our ability to produce natural gas, NGLs and oil at expected levels, quality

and costs that may result in additional liabilities to us.

• The levels of our natural gas and oil reserves and resources and their quality and production volumes may be lower than estimated

or expected.

• PV-10 will not necessarily be the same as the current market value of our estimated natural gas, NGL and oil reserves.
• We may face unanticipated increased or incremental costs in connection with decommissioning obligations such as plugging.
• We may not be able to keep pace with technological developments in our industry or be able to implement them effectively.
• Deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide

financial downturn, or negative credit market conditions could have a material adverse effect on our liquidity, results of

operations, business and financial condition that we cannot predict.

• Our operations are subject to a series of risks relating to weather events.
• We rely on third-party infrastructure that we do not control and/or are subject to tariff charges that we do not control.

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• Failure by us, our contractors or our primary offtakers to obtain access to necessary equipment and transportation systems could

materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

• A proportion of our equipment has substantial prior use and significant expenditure may be required to maintain operability and

operations integrity.

• We depend on our directors, key members of management, independent experts, and technical and operational service providers

and on our ability to retain and hire such persons to effectively manage our growing business.

• We may face unanticipated water and other waste disposal costs.
• We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
• Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability to

enter into future debt financing.

• There are risks inherent in our acquisitions of natural gas and oil assets.
• We may not have good title to all our assets and licenses.
• Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
• The securitizations of our limited purpose, bankruptcy-remote, wholly owned subsidiaries may expose us to financing and other

risks, and there can be no assurance that we will be able to access the securitization market in the future, which may require us to

seek more costly financing.

• We are subject to regulation and liability under environmental, health and safety regulations, the violation of which may affect our

financial condition and operations.

• Our operations are dependent on our compliance with obligations under permits, licenses, contracts and field development plans.
• Our internal systems and website may be subject to intentional and unintentional disruption, and our confidential information may

be misappropriated, stolen or misused, which could adversely impact our reputation and future sales.

• Our operations are subject to the risk of litigation.
• Failure to comply with requirements to design, implement and maintain effective internal control over financial reporting could

have a material adverse effect on our business.

• We are subject to certain tax risks, including changes in tax legislation in the United States.

Risks Related to Our Business, Operations and Industry

Volatility and future changes in natural gas, NGLs and oil prices could materially and adversely affect our business, results of

operations, financial condition, cash flows or prospects.

Our business, results of operations, financial condition, cash flows or prospects depend substantially upon prevailing natural gas, NGL

and oil prices, which may be adversely impacted by unfavorable global, regional and national macroeconomic conditions, including

but not limited to instability related to the military conflicts in Ukraine and the Middle East. Natural gas, NGLs and oil are

commodities for which prices are determined based on global and regional demand, supply and other factors, all of which are beyond

our control.

Historically, prices for natural gas, NGLs and oil have fluctuated widely for many reasons, including:

• Global and regional supply and demand, and expectations regarding future supply and demand, for gas and oil products;
• Global and regional economic conditions;
• Evolution of stocks of oil and related products;
• Increased production due to new extraction developments and improved extraction and production methods;
• Geopolitical uncertainty;
• Threats or acts of terrorism, war or threat of war, which may affect supply, transportation or demand;
• Weather events, natural disasters and environmental incidents;
• Access to pipelines, storage platforms, shipping vessels and other means of transporting, storing and refining gas and oil,

including without limitation, changes in availability of, and access to, pipeline ullage;

• Prices and availability of alternative fuels;
• Prices and availability of new technologies affecting energy consumption;
• Increasing competition from alternative energy sources;
• The ability of OPEC and other oil-producing nations, to set and maintain specified levels of production and prices;
• Political, economic and military developments in gas and oil producing regions generally;

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• Governmental regulations and actions, including the imposition of tariffs, export restrictions and taxes and environmental

requirements and restrictions as well as anti-hydrocarbon production policies;

• Trading activities by market participants and others either seeking to secure access to natural gas, NGLs and oil or to hedge

against commercial risks, or as part of an investment portfolio; and

• Market uncertainty, including fluctuations in currency exchange rates, and speculative activities by those who buy and sell natural

gas, NGLs and oil on the world markets.

It is impossible to accurately predict future gas, NGL and oil price movements. Historically, natural gas prices have been highly

volatile and subject to large fluctuations in response to relatively minor changes in the demand for natural gas.

The economics of producing from some wells and assets may also result in a reduction in the volumes of our reserves which can be

produced commercially, resulting in decreases to our reported reserves. Additionally, further reductions in commodity prices may

result in a reduction in the volumes of our reserves. We might also elect not to continue production from certain wells at lower prices,

or our license partners may not want to continue production regardless of our position.

Each of these factors could result in a material decrease in the value of our reserves, which could lead to a reduction in our natural gas,

NGLs and oil development activities and acquisition of additional reserves. In addition, certain development projects or potential

future acquisitions could become unprofitable as a result of a decline in prices and could result in us postponing or canceling a planned

project or potential acquisition, or if it is not possible to cancel, to carry out the project or acquisition with negative economic impacts.

Further, a reduction in natural gas, NGL or oil prices may lead our producing fields to be shut in and to be entered into the

decommissioning phase earlier than estimated.

Our revenues, cash flows, operating results, profitability, dividends, future rate of growth and the carrying value of our gas and oil

properties depend heavily on the prices we receive for natural gas, NGLs and oil sales. Commodity prices also affect our cash flows

available for capital investments and other items, including the amount and value of our gas and oil reserves. In addition, we may face

gas and oil property impairments if prices fall significantly. In light of the continuing increase in supply coming from the Utica and

Marcellus shale plays of the Appalachian Basin, no assurance can be given that commodity prices will remain at levels which enable us

to do business profitably or at levels that make it economically viable to produce from certain wells and any material decline in such

prices could result in a reduction of our net production volumes and revenue and a decrease in the valuation of our production

properties, which could negatively impact our business, results of operations, financial condition, cash flows or prospects.

We conduct our business in a highly competitive industry.

The gas and oil industry is highly competitive. The key areas in which we face competition include:

• Engagement of third-party service providers whose capacity to provide key services may be limited;
• Acquisition of other companies that may already own licenses or existing producing assets;
• Acquisition of assets offered for sale by other companies;
• Access to capital (debt and equity) for financing and operational purposes;
• Purchasing, leasing, hiring, chartering or other procuring of equipment that may be scarce; and
• Employment of qualified and experienced skilled management and gas and oil professionals and field operations personnel.

Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial

resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their degree of vertical

integration and pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop

reserves and their ability to foster and maintain relationships with the relevant authorities. The cost to attract and retain qualified and

experienced personnel has increased and may increase substantially in the future.

Our competitors also include those entities with greater technical, physical and financial resources than us. Finally, companies and

certain private equity firms not previously investing in natural gas and oil may choose to acquire reserves to establish a firm supply or

simply as an investment. Any such companies will also increase market competition which may directly affect us.

If we are unsuccessful in competing against other companies, our business, results of operations, financial condition, cash flows or

prospects could be materially adversely affected.

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We may experience delays in production, transportation and marketing.

Various production, transportation and marketing conditions may cause delays in natural gas, NGLs and oil production and adversely

affect our business. For example, the gas gathering systems that we own connect to other pipelines or facilities which are owned and

operated by third parties. These pipelines and other midstream facilities and others upon which we rely may become unavailable

because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements,

curtailments of receipt or deliveries due to insufficient capacity or because of damage. Our largest processor of NGLs is the MarkWest

Energy Partners, L.P. (“MarkWest”) plant located in Langley, Kentucky. If we were to lose the ability to process NGLs at MarkWest’s

plant during a period of high pricing, our revenues would be negatively impacted. As a short-term measure, we could divert the natural

gas through other pipeline routes; however, certain pipeline operators would eventually decline to transport the gas due to its liquid

content at a level that would exceed tariff specifications for those pipelines. The lack of available capacity on third-party systems and

facilities could reduce the price offered for our production or result in the shut-in of producing wells. Any significant changes

affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities,

could delay our production, which could negatively impact our business, results of operations, financial condition, cash flows or

prospects.

We face production risks and hazards that may affect our ability to produce natural gas, NGLs and oil at expected levels,

quality and costs that may result in additional liabilities to us.

Our natural gas and oil production operations are subject to numerous risks common to our industry, including, but not limited to,

premature decline of reservoirs, incorrect production estimates, invasion of water into producing formations, geological uncertainties

such as unusual or unexpected rock formations and abnormal geological pressures, low permeability of reservoirs, contamination of

natural gas and oil, blowouts, oil and other chemical spills, explosions, fires, equipment damage or failure, challenges relating to

transportation, pipeline infrastructure, natural disasters, uncontrollable flows of oil, natural gas or well fluids, adverse weather

conditions, shortages of skilled labor, delays in obtaining regulatory approvals or consents, pollution and other environmental risks.

If any of the above events occur, environmental damage, including biodiversity loss or habitat destruction, injury to persons or

property and other species and organisms, loss of life, failure to produce natural gas, NGLs and oil in commercial quantities or an

inability to fully produce discovered reserves could result. These events could also cause substantial damage to our property or the

property of others and our reputation and put at risk some or all of our interests in licenses, which enable us to produce, and could

result in the incurrence of fines or penalties, criminal sanctions potentially being enforced against us and our management, as well as

other governmental and third-party claims. Consequent production delays and declines from normal field operating conditions and

other adverse actions taken by third parties may result in revenue and cash flow levels being adversely affected.

Moreover, should any of these risks materialize, we could incur legal defense costs, remedial costs and substantial losses, including

those due to injury or loss of life, human health risks, severe damage to or destruction of property, natural resources and equipment,

environmental damage, unplanned production outages, clean-up responsibilities, regulatory investigations and penalties, increased

public interest in our operational performance and suspension of operations, which could negatively impact our business, results of

operations, financial condition, cash flows or prospects.

The levels of our natural gas and oil reserves and resources, their quality and production volumes may be lower than

estimated or expected.

The reserves data as of December 31, 2025, 2024 and 2023 contained in this Annual Report on Form 10-K has been audited by NSAI

unless stated otherwise. The standards utilized to prepare the reserves information may be different from the standards of reporting

adopted in other jurisdictions. Investors, therefore, should not assume that our reserves information as set forth in this Annual Report

on Form 10-K is directly comparable to similar information that has been prepared in accordance with the reserve reporting standards

of other jurisdictions.

In general, estimates of economically recoverable natural gas, NGLs and oil reserves are based on a number of factors and

assumptions made as of the date on which the reserves estimates were determined, such as geological, geophysical and engineering

estimates (which have inherent uncertainties), historical production from the properties or analogous reserves, the assumed effects of

regulation by governmental agencies and estimates of future commodity prices, operating costs, gathering and transportation costs and

production related taxes, all of which may vary considerably from actual results.

Underground accumulations of hydrocarbons cannot be measured in an exact manner and estimates thereof are a subjective process

aimed at understanding the statistical probabilities of recovery. Estimates of the quantity of economically recoverable natural gas and

oil reserves, rates of production and, where applicable, the timing of development expenditures depend upon several variables and

assumptions.

Many of the factors in respect of which assumptions are made when estimating reserves are beyond our control and therefore these

estimates may prove to be incorrect over time. Evaluations of reserves necessarily involve multiple uncertainties. The accuracy of any

reserves evaluation depends on the quality of available information and natural gas, NGLs and oil engineering and geological

interpretation. Interpretation, testing and production after the date of the estimates may require substantial upward or downward

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revisions in our reserves and resources data. Moreover, different reserves engineers may make different estimates of reserves and cash

flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from

estimates and the variances may be material.

If the assumptions upon which the estimates of our natural gas and oil reserves prove to be incorrect or if the actual reserves available

to us (or the operator of an asset in we have an interest) are otherwise less than the current estimates or of lesser quality than expected,

we may be unable to recover and produce the estimated levels or quality of natural gas, NGLs or oil set out in this document and this

may materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

The PV-10 of our reserves will not necessarily be the same as the current market value of our estimated natural gas, NGL and

oil reserves.

You should not assume that the present value of future net cash flows from our reserves is the current market value of our estimated

natural gas, NGL and oil reserves. Actual future net cash flows from our natural gas and oil properties will be affected by factors such

as:

• Actual prices we receive for natural gas, NGL and oil;
• Actual cost of development and production expenditures;
• The amount and timing of actual production;
• Transportation and processing; and
• Changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of our natural

gas and oil properties will affect the timing and amount of actual future net cash flows from reserves, and thus their actual present

value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate

discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in

general. Actual future prices and costs may differ materially from those used in the present value estimate.

We may face unanticipated increased or incremental costs in connection with decommissioning obligations such as plugging.

In the future, we may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use

for the processing of natural gas and oil reserves. With regards to plugging, we are party to agreements with regulators in the states of

Ohio, West Virginia, Kentucky and Pennsylvania, four of our largest wellbore states, setting forth plugging and abandonment schedules

spanning a period ranging from 10 to 100 years. We will incur such decommissioning costs at the end of the operating life of some of our

properties or in the future period that wells are scheduled to be plugged. The ultimate decommissioning costs are uncertain and cost

estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration

techniques, the shortage of plugging vendors, difficult terrain or weather conditions or experience at other well locations. The expected

timing and amount of expenditure can also change, for example, in response to changes in reserves, wells losing commercial viability

sooner than forecasted or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the

provisions established which would affect future financial results. The use of other funds to satisfy such decommissioning costs may

impair our ability to focus capital investment in other areas of our business, which could materially and adversely affect our business,

results of operations, financial condition, cash flows or prospects.

We may not be able to keep pace with technological developments in our industry or be able to implement them effectively.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new

products and services using new technologies, such as emissions controls and processing technologies. Rapid technological

advancements in information technology and operational technology domains require seamless integration. Failure to integrate these

technologies efficiently may result in operational inefficiencies, security vulnerabilities, and increased costs. During mergers and

acquisitions, integrating technology assets from acquired companies can be complex. Poor integration may lead to data

inconsistencies, security gaps and operational disruptions. Technology systems are also susceptible to cybersecurity threats, including

malware, denial-of-service attacks, data breaches, hacking, social engineering or "phishing", deepfake attacks, computer viruses,

employee or insider threats, malfeasance, supply chain attacks, physical breaches, vendor email compromise, payment fraud, and

ransomware attacks. These threats may disrupt operations, compromise sensitive data and lead to significant financial losses. Further,

inefficient data management practices may result in data breaches, data loss and missed opportunities for operational insights. The

presence of legacy technology systems can also pose challenges, as they may lack modern security features, making them vulnerable

to cyber threats and necessitating costly upgrades. As others use or develop new technologies (including technologies related to

artificial intelligence), we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those

new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical and

personnel resources that allow them to enjoy technological advantages, which may in the future allow them to implement new

technologies before we can. Additionally, reliance on global supply chains for information technology hardware, software and

operational technology equipment exposes the industry to supply chain disruptions, shortages and cybersecurity risks.

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Our operations are subject to a series of risks relating to weather events.

Continued public concern regarding weather events and potential mitigation through regulation could have a material impact on our

business. International agreements, national, regional, state and local legislation, and regulatory measures to limit GHG emissions or

mandate related disclosures are currently in place or in various stages of discussion or implementation. Given that some of our

operations are associated with emissions of GHGs, these and other GHG emissions-related laws, policies and regulations may result in

substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and

regulations is uncertain and is expected to vary depending on the laws enacted by particular countries, states, provinces and

municipalities.

Additionally, regulatory, market and other changes to respond to weather events may adversely impact our business, financial

condition or results of operations. Reporting expectations are also increasing, with a variety of customers, capital providers and

regulators seeking increased information on weather-related risks. For example, U.S. states have adopted or proposed weather-related

disclosures rules that may require us to incur significant costs to assess and disclose on a range of weather-related data and risks.

Internationally, the United Nations-sponsored “Paris Agreement” requires member nations to individually determine and submit non-

binding emissions reduction targets every five years after 2020. In November 2021, the international community gathered in Glasgow

at the 26th Conference of the Parties to the UN Framework Convention on Climate Change, during which multiple announcements

were made, including a call for parties to eliminate certain natural gas and oil subsidies and pursue further action on non-carbon

dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which

aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy

sector. Such commitments were re-affirmed at the 27th Conference of the Parties in Sharm El Sheikh. However, on January 20, 2025,

President Trump issued an Executive Order directing the U.S. Ambassador to the United Nations to withdraw from the Paris

Agreement. Accordingly, the UN Secretary General issued a depositary notification of the U.S. withdrawal from the Paris Agreement,

effective January 27, 2026. More recently, in February 2026, the U.S. Environmental Protection Agency rescinded its prior finding

that certain GHG emissions endangered public health and welfare, which had served as the basis for certain GHG emission regulation

by the agency. This, and other changes undertaken by the Trump Administration have or may in the future reverse or rescind weather-

related initiatives and regulations and focus on driving increased U.S. energy production. The emission reduction targets and other

provisions of legislative or regulatory initiatives and policies enacted in the future by the states in which we operate, could adversely

impact our business by imposing increased costs in the form of higher taxes or increases in the prices of emission allowances, limiting

our ability to develop new gas and oil reserves, transport hydrocarbons through pipelines or other methods to market, decreasing the

value of our assets, or reducing the demand for hydrocarbons and refined petroleum products. With increased pressure to reduce GHG

emissions by replacing natural gas and oil energy generation with alternative energy generation, it is possible that peak demand for gas

and oil will be reached, and gas and oil prices will be adversely impacted as and when this happens. Further, the consequences of the

effects of global weather events and patterns, and the continued political and societal attention afforded to mitigating the effects of

weather events and patterns, may generate adverse investor and stakeholder sentiment towards the hydrocarbon industry and

negatively impact the ability to invest in the sector. Similarly, longer term reduction in the demand for hydrocarbon products due to

the pace of commercial deployment of alternative energy technologies or due to shifts in consumer preference for lower GHG

emissions products could reduce the demand for the hydrocarbons that we produce.

Further, in response to concerns related to weather events, companies in the natural gas and oil sector may be exposed to increasing

financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may

elect in the future to shift some or all of their investment into non-natural gas and oil related sectors. Institutional lenders who provide

financing to fossil-fuel energy companies have also become more attentive to sustainable lending practices, and some of them may elect

in the future not to provide funding for natural gas and oil energy companies. A material reduction in the capital available to the natural

gas and oil industry could make it more difficult to secure funding for exploration, development, production, and transportation activities,

which could in turn negatively affect our operations.

The Company may also be subject to activism from environmental non-governmental organizations (“NGOs”) campaigning against

natural gas and oil extraction or negative publicity from media alleging inadequate remedial actions to retire non-producing wells

effectively, which could affect our reputation, disrupt our programs, require us to incur significant, unplanned expense to respond or react

to intentionally disruptive campaigns or media reports, create blockades to interfere with operations or otherwise negatively impact our

business, results of operations, financial condition, cash flows or prospects. Litigation risks are also increasing as a number of entities

have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such

companies created public nuisances by producing fuels that contributed to weather events or alleging that the companies have been aware

of the adverse effects of weather events and patterns for some time.

Finally, our operations are subject to disruption from the physical effects that may be caused or aggravated by weather events. These

include risks from extreme weather events, such as hurricanes, severe storms, floods, heat waves, and ambient temperature increases,

as well as wildfires.

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We rely on third-party infrastructure that we do not control and/or, in each case, are subject to tariff charges that we do not

control.

A significant portion of our production passes through third-party owned and controlled infrastructure. If these third-party pipelines or

liquids processing facilities experience any event that causes an interruption in operations or a shut-down such as mechanical problems,

an explosion, adverse weather conditions, a terrorist attack or labor dispute, our ability to produce or transport natural gas could be

severely affected. For example, we have an agreement with a third-party where approximately 28% of the NGLs we sold during the

year ending December 31, 2025 were processed at the third-party’s facility in Kentucky. Any material decreases in our ability to

process or transport our natural gas through third-party infrastructure could have a material adverse effect on our business, results of

operations, financial condition, cash flows or prospects.

Our use of third-party infrastructure may be subject to tariff charges. Although we seek to manage our flow via our midstream

infrastructure, we may not always be able to avoid higher tariffs or basis blowouts due to the lack of interconnections. In such instances,

the tariff charges can be substantial and the cost is not subject to our direct control, although we may have certain contractual or

governmental protections and rights. Generally, the operator of the gathering or transmission pipelines sets these tariffs and expenses on a

cost sharing basis according to our proportionate hydrocarbon through-put of that facility. A provisional tariff rate is applied during the

relevant year and then finalized the following year based on the actual final costs and final through-put volumes. Such tariffs are

dependent on continued production from assets owned by third parties and, may be priced at such a level as to lead to production from

our assets ceasing to be economic and thus may have a material adverse effect on our business, results of operations, financial condition,

cash flows or prospects.

Furthermore, our use of third-party infrastructure exposes us to the possibility that such infrastructure will cease to be operational or

be decommissioned and therefore require us to source alternative export routes and/or prevent economic production from our assets.

This could also have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

Failure by us, our contractors or our primary offtakers to obtain access to necessary equipment and transportation systems

could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

We rely on our natural gas and oil field suppliers and contractors to provide materials and services that facilitate our production

activities, including plugging and abandonment contractors. Any competitive pressures on the oil field suppliers and contractors could

result in a material increase of costs for the materials and services required to conduct our business and operations. For example, we

are dependent on the availability of plugging vendors to help us satisfy abandonment schedules that we have agreed to with the states

of Ohio, West Virginia, Kentucky and Pennsylvania. Such personnel and services can be scarce and may not be readily available at the

times and places required. Future cost increases could have a material adverse effect on our asset retirement liability, operating

income, cash flows and borrowing capacity and may require a reduction in the carrying value of our properties, our planned level of

spending for development and the level of our reserves. Prices for the materials and services we depend on to conduct our business

may not be sustained at levels that enable us to operate profitably.

We and our offtakers rely, and any future offtakers will rely, upon the availability of pipeline and storage capacity systems, including

such infrastructure systems that are owned and operated by third parties. As a result, we may be unable to access or source alternatives

for the infrastructure and systems which we currently use or plan to use, or otherwise be subject to interruptions or delays in the

availability of infrastructure and systems necessary for the delivery of our natural gas, NGLs and oil to commercial markets. In

addition, such infrastructure may be close to its design life and decisions may be taken to decommission such infrastructure or perform

life extension work to maintain continued operations. Any of these events could result in disruptions to our projects and thereby

impact our ability to deliver natural gas, NGLs and oil to commercial markets and/or may increase our costs associated with the

production of natural gas, NGLs and oil reliant upon such infrastructure and systems. Further, our offtakers could become subject to

increased tariffs imposed by government regulators or the third-party operators or owners of the transportation systems available for

the transport of our natural gas, NGLs and oil, which could result in decreased offtaker demand and downward pricing pressure.

If we are unable to access infrastructure systems facilitating the delivery of our natural gas, NGLs and oil to commercial markets due

to our contractors or primary offtakers being unable to access the necessary equipment or transportation systems, our operations will

be adversely affected. If we are unable to source the most efficient and expedient infrastructure systems for our assets then delivery of

our natural gas, NGLs and oil to the commercial markets may be negatively impacted, as may our costs associated with the production

of natural gas, NGLs and oil reliant upon such infrastructure and systems.

A proportion of our equipment has substantial prior use and significant expenditure may be required to maintain operability

and operations integrity.

A part of our business strategy is to optimize or refurbish producing assets where possible to maximize the efficiency of our operations

while avoiding significant expenses associated with purchasing new equipment. Our producing assets and midstream infrastructure

require ongoing maintenance to ensure continued operational integrity. For example, some older wells may struggle to produce

suitable line pressure and will require the addition of compression to push natural gas. Despite our planned operating and capital

expenditures, there can be no guarantee that our assets or the assets we use will continue to operate without fault and not suffer

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material damage in this period through, for example, wear and tear, severe weather conditions, natural disasters or industrial accidents.

If our assets, or the assets we use, do not operate at or above expected efficiencies, we may be required to make substantial

expenditures beyond the amounts budgeted. Any material damage to these assets or significant capital expenditure on these assets for

improvement or maintenance may have a material adverse effect on our business, results of operations, financial condition, cash flows

or prospects. In addition, as with planned operating and capital expenditure, there is no guarantee that the amounts expended will

ensure continued operation without fault or address the effects of wear and tear, severe weather conditions, natural disasters or

industrial accidents. We cannot guarantee that such optimization or refurbishment will be commercially feasible to undertake in the

future and we cannot provide assurance that we will not face unexpected costs during the optimization or refurbishment process.

We depend on our directors, key members of management, independent experts, and technical and operational service

providers and on our ability to retain and hire such persons to effectively manage our growing business.

Our future operating results depend in significant part upon the continued contribution of our directors, key senior management and

technical, financial and operations personnel. Management of our growth will require, among other things, stringent control of

financial systems and operations, the continued development of our control environment, the ability to attract and retain sufficient

numbers of qualified management and other personnel, the continued training of such personnel and the presence of adequate

supervision.

In addition, the personal connections and relationships of our directors and key management are important to the conduct of our

business. If we were to unexpectedly lose a member of our key management or fail to maintain one of the strategic relationships of our

key management team, our business, results of operations, financial condition, cash flows or prospects could be materially adversely

affected. In particular, we are very dependent on our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr. Acquisitions are a

key part of our strategy, and Mr. Hutson has been instrumental in sourcing them and securing their financing. Furthermore, as our

founder, Mr. Hutson is strongly associated with our success, and if he were to cease being the Chief Executive Officer, perception of

our future prospects may be diminished.

Attracting and retaining additional skilled personnel will be fundamental to the continued growth and operation of our business. We

require skilled personnel in the areas of development, operations, engineering, business development, natural gas, NGLs and oil

marketing, finance and accounting relating to our projects. Personnel costs, including salaries, are increasing as industry wide demand

for suitably qualified personnel increases. We may not successfully attract new personnel and retain existing personnel required to

continue to expand our business and to successfully execute and implement our business strategy.

We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas, oil and NGL

production operations. Productive zones frequently contain water that must be removed for the natural gas, oil and NGL to produce,

and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce

natural gas, oil and NGL in commercial quantities. The produced water must be transported from the leasehold and/or injected into

disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may

affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with

regulations concerning water disposal, may reduce our profitability. We have entered into various water management services

agreements in the Appalachian Region which provide for the disposal of our produced water by established counterparties with large

integrated pipeline networks. If these counterparties fail to perform, we may have to shut in wells, reduce drilling activities, or upgrade

facilities for water handling or treatment. The costs to dispose of this produced water may increase for a number of reasons, including

if new laws and regulations require water to be disposed in a different manner.

In 2016, the EPA adopted effluent limitations for the treatment and discharge of wastewater resulting from onshore unconventional

natural gas, oil and NGL extraction facilities to publicly owned treatment works. In addition, the injection of fluids gathered from

natural gas, oil and NGL producing operations in underground disposal wells has been identified by some groups and regulators as a

potential cause of increased seismic events in certain areas of the country, including the states of West Virginia, Ohio and Kentucky in

the Appalachian Region as well as Oklahoma, Texas and Louisiana in our Central Region. Certain states, including those located in

the Appalachian Region have adopted, or are considering adopting, laws and regulations that may restrict or prohibit oilfield fluid

disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing

certain wells in areas where seismic events have occurred to restrict or suspend disposal well permits or operations or impose certain

conditions related to disposal well construction, monitoring, or operations. Any of these developments could increase our cost to

dispose of our produced water.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Pursuant to the authority under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and Hazardous Liquid Pipeline Safety Act of

1979 (“HLPSA”), as amended by the Pipeline Safety Improvement Act of 2002 (“PSIA”), the Pipeline Inspection, Protection,

Enforcement and Safety Act of 2006 (“PIPESA”) and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the

“2011 Pipeline Safety Act”), the PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity

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management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect high

consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high-

population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of

covered pipelines to:

• Perform ongoing assessments of pipeline integrity;
• Identify and characterize applicable threats to pipeline segments that could impact HCAs;
• Improve data collection, integration and analysis;
• Repair and remediate the pipeline as necessary; and
• Implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid

pipelines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations,

as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of pipeline

integrity testing, but the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures

for repairs or upgrades deemed necessary to ensure the safe and reliable operation of our pipelines.

At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, federal and state legislative and

regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent

enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Moreover as of January 2025, the maximum civil penalties PHMSA can impose are $272,926 per pipeline safety violation per day,

with a maximum of $2,729,245 for a related series of violations. The safety enhancement requirements and other provisions of the

2011 Pipeline Safety Act as well as any implementation of PHMSA regulations thereunder or any issuance or reinterpretation of

guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue

additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our

incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. States

are also pursuing regulatory programs intended to safely build pipeline infrastructure. The adoption of new or amended regulations by

PHMSA or the states that result in more stringent or costly pipeline integrity management or safety standards could have a significant

adverse effect on us and similarly situated midstream operators.

Risks Relating to Our Financing, Acquisitions, Investment and Indebtedness

Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability

to enter into future debt financing.

Inflation can adversely affect us by increasing costs of materials, equipment, labor and other services. In addition, inflation is often

accompanied by higher interest rates. Continued inflationary pressures could impact our profitability. Though we believe that the rates

of inflation in recent years, including the 12 months ended December 31, 2025, have not had a significant impact on our operations, a

continued increase in inflation, including inflationary pressure on labor, could result in increases to our operating costs, and we may be

unable to pass these costs on to our customers. These inflationary pressures could also adversely impact our ability to procure

materials and equipment in a cost-effective manner, which could result in reduced margins and production delays and, as a result, our

business, financial condition, results of operations and cash flows could be materially and adversely affected. We continue to

undertake actions and implement plans to address these inflationary pressures and protect the requisite access to materials and

equipment. With respect to our costs of capital, our ABS Notes (as defined in the Notes to the Consolidated Financial Statements) are

fixed-rate instruments (described in Note 15 in the Notes to the Consolidated Financial Statements) and as of February 25, 2026, we

had $243 million outstanding on our Credit Facility and $500 million of 9.75% senior secured bonds due 2029. Nevertheless, inflation

may also affect our ability to enter into future debt financing, including refinancing of our Credit Facility or issuing additional SPV-

level asset backed securities, as high inflation may result in a relative increase in the cost of debt capital.

We are taking efforts to mitigate inflationary pressures, by working closely with other suppliers and service providers to ensure

procurement of materials and equipment in a cost-effective manner. However, these mitigation efforts may not succeed or may be

insufficient.

Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If

the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further,

which could impact the price at which natural gas, NGLs and oil can be sold, which could affect our results of operations, financial

condition, cash flows and prospects.

There are risks inherent in our acquisitions of natural gas and oil assets.

Acquisitions are an essential part of our strategy for protecting and growing cash flow, particularly in relation to the risk that some of

our wells may have a higher than anticipated production decline rate. Over the past several years, we have undertaken a number of

26

acquisitions of natural gas and oil assets (and of companies holding such assets). Our ability to complete future acquisitions will

depend on us being able to identify suitable acquisition candidates and negotiate favorable terms for their acquisition, in each case,

before any attractive candidates are purchased by other parties such as private equity firms, some of whom have substantially greater

financial and other resources than we do. We may face competition for attractive acquisition targets that may also increase the price of

the target business. As a result, there is no assurance that we will always be able to source and execute acquisitions in the future at

attractive valuations.

Furthermore, an acquisition in a new area in which we lack experience may present unanticipated risks and challenges that were not

accounted for or previously experienced. Ordinarily, our due diligence efforts are focused on higher valued and material properties or

assets. Even an in-depth review of all properties and records may not reveal all existing or potential problems, nor will such review

always permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Generally,

physical inspections are not performed on every well or facility, and structural or environmental problems are not necessarily

observable even when an inspection is undertaken.

There can be no assurance that our prior acquisitions or any other potential acquisition will perform operationally as anticipated or be

profitable. We could fail to appropriately value any acquired business and the value of any business, company or property that we

acquire or invest in may actually be less than the amount paid for it or its estimated production capacity. We may be required to

assume pre-closing liabilities with respect to an acquisition, including known and unknown title, contractual, and environmental and

decommissioning liabilities, and may acquire interests in properties on an “as is” basis without recourse to the seller of such interest or

the seller may have limited resources to provide post-sale indemnities.

In addition, successful acquisitions of gas and oil assets require an assessment of a number of factors, including estimates of

recoverable reserves, the time of recovering reserves, exploration potential, future natural gas, NGLs and oil prices and operating

costs. Such assessments are inexact, and we cannot guarantee that we make these assessments with a high degree of accuracy. In

connection with assessments, we perform a review of the acquired assets. However, such a review will not reveal all existing or

potential problems. Furthermore, review may not permit us to become sufficiently familiar with the assets to fully assess their

deficiencies and capabilities.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may

disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. However, we may not be able

to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to

complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing

operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate

amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices

significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional

suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully

acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing

operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial

condition and results of operations.

Our Credit Facility and other debt agreements also limit our ability to incur certain indebtedness, which could indirectly limit our

ability to engage in acquisitions of businesses.

The Company’s success will be impacted by its ability to fully integrate Canvas and deliver the value of the combined

underlying businesses; the full financial benefits expected from the Company may not be fully achieved.

While the Company believes that the financial benefits of the Canvas acquisition and the costs associated with the Canvas acquisition

have been reasonably estimated, unanticipated events or liabilities may arise or become apparent which may, in turn, result in a delay

or reduction in the benefits anticipated to be derived from the Canvas acquisition, or in costs significantly in excess of those estimated.

No assurance can be given that the integration process will deliver all or substantially all of the expected benefits or realize any such

benefits within the assumed timeframe, or that the costs to integrate and achieve the financial benefits will not be higher than

anticipated.

Further, the demands that the integration process may have on management time could result in diversion of the attention of the

Company's management and employees from ongoing operations, pursuing other potential business opportunities and may cause a

delay in other projects currently contemplated by the Company. To the extent that the combined company is unable to efficiently

integrate the operations of the Company and Canvas, realize anticipated financial benefits, retain key personnel and avoid unforeseen

costs or delay, there may be a material adverse effect on the business, results of operations, financial condition, cash flows or

prospects of the Company.

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We may not have good title to all our assets and licenses.

Although we believe that we take due care and conduct due diligence on new acquisitions in a manner that is consistent with industry

practice, there can be no assurance that we have good title to all our assets and the rights to develop and produce natural gas and oil

from our assets. Such reviews are inherently incomplete and it is generally not feasible to review in depth every individual well or

field involved in each acquisition. There can be no assurance that any due diligence carried out by us or by third parties on our behalf

in connection with any assets that we acquire will reveal all of the risks associated with those assets, and the assets may be subject to

preferential purchase rights, consents and title defects that were not apparent at the time of acquisition. We may acquire interests in

properties on an “as is” basis without recourse to the seller of such interest or the seller may have limited resources to provide post-

sale indemnities. In addition, changes in law or change in the interpretation of law or political events may arise to defeat or impair our

claim to certain properties which we currently own or may acquire which could result in a material adverse effect on our business,

results of operations, financial condition, cash flows or prospects.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our Credit Facility and other debt agreements contain a number of significant covenants that may limit our ability to, among other

things:

• Incur additional indebtedness;
• Incur liens;
• Sell assets;
• Make certain debt payments;
• Enter into agreements that restrict or prohibit the payment of dividends;
• Limits our subsidiaries’ ability to make certain payments with respect to their equity, based on the pro forma effect thereof on

certain financial ratios, which would be the source of distributable profits and available cash from which we may issue a dividend;

and

• Conduct hedging activities.

In addition, our Credit Facility and other debt agreements require us to maintain compliance with certain financial covenants.

We may also be prevented from taking advantage of business opportunities that arise because of the limitations from the restrictive

covenants under our Credit Facility and other debt agreements. These restrictions may limit our ability to obtain future financings to

withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities.

A material uncured breach of any covenant in our Credit Facility and other debt agreements will result in a default under the

agreement and may result in an event of default if such default is not cured during any applicable grace period. An event of default, if

not waived, could result in acceleration of the indebtedness outstanding and in an event of default with respect to, and an acceleration

of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would

become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient

funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to

us.

Any significant reduction in our borrowing base under our Credit Facility as a result of periodic borrowing base

redeterminations or otherwise may negatively impact our ability to fund our operations.

Our Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion,

unilaterally determine based upon our reserve reports for the applicable period and other data and reports. Such determinations will be

made on a regular basis semi-annually (each a “Scheduled Redetermination”) and at the option of the lenders with more than 66.6% of

the loans and commitments under the Credit Facility, no more than one time in between each Scheduled Redetermination. As of

February 25, 2026, our borrowing base was $825 million.

In the future, we may not be able to access adequate funding under our Credit Facility as a result of a decrease in our borrowing base

due to the issuance of new indebtedness, the outcome of a borrowing base redetermination, or an unwillingness or inability on the part

of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a

defaulting lender’s portion. Declines in commodity prices from their current levels could result in a determination to lower the

borrowing base and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As

a result, we may be unable to make acquisitions or otherwise carry out business plans, which could have a material adverse effect on

our business, results of operations, financial condition, cash flows or prospects.

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The securitizations of our limited purpose, bankruptcy-remote, wholly owned subsidiaries may expose us to financing and

other risks, and there can be no assurance that we will be able to access the securitization market in the future, which may

require us to seek more costly financing.

Through limited purpose, bankruptcy-remote, wholly owned subsidiaries (“SPVs”), we have securitized and expect to securitize in the

future, certain of our assets to generate financing. In such transactions, we convey a pool of assets to an SPV, that, in turn, issues

certain securities or enters into certain debt agreements. The securities issued by the SPVs are each collateralized by a pool of assets.

In exchange for the transfer of finance receivables to the SPV, we typically receive the cash proceeds from the sale of the securities or

entering into term loans.

Although our SPVs have completed securitizations in connection with the ABS IV Notes, ABS VI Notes, ABS VII Notes, ABS VIII

Notes (which now covers ABS III Notes and ABS V Notes), ABS IX Notes, ABS X Notes (which now covers Term Loan I, ABS I

Notes, and ABS II Notes) (each as defined herein), and ABS XI Notes, there can be no assurance that we, through our SPVs, will be

able to complete additional securitizations, particularly if the securitization markets become constrained. In addition, the value of any

securities that our limited purpose, bankruptcy-remote, wholly owned subsidiaries retain in our securitizations, including securities

retained to comply with applicable risk retention rules, might be reduced or, in some cases, eliminated as a result of an adverse change

in economic conditions or the financial markets. In addition, our ABS IV Notes, ABS VI Notes, ABS VII Notes, ABS VIII Notes

(which now covers ABS III Notes and ABS V Notes), ABS IX Notes, ABS X Notes (which now covers Term Loan I, ABS I Notes,

and ABS II Notes), and ABS XI Notes are subject to customary accelerated amortization events, including events tied to the failure to

maintain stated debt service coverage ratios.

If it is not possible or economical for us to securitize our assets in the future, we would need to seek alternative financing to support

our operations and to meet our existing debt obligations, which may be less efficient and more expensive than raising capital via

securitizations and may have a material adverse effect on our results of operations, financial condition, cash flows and liquidity.

An increase in interest rates would increase the cost of servicing our indebtedness and could reduce our profitability, decrease

our liquidity and impact our solvency.

Our Credit Facility provides for, and our future debt agreements may provide for, debt incurred thereunder to bear interest at variable

rates. As of February 25, 2026, we had $243 million outstanding on our Credit Facility. Increases in interest rates would increase the

cost of servicing indebtedness under our Credit Facility or under future debt agreements subject to interest at variable rates, and

materially reduce our profitability, decrease our liquidity and impact our solvency.

Our hedging activities could result in financial losses or could reduce our net income.

To achieve more predictable cash flows, we employ a hedging strategy involving opportunistically hedging a majority of our first two

years of production as well as hedging a significant percentage of production beyond our first two years of forecasted production.

Even so, the remainder of our production that is unhedged is exposed to the continuing and prolonged declines in the prices of natural

gas, NGLs and oil. Our results of operations and financial condition would be negatively impacted if the prices of natural gas, NGLs

or oil were to remain depressed or decline materially from current levels. To achieve more predictable cash flows and to reduce our

exposure to fluctuations in the prices of natural gas, NGLS and oil, we may enter into additional hedging arrangements for a

significant portion of our production.

Our derivative contracts may result in substantial gains or losses. For example, we reported income from operations of $535 million

for the year ended December 31, 2025, compared to a loss of $97 million for the year ended December 31, 2024 and income of

$1.1 billion for the year ended December 31, 2023. While our earnings are impacted by a variety of factors as described in Results of

Operations, a key driver of our year-over-year change from a loss to income was attributable to a change of $255 million in the mark-

to-market valuation adjustment on our derivative financial instrument valuations to a gain of $218 million in 2025 from a loss of $38

million in 2024. There can be no assurance that we will not realize additional losses due to our hedging activities in the future. In

addition, if we enter into any derivative contracts and experience a sustained material interruption in our production, we might be

forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying

physical commodity, resulting in a substantial diminution of our liquidity. Our ability to use hedging transactions to protect us from

future natural gas, NGL and oil price volatility will be dependent upon natural gas, NGL and oil prices at the time we enter into future

hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity

price changes. In addition, if commodity prices remain low, we will not be able to replace our hedges or enter into new hedges at

favorable prices.

Our price hedging strategy and future hedging transactions will be determined at our discretion, subject to the terms of certain

agreements governing our indebtedness. The prices at which we hedge our production in the future will be dependent upon commodity

prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our

price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our

hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially

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larger percentage of our future production will not be hedged as compared with the next few years, which would result in our natural

gas, NGL and oil revenues becoming more sensitive to commodity price fluctuations.

The failure of our hedge counterparties to meet their obligations to us may adversely affect our financial results.

An attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the

instrument and that we will not realize the benefit of the hedge. Disruptions in the financial markets could lead to sudden decreases in

a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be

able to realize the benefit of the derivative contract. Any default by the counterparty to these derivative contracts when they become

due would have a material adverse effect on our results of operations, financial condition, cash flows and prospects.

We may not be able to enter into commodity derivatives on favorable terms or at all.

To achieve a more predictable cash flow, we employ a hedging strategy involving opportunistically hedging a majority of our first two

years of production as well as hedging a significant percentage of production beyond our first two years of forecasted production. If

we are unable to maintain sufficient hedging capacity with our counterparties, we could have greater exposure to changes in

commodity prices and interest rates, which could have a material adverse impact on our business, results of operations, financial

condition, cash flows or prospects.

Risks Relating to Legal, Tax, Environmental and Regulatory Matters

We are subject to regulation and liability under environmental, health and safety regulations, the violation of which may affect

our financial condition and operations.

We operate in an industry that has certain inherent hazards and risks, and consequently we are subject to stringent and comprehensive

laws and regulations, especially with regard to the protection of health, safety and the environment. For example, we are subject to

laws and regulations related to occupational safety and health, hydraulic fracturing activities, air emissions, soil and water quality, the

protection of threatened and endangered plant and animal species, biodiversity and ecosystems, and the safety of our assets and

employees. Although we believe that we have adequate procedures in place to mitigate operational risks, there can be no assurances

that these procedures will be adequate to address every potential health, safety and environmental hazard, and a failure to adequately

mitigate risks may result in loss of life, injury, or adverse impacts on the health of employees, contractors and third-parties or the

environment. Any failure by us or one of our subcontractors, whether inadvertent or otherwise, to comply with applicable legal or

regulatory requirements may give rise to civil, administrative and/or criminal liabilities, civil fines and penalties, delays or restrictions

in acquiring or disposing of assets and/or delays in securing or maintaining required permits, licenses and approvals. Further, a lack of

regulatory compliance may lead to denial, suspension, or termination of permits, licenses, or approvals that are required to operate our

sites or could result in other operational restrictions or obligations. Our health, safety and environmental policies require us to observe

local, state and national legal and regulatory requirements and to apply generally accepted industry best practices where legislation or

regulation does not exist.

The terms and conditions of licenses, permits, regulatory orders, approvals or permissions may include more stringent operational,

environmental and/or health and safety requirements. Obtaining development or production licenses and permits may become more

difficult or may be delayed due to federal, regional, state or local governmental constraints, considerations, or requirements on issuing.

Furthermore, third-parties such as environmental NGOs may administratively or judicially contest or protest licenses and permits

already granted by relevant authorities or applications for the same and operations may be subject to other administrative or judicial

challenges.

In addition, under certain environmental laws and regulations, we could be subject to joint and several strict liability for the removal or

remediation of previously released materials, pollution, or property contamination regardless of whether we were responsible for the

release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken.

Private parties, including the owners of properties on or adjacent to well sites and facilities where petroleum hydrocarbons or wastes

are taken for reclamation or disposal, may also have the right to pursue legal actions as well as to seek damages for non-compliance

with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases

of pollutants or contaminants could expose us to significant liabilities that could have a material adverse effect on our business,

financial condition and results of operations.

We incur, and expect to continue to incur, capital and operating costs in an effort to comply with increasingly complex operational

health and safety and environmental laws and regulations. New laws and regulations, the imposition of more stringent requirements in

permits and licenses, increasingly strict enforcement of, or new interpretations of, existing laws, regulations and permits and licenses,

or the discovery of previously unknown contamination or hazards may require further costly expenditures to, for example:

• Modify operations, including an increase in plugging and abandonment operations;
• Install or upgrade pollution or emissions control equipment;
• Perform site clean ups, including the remediation and reclamation of gas and oil sites;
• Curtail or cease certain operations;

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• Provide financial securities, bonds, and/or take out insurance; or
• Pay fees or fines or make other payments for pollution, discharges to the environment or other breaches of environmental or

health and safety requirements or consent agreements with regulatory agencies.

We cannot predict with any certainty the full impact of any new laws, regulations, or policies on our operations or on the cost or

availability of insurance to cover the risks associated with such operations. The costs of such measures and liabilities related to

potential operational health and safety or environmental risks associated with the Company may increase, which could materially and

adversely affect our business, results of operations, financial condition, cash flows or prospects. In addition, it is not possible to predict

what future operational health and safety or environmental laws and regulations will be enacted or how current or future operational,

health, safety or environmental laws and regulations will be applied or enforced. We may have to incur significant expenditure for the

installation and operation of additional systems and equipment for monitoring and carry out remedial measures in the event that

operational health and, safety and environmental regulations become more stringent or costly reform is implemented by regulators.

Any such expenditure may have a material adverse effect on our business, results of operations, financial condition, cash flows or

prospects. No assurance can be given that compliance with occupational health and safety and environmental laws or regulations in the

regions where we operate will not result in a curtailment of production or a material increase in the cost of production or development

activities.

Heightened attention to sustainability matters may impact our business and financial results.

In recent years, heightened attention has been given to corporate activities related to sustainability matters in public discourse and the

investment community. A number of advocacy groups, both domestically and internationally, have previously campaigned for

governmental and private action to promote change at public companies related to sustainability matters, including through the

investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the

investing community. These activities include attention and demands for action related to weather events and promoting the use of

alternative forms of energy. These activities may result in demand shifts for oil and natural gas products and additional governmental

investigations and private litigation against us. In addition, stakeholder views continue to evolve and vary, and our initiatives related to

these matters, which rely on standards for measuring progress that are subject to change, are unlikely to satisfy all stakeholders. Our

failure to comply with evolving investor or customer expectations and standards (which may support or disfavor sustainability

initiatives) or if we are perceived to not have responded appropriately to the growing concern for sustainability issues, regardless of

whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, including as

a result of heightened scrutiny of and challenges to sustainability initiatives and related claims, and could have a material adverse

effect on our results of operation.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings

systems for evaluating companies on their approach to sustainability matters. These ratings are used by some investors to inform their

investment and voting decisions. Unfavorable sustainability ratings may lead to increased negative investor sentiment toward us and

our industry and to the diversion of investment to other companies or industries, which could have a negative impact on our stock

price and our access to and costs of capital. Also, institutional lenders may decide not to provide funding for oil and natural gas

companies based on weather event-related concerns, which could affect our access to capital for potential growth projects.

The U.S. administration, acting through the executive branch and/or in coordination with Congress, could enact or rescind

rules and regulations that may impact our operations.

Governmental, scientific and public concern over the threat of weather events has resulted in increasing political risks in the United

States, including weather event-related commitments and uncertainty expressed by some officials and political candidates who are

now, or may in the future be, in political office.

While our operations are largely not conducted on federal lands, we may in the future consider acquisitions of natural gas and oil

assets located in areas in which the development of such assets would require permits and authorizations to be obtained from or issued

by federal agencies. To conduct these operations, we may be required to file applications for permits, seek agency authorizations and

comply with various other statutory and regulatory requirements. Further, new oil and gas leasing on public lands has been the subject

of recent proposed executive action rescinding weather event-related initiatives and requirements. Complying with these evolving

requirements may adversely affect our ability to conduct operations at the costs and in the time periods anticipated, and may

consequently adversely impact our anticipated returns from our operations.

Any such measures or increased costs could have a material adverse effect on our business, results of operations, financial condition,

cash flows or prospects.

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Our operations are dependent on our compliance with obligations under permits, licenses, contracts and field development

plans.

Our operations must be carried out in accordance with the terms of permits, licenses, operating agreements, annual work programs and

budgets. Fines, penalties, or enforcement actions may be imposed and a permit or license may be suspended or terminated if a permit

or license holder, or party to a related agreement, fails to comply with its obligations under such permit, license or agreement, or fails

to make timely payments of levies and taxes for the licensed activity, or fails to provide the required geological information or meet

other reporting requirements. It may from time to time be difficult to ascertain whether we have complied with obligations under

permits or licenses as the extent of such obligations may be unclear or ambiguous and regulatory authorities in jurisdictions in which

we do business, or in which we may do business in the future, may not be forthcoming with confirmatory statements that work

obligations have been fulfilled, which can lead to further operational uncertainty.

In addition, we and our commercial partners, as applicable, have obligations to operate assets in accordance with specific requirements

under certain licenses and related agreements, field development agreements, laws and regulations. If we or our partners were to fail to

satisfy such obligations with respect to a specific field, the license or related agreements for that field may be suspended, revoked or

terminated. Although we have in the past acquired and may in the future acquire shale assets, a significant source of our natural gas

and crude oil remains conventional wells. In some instances, these conventional wells are located on the same property as

unconventional wells that produce shale oil and gas. In these cases, the rights to access the shale layers of the property will typically

be conditioned on the ongoing productivity of conventional wells on the property. Furthermore, the shale rights may be owned by a

third party, and in such instances, we will enter into a joint use agreement with the third party. This joint use agreement may stipulate

that in consideration for permission to operate the conventional wells, we are to use reasonable efforts to maintain production so that the

third party retains the shale licenses. If we fail to maintain production in the conventional wells, under the joint use agreement, we may

be liable to the third party for replacing the lost land rights. The relevant authorities are typically authorized to, and do from time to time,

inspect to verify compliance by us or our commercial partners, as applicable, with relevant laws and the licenses or the agreements

pursuant to which we conduct our business. There can be no assurance that the views of the relevant government agencies regarding the

development of the fields that we operate or the compliance with the terms of the licenses pursuant to which we conduct such operations

will coincide with our views, which might lead to disagreements that may not be resolved.

The suspension, revocation, withdrawal or termination of any of the permits, licenses or related agreements pursuant to which we may

conduct business, as well as any delays in the continuous development of or production at our fields caused by the issues detailed

above could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects. In

addition, failure to comply with the obligations under the permits, licenses or agreements pursuant to which we conduct business,

whether inadvertent or otherwise, may lead to fines, penalties, restrictions, enforcement actions brought by governmental authorities,

withdrawal of licenses and termination of related agreements.

We do not insure against certain risks and our insurance coverage may not be adequate for covering losses arising from

potential operational hazards and unforeseen interruptions.

We insure our operations in accordance with industry practice and plan to continue to insure the risks we consider appropriate for our

needs and circumstances. However, we may elect not to have insurance for certain risks, due to the high premium costs associated

with insuring those risks or for various other reasons, including an assessment in some cases that the risks are remote.

Our insurance may not be adequate to cover all losses or liabilities we may suffer. We cannot assure that we will be able to obtain

insurance coverage at reasonable rates (or at all), or that any coverage we or the relevant operator obtain, and any proceeds of

insurance, will be adequate and available to cover any claims arising. We may become subject to liability for pollution, blow-outs or

other hazards against which we have not insured or cannot insure, including those in respect of past activities for which we were not

responsible. Any indemnities we may receive from sub-contractors, operators or joint venture partners may be difficult to enforce if

such sub-contractors, operators or joint venture partners lack adequate resources.

Operational insurance policies are usually placed in one year contracts and the insurance market can withdraw cover for certain risks

due to events occurring in other parts of the industry, thus greatly increasing the costs of risk transfer. For example, in September

2018, a gas pipeline operated by another midstream company exploded in Beaver County, Pennsylvania, a state in which we have

operations. The explosion resulted in the destruction of residential property and motor vehicles as well as the evacuation of nearby

households. Catastrophic events such as these may cause the insurance costs for our midstream operations to rise, despite us not being

involved in the catastrophic event. In the event that insurance coverage is not available or our insurance is insufficient to fully cover

any losses, including losses incurred due to lost revenues resulting from third party operations or processing plants, claims and/or

liabilities incurred, or indemnities are difficult to enforce, our business and operations, financial results or financial position may be

disrupted and adversely affected.

The payment by our insurers of any insurance claims may result in increases in the premiums payable by us for our insurance coverage

and could adversely affect our financial performance. In the future, some or all of our insurance coverage may become unavailable or

prohibitively expensive.

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Our internal systems and website may be subject to intentional and unintentional disruption, and our confidential information

may be misappropriated, stolen or misused, which could adversely impact our reputation and future sales.

We have faced, and may in the future continue to face, cyber-attacks and data security breaches. Such cyber-attacks and breaches may

come from criminal hackers, state-sponsored threat actors, industrial espionage or employee malfeasance and are designed to penetrate

our network security or the security of our internal systems, misappropriate proprietary information and/or cause interruptions to our

services. We expect to continue to face similar threats in the future, and cannot guarantee that we will be able to successfully prevent all

future attacks. Such future attacks could include malware, denial-of-service attacks, data breaches, hacking, social engineering or

"phishing", deepfake attacks, computer viruses, employee or insider threats, malfeasance, supply chain attacks, physical breaches,

vendor email compromise, payment fraud and ransomware attacks. If an actual or perceived breach of our network security occurs, it

could adversely affect our business or reputation, and may trigger governmental notice requirements and public disclosure, and expose

us to the loss of information, fines, regulatory actions, sanctions, litigation and possible liability. An actual security breach could also

impair our ability to operate our business and provide products and services to our customers. Additionally, malicious attacks,

including cyber-attacks, may damage our assets, prevent production at our producing assets, cause disruptions in business operations,

lead to injury to people or harm to the environment and otherwise significantly affect corporate activities. For example, we utilize

electronic monitoring of meters and flow rate devices to monitor pressure build-up in our production wells. If there were a cyber-attack

that penetrated our monitoring systems such that they provided false readings, this could result in an unknown pressure build-up,

creating a dangerous situation which could lead to an explosion. As techniques used to obtain unauthorized access to or to sabotage

systems change frequently and may not be known until launched against us or our third-party service providers, we may be unable to

anticipate or implement adequate measures to protect against these attacks and our service providers may likewise be unable to do so.

Additionally, artificial intelligence has contributed to an increase in the number and sophistication of cyber-attacks. As there continue

to be advances in artificial intelligence, threat actors will develop increasingly sophisticated cyber-attack strategies. This may include

the use of artificial intelligence to enhance and automate phishing schemes, advance malware, or carry out cyber-attacks that are more

effective and more difficult to detect or stop. Such an outcome would have a material adverse impact on our business, results of

operations, financial condition, cash flows or prospects.

In addition, confidential or financial payment information that we maintain may be subject to misappropriation, theft and deliberate or

unintentional misuse by current or former employees, third-party contractors or other parties who have had access to such information.

Any such misappropriation and/or misuse of our information could result in the Company, among other things, being in breach of

certain data protection requirements and related legislation as well as incurring liability to third parties. We expect that we will need to

continue closely monitoring the accessibility and use of confidential information in our business, educate our employees and third-

party contractors about the risks and consequences of any misuse of confidential information and, to the extent necessary, pursue legal

or other remedies to enforce our policies and deter future misuse. If our confidential information is misappropriated, stolen or misused

as a result of a disruption to our website or internal systems this could have a material adverse effect on our business, results of

operations, financial condition, cash flows or prospects.

Although we maintain insurance to protect against losses resulting from certain of data protection breaches and cyber-attacks, our

coverage for protecting against such risks may not be sufficient.

Our operations are subject to the risk of litigation.

From time to time, we may be subject, directly or indirectly, to litigation arising out of our operations and the regulatory environments

in our areas of operations. Historically, categories of litigation that we have faced included actions by royalty owners over payment

disputes, personal injury claims and property related claims, including claims over property damage, trespass or nuisance. Although

we currently face no material litigation that is reasonably expected to have an adverse material impact for which we are not

sufficiently indemnified or insured, damages claimed under such litigation in the future may be material or may be indeterminate, and

the outcome of such litigation, if determined adversely to us, could individually or in the aggregate, be reasonably expected to have a

material and adverse effect on our business, financial position or results of operations. While we assess the merits of each lawsuit and

defend ourselves accordingly, we may be required to incur significant expenses or devote significant resources to defend against such

litigation. In addition, the adverse publicity surrounding such claims may have a material adverse effect on our business.

We are subject to certain tax risks.

Tax legislation may be enacted in the future that could negatively impact our current or future tax structure and effective tax rates.

Following the completion of the U.S. Domestication, our public holding company is a U.S. corporation. Accordingly, any changes in

U.S. federal income tax law could negatively impact our effective tax rate and cash flows, which could cause our business, results of

operations, financial condition, cash flows or prospects to be materially adversely affected.

We are subject to income taxes in the United States, and there can be no certainty that the current taxation regime in the United States

or other jurisdictions within which we currently operate or may operate in the future will remain in force or that the current levels of

corporation taxation will remain unchanged. For example, the U.S. government has imposed a minimum tax on corporations and

proposed and may enact significant changes to the taxation of business entities, including, among others, an increase in the U.S.

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federal income tax rate applicable to corporations, like us, and surtaxes on certain types of income. Certain U.S. localities also

maintain a severance tax or impact fee on the removal of oil and natural gas from the ground, and such tax rates may be increased or

new severance taxes or impact fees may be implemented.

Our domestic tax liabilities are subject to the allocation of expenses in differing jurisdictions. Our effective tax rate could be adversely

affected by changes in the mix of earnings and losses in taxing jurisdictions with differing statutory tax rates, certain non-deductible

expenses, the valuation of deferred tax assets and liabilities and changes in federal or state tax laws and accounting principles.

Increases in our effective tax rate could materially affect our net financial results. Although we believe that our income tax liabilities

are reasonably estimated and accounted for in accordance with applicable laws and principles, an adverse resolution of one or more

uncertain tax positions in any period could have a material adverse effect on our business, results of operations, financial condition,

cash flows or prospects.

In the past, we have been able to offset a large portion of our U.S. federal income tax burden with marginal well tax credits that are

available to qualified producers who operate lower-volume wells during a low commodity pricing environment. There can be no

assurance that there will be no amendment to the existing taxation laws applicable to us, which may have a material adverse effect on

our financial position. Our ability to utilize marginal well tax credits in the United States could be or become subject to limitations (for

example, if we are deemed to undergo an “ownership change” for applicable U.S. federal income tax purposes).

The nature and amount of tax that we expect to pay and the tax attributes expected to be available to us are each dependent upon

several assumptions, any one of which may change and which would, if so changed, affect the nature and amount of tax payable and

tax attributes available.

Risks Relating to Our Common Stock

The expected benefits of the U.S. Domestication may not be realized.

On November 21, 2025, we completed the U.S. Domestication following our Board’s conclusion that the U.S. market is the natural

long term primary listing venue for the Company and that moving to a US primary listing (while retaining a secondary UK listing) is

in the best interests of the business and its stakeholders. We believe that the U.S. Domestication and moving to a U.S. primary listing

will increase access to a broader set of investors, support inclusion in additional stock indices, streamline our corporate structure, and

provide more flexibility in accessing capital and, as a result, will be beneficial to our business and operations, the holders of our

common stock, and other stakeholders. The success of the U.S. Domestication and moving to a U.S. primary listing will depend, in

part, on our ability to realize the anticipated benefits associated with the U.S. Domestication and associated reorganization of our

corporate structure. There can be no assurance that all of the anticipated benefits of the U.S. Domestication and moving to a U.S.

primary listing will be achieved, particularly as the achievement of the benefits are subject to factors that we do not and cannot

control.

We expect to incur additional costs related to the U.S. Domestication, including non-recurring costs as well as recurring costs a

result of financial reporting obligations of being a “domestic issuer” as opposed to a “foreign private issuer” in the United

States.

We will incur additional legal, accounting and other expenses that may exceed the expenses we incurred prior to the U.S.

Domestication. The obligations of being a public company in the U.S. require significant expenditures and will place significant

demands on our management and other personnel, including costs resulting from public company reporting obligations under the

Exchange Act, and the rules and regulations regarding corporate governance practices, including those under the Sarbanes-Oxley Act

of 2002 (the “Sarbanes-Oxley Act”), the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, and the listing

requirements of the New York Stock Exchange (“NYSE”). Additionally, as we are retaining a secondary UK listing, we will also need

to continue to comply with certain UK Listing Rules and certain other applicable requirements.

These rules require that we maintain effective disclosure and financial controls and procedures, internal control over financial

reporting and changes in corporate governance practices, among many other complex rules that are often difficult to monitor and

maintain compliance with. While we were subject to many of these requirements prior to the U.S. Domestication, additional legal and

accounting requirements will apply to us following the U.S. Domestication. Our management and other personnel will need to devote

additional time to ensure compliance with all of these requirements and to keep pace with new regulations, otherwise we may fall out

of compliance and risk becoming subject to litigation or being delisted, among other potential problems.

The requirements of being a public company, including additional rules and regulations that we must comply with now that

we are no longer a foreign private issuer, may strain our resources, divert management’s attention, and affect our ability to

attract and retain executive officers and qualified board members.

We are subject to the reporting requirements of the Exchange Act, the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and

Consumer Protection Act of 2010, the listing requirements of the NYSE and other applicable securities rules and regulations, as well

as certain UK Listing Rules. Compliance with these rules and regulations has increased our legal and financial compliance costs,

making some activities more difficult, time-consuming, and costly, and has increased demand on our systems and resources. The

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Exchange Act requires, among other things, that we file annual reports with respect to our business and results of operations. The

Sarbanes-Oxley Act requires, among other things, that we maintain effective disclosure controls and procedures and internal control

over financial reporting. In order to maintain and, if required, improve our disclosure controls and procedures and internal control over

financial reporting to meet this standard, significant resources and management oversight is required.

Additionally, as of November 21, 2025, we are no longer a foreign private issuer, and we are required to comply with all of the

provisions applicable to a U.S. domestic issuer under the Exchange Act, including filing an annual report on Form 10-K, quarterly

periodic reports and current reports for certain events, complying with the sections of the Exchange Act regulating the solicitation of

proxies, requiring insiders to file public reports of their share ownership and trading activities and insiders being liable for profit from

trades made in a short period of time. We are also no longer exempt from the requirements of Regulation FD promulgated under the

Exchange Act related to selective disclosures. We are also no longer permitted to follow the UK’s rules in lieu of the corporate

governance obligations imposed by the NYSE, and are required to comply with the governance practices required by U.S. domestic

issuers listed on the NYSE. We are also required to comply with all other rules of the NYSE applicable to U.S. domestic issuers. In

addition, we are required to report our financial results under GAAP, including our historical financial results, which have previously

been prepared in accordance with IFRS.

The regulatory and compliance costs associated with the reporting and governance requirements applicable to U.S. domestic issuers

may be significantly higher than the costs we previously incurred as a foreign private issuer. We expect to continue to incur significant

legal, accounting, insurance and other expenses and to expend greater time and resources to comply with these requirements.

Additionally, as a result of the complexity involved in complying with the rules and regulations applicable to public companies, our

management’s attention may be diverted from other business concerns, which could harm our business, results of operations and

financial condition. In addition, the pressures of operating a public company may divert management’s attention to delivering short-

term results, instead of focusing on long-term strategy. In addition, we may need to develop our reporting and compliance

infrastructure and may face challenges in complying with the new requirements applicable to us. If we fall out of compliance, we risk

becoming subject to litigation or being delisted, among other potential problems.

We face various cybersecurity risks due to the threat and sophistication of cybercrime. A cybersecurity breach, incident, or failure of

our IT systems could disrupt our businesses, put employees or others at risk, result in the disclosure of confidential information,

damage our reputation, and create significant financial and legal exposure for DEC.

Governance

Our Chief Information Security Officer oversees our cybersecurity program. He is responsible for creating and executing the

cybersecurity strategy that is aligned with our technology posture while also accountable for the detection, mitigation and remediation

of cybersecurity incidents. Our Chief Information Security Officer has over 25 years of experience in the oil and gas industry with

numerous leadership positions from digital transformation to cybersecurity at large E&P companies and in consulting. Our

Information Security Management Team, which includes certain members of the Senior Leadership Team including the Chief

Financial Officer, Chief Operating Officer, Chief Information Officer, Head of Internal Audit, Chief Information Security Officer,

Chief Legal and Risk Officer, meets at least once a quarter to discuss cybersecurity issues, risks and strategies.

The Audit Committee of the Board of Directors provides oversight of our cybersecurity risk management efforts, and receives regular

reports from our Information Security Management Team on information security matters, including assessing risks, efforts to

improve our network security systems and enhanced employee trainings. The membership of this committee is adequately trained and

educated to provide proper oversight over the cybersecurity program utilizing the National Institute of Standards and Technology

framework.

Risk Management & Strategy

Our Information Security Management Team engages in robust processes for assessing and overseeing cybersecurity risks. The

Information Security Team uses advanced network security detection with regular threat testing to detect cybersecurity threats and is

responsible for controlling and protecting our confidential information. They are responsible for testing our cybersecurity crisis

management and business continuity teams including conducting tabletop exercises biennially. The Information Security Team

oversees our IT Security Policy, which includes measures to protect against cyber-attacks, and updates it on an annual basis. They also

regularly engage with key technology partners and suppliers to ensure potentially vulnerable systems are identified and secured. In

addition, we have robust mandatory employee training, phishing simulations, and e-learning sessions delivered quarterly by our digital

security team.

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Through the date of this report, there were no cybersecurity incidents that have materially affected or are reasonably likely to

materially affect the Company or our strategy, financial condition, or results of operations. However, the scope and impact of any

future incident cannot be predicted. Refer to Item 1A. Risk Factors of this Annual Report on Form 10-K for more information on our

cybersecurity related risks.

Information regarding our properties is included in Item 1. Business and in Supplemental Natural Gas & Oil Information in Part II.

We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those

that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas exploration and

development industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to crude

oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third

parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and

any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely,

will have a material adverse effect on our financial condition, results of operations or cash flows.

Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the

proceedings involve potential monetary sanctions that we reasonably believe could exceed a specified threshold. Pursuant to Item 103

of Regulation S-K, we have elected to apply a threshold of $1.0 million for purposes of determining whether disclosure of any such

proceedings is required. Applying this threshold, we are not aware of any such proceedings.

Operations

The following discussion and analysis of financial condition and results of operations should be read in conjunction with the

Consolidated Financial Statements and the notes thereto included in this report. Unless the context otherwise indicates, references to

“Diversified,” the “Company,” “our,” “we” and “us” (i) for periods until the completion of the U.S. Domestication, refer to

Diversified Energy Company PLC and its consolidated subsidiaries, collectively, and (ii) for periods at or after the completion of the

U.S. Domestication, refer to Diversified Energy Company and its consolidated subsidiaries, collectively. For certain industry specific

terms used in this Annual Report on Form 10-K, please refer to the Glossary of Terms.

In this discussion and analysis of financial condition and results of operations, we address topics such as acquisitions, tax matters,

derivatives, stockholders’ equity, asset retirement obligations, and debt. For more detailed information on these areas, refer to Notes

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3, 4, 8, 11, 13, and 15 within the Notes to the Consolidated Financial Statements. These notes provide comprehensive disclosures and

explanations that support the analysis presented in this section.

Market Conditions

Our business was influenced by a range of external factors in 2025, including commodity price volatility, geopolitical developments,

regulatory changes, and evolving supply and demand dynamics. As a U.S. domestic energy producer focused primarily on natural gas,

we benefited from strong LNG export demand and colder-than-average weather, which supported an average Henry Hub price of

approximately $3.43 per MMBtu for the year. Prices fluctuated from an average high of $4.42 per MMBtu in December to an average

low of $2.84 per MMBtu in October. Year-end inventories were above the five-year average, contributing to price stability despite

ongoing global tensions.

Geopolitical conflicts, such as the Russia-Ukraine war and instability in the Middle East and Venezuela, continued to disrupt global

energy flows and underscored the strategic importance of U.S. energy production and exports. Domestically, policy shifts created a

more favorable operating environment, although new tariffs on imported energy equipment and materials introduced some uncertainty

for the industry. Our vertically integrated model helped insulate us from direct impacts, and our hedging program played a key role in

mitigating commodity price risk and supporting cash flow stability.

We also monitored inflationary pressures and supply chain challenges, which affected operating costs across the industry. Despite

ongoing market volatility and policy uncertainty, we remain focused on optimizing our asset base, managing costs, and enhancing

operational efficiency. Our integrated model and strategic positioning continue to enable us to navigate market fluctuations and

capitalize on long-term opportunities in the natural gas and oil sector.

Results of Operations for the Year Ended December 31, 2025 Compared to the Year Ended December 31,

2024

Production Volumes

The increase in production volumes for the year ended December 31, 2025 compared to the year ended December 31, 2024 was

primarily related to the Maverick and Canvas acquisitions in 2025, as well as full year production for Oaktree, Crescent Pass, and East

Texas II acquisitions completed in 2024, partially offset by normal production declines.

Commodity Pricing

Commodity prices fluctuate due to a variety of factors we can neither control nor predict, including increased production in excess of

demand of natural gas, NGLs or oil, weather conditions, political and economic events, and competition from other energy sources.

These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the

prices we realize for our production are affected by our derivative activities and commodity trades by non-physical trading entities, as

well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price

environment and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.

The following table summarizes our average realized sales prices and benchmark prices for the periods presented:

39

Commodity Revenue

The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) by reflecting the

effect of changes in volume and in the underlying prices:

(In thousands)

Commodity revenue of $1,539 million for the year ended December 31, 2025 increased $807 million, or 110%, compared to $732

million for the year ended December 31, 2024. The increase in commodity revenue was primarily related to the 53% increase in

average realized sales prices, excluding the impact of derivatives settled in cash, and the 37% increase in sold volumes primarily due

to acquisitions as discussed above.

Commodity Derivatives

To manage our cash flows in a volatile commodity price environment, we utilize derivative hedging contracts that allow us to fix the

per unit sales prices for our production. As of December 31, 2025, approximately 80% of our production was fixed through derivative

hedging contracts over the next twelve months. The tables below set forth the commodity hedge impact on commodity revenue,

excluding and including cash received for commodity hedge settlements:

(In thousands, except per unit data)

(In thousands, except per unit data)

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Gain (Loss) on Derivatives

The table below sets forth the impact of settlements and fair value adjustments on derivatives for the periods presented:

(In thousands)

(a) Represents the cash settlement of derivatives that settled during the period.

(b) Represents the change in fair value of derivatives net of removing the carrying value of derivatives that settled during the period.

The change in this metric was primarily related to an increase in the value of unsettled derivatives, which had a gain of $194 million in

2025 compared to a loss of $189 million in 2024, a change of $383 million, as a result of decreases along the forward commodity

curve. This change was partially offset by a $128 million decrease in gains on settled derivatives as a result of increased commodity

pricing.

Operating Expenses

(In thousands, except per unit data)

Lease Operating Expense (“LOE”): LOE includes costs incurred to maintain producing properties. Such costs include direct and

contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.

The increase in LOE was driven by the acquisitions of Maverick and Canvas. Specifically, the increase in LOE per Mcfe was

primarily related to a greater exposure to liquids production. Areas with higher liquids output tend to incur elevated operating costs,

although they also benefit from higher realized prices. In 2025, the Company’s liquids production grew by 122% compared to 2024,

primarily driven by the acquisitions of Maverick and Canvas.

Production Taxes: Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural

gas, NGLs and oil production at fixed rates established by federal, state, or local taxing authorities. Property taxes are generally

based on the taxing jurisdictions’ valuation of our natural gas and oil properties and midstream assets.

The increase in production taxes and production taxes per Mcfe was primarily related to an increase in severance and property taxes as

a result of an increase in revenue due to higher commodity prices and the additional value of added oil revenue, as well as additional

property taxes on assets acquired during the year.

Midstream Operating Expense: Midstream operating expenses are costs incurred to operate our owned midstream assets inclusive of

employee and benefit expenses.

The decrease in midstream operating expense per Mcfe was primarily related to maintaining a consistent level of midstream assets

while increasing overall production in 2025, following the acquisitions of Summit, Maverick, and Canvas. By keeping midstream

operations relatively unchanged and expanding production volumes, the per unit cost of midstream operations declined.

41

Transportation Expense: Transportation expenses are costs incurred from third-party systems to gather, process and transport our

natural gas, NGLs and oil.

The increase in transportation expense was driven by the acquisitions of Maverick and Canvas. The decrease in transportation expense

per Mcfe was primarily related to additional liquids production. Transportation costs are primarily associated with the movement of

natural gas volumes. Following the acquisitions of Maverick and Canvas, the proportion of liquids in the Company’s overall

production mix has risen significantly. Specifically, the liquids share increased to 25% in 2025 from 16% in 2024.

Accretion of Asset Retirement Obligation (“Accretion”): Accretion represents the change in the carrying amount of the asset

retirement obligation (“ARO”) over time. This expense reflects the gradual recognition of the future costs associated with retiring

natural gas and oil wells.

The increase in accretion was primarily related to the expanded obligation as a result of the Summit, Maverick, and Canvas

acquisitions during 2025, as well as normal revisions.

General & Administrative Expense (“G&A”): G&A includes overhead, including payroll and benefits for our corporate staff, costs of

maintaining our headquarters, costs of managing our operations, franchise taxes, audit and other professional fees, legal compliance,

equity compensation, and non-recurring costs primarily related to acquisitions.

The increase in G&A was the result of the increase in scale, including increased headcount, due to the Summit, Maverick, and Canvas

acquisitions. The decrease in G&A per Mcfe was primarily related to recognizing administrative synergies and leveraging our existing

infrastructure, which offset the acquisition-related increases.

Depreciation, Depletion & Amortization Expense (“DD&A”): DD&A expenses are non-cash charges that allocate the cost of assets

and natural resources over their useful lives, reflecting their wear and tear, usage, or consumption.

The increase in DD&A was primarily related to an increase in our DD&A rate, as well as a 37% increase in production over the

period. The increase in production and the DD&A rate was due to the Summit, Maverick, and Canvas acquisitions, as these led to an

increase in our depreciable base.

Gain (Loss) on Natural Gas and Oil Properties and Equipment: Gains and (losses) on natural gas and oil properties and equipment

represent the difference between cash proceeds and recorded basis of sales of natural gas and oil properties and equipment.

The increase in this metric was primarily related to increased acreage sales, as we strategically pursue the divestiture of select non-

core, undeveloped acreage within our operating portfolio. In 2025, we recognized a gain of $95 million from acreage sales compared

to $27 million in 2024. Additionally, the disposal of various property, plant and equipment in the normal course of business resulted in

a loss on natural gas and oil properties and equipment of $22 million in 2025, compared to $0.9 million in 2024.

Other Income (Expense)

(In thousands)

Interest Expense

(In thousands)

The increase in interest expense was primarily related to the issuance of the ABS X Notes, the assumption of the Maverick ABS Notes

as a result of the Maverick acquisition, the issuance of the Nordic Bonds, and the issuance of the ABS XI Notes in connection with the

Canvas acquisition. The increase was partially offset by lower outstanding balances on our existing ABS structures.

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As of December 31, 2025 and 2024, total borrowings were $3.0 billion and $1.7 billion, respectively. For the year ended

December 31, 2025, the weighted average interest rate on borrowings was 7.61% compared to 7.37% for the year ended December 31,

2024. As of December 31, 2025, 73% of our borrowings resided in non-recourse, fixed-rate, hedge-protected, amortizing structures

compared to 83% as of December 31, 2024.

Loss on Debt Extinguishment

In February 2025, the proceeds from the ABS X Notes were used to repay the outstanding principal of the ABS I & II Notes and Term

Loan I, retiring these from our outstanding debt and resulting in a loss on debt extinguishment of $27 million. In 2024, the loss on debt

extinguishment was primarily driven by the use of proceeds from the ABS VIII Notes to repay the outstanding principal of the ABS

III & V Notes, retiring these from our outstanding debt and resulting in a loss on debt extinguishment of $11 million.

Income Tax Benefit (Expense)

The differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:

(in thousands)

(a) The impact and the presentation of the federal tax credits on our effective tax rate can be positive or negative based on the

Company’s annual pre-tax income or loss.

The effective tax rates for the years ended December 31, 2025 and 2024 were (13.5%) and 58.4%, respectively. The effective tax rates

can be materially impacted by the recognition of the marginal well tax credit available to qualified producers as reflected in our 2025

effective tax rate. The federal government provides these credits to incentivize companies to continue operating lower-output wells

during periods of low prices. This support helps sustain production, preserve the jobs associated with these operations, and ensures

that communities continue to receive state and local tax income. Such revenue is vital for funding schools, law enforcement, social

initiatives, and other essential public services.

State and local income taxes are more than 50% comprised of Oklahoma and West Virginia.

The provision for income taxes in the Consolidated Statement of Operations is summarized below:

(In thousands)

Tax benefit of $41 million for the year ended December 31, 2025 decreased $104 million, or 72%, compared to a benefit of $145

million for the year ended December 31, 2024. The change in this metric was primarily related to the change in the income or loss

before taxation and a change in the effective tax rate.

43

Results of Operations for the Year Ended December 31, 2024 Compared to the Year Ended December 31,

2023

Production Volumes

The decrease in production volumes for the year ended December 31, 2024 compared to the year ended December 31, 2023 was

primarily related to the sale of our equity interest in DP Lion Equity Holdco in December 2023 along with normal declines partially

offset by increased production as a result of the Oaktree, Crescent Pass, and East Texas II acquisitions in 2024.

Commodity Pricing

The following table summarizes our average realized sales prices and benchmark prices for the periods presented:

44

Commodity Revenue

The following table reconciles the change in commodity revenue (excluding the impact of derivatives settled in cash) by reflecting the

effect of changes in volume and in the underlying prices:

(In thousands)

Commodity revenue of $732 million for the year ended December 31, 2024 decreased $70 million, or 9%, compared to $802 million

for the year ended December 31, 2023. The decrease in commodity revenue was primarily related to the 6% decrease in average

realized sales prices, excluding the impact of derivatives settled in cash, and the 3% decrease in sold volumes.

Commodity Derivatives

As of December 31, 2024, approximately 86% of our production was fixed through derivative hedging contracts over the next twelve

months. The tables below set forth the commodity derivative impact on commodity revenue, excluding and including cash received for

commodity derivative settlements:

(In thousands, except per unit data)

(In thousands, except per unit data)

Gain (Loss) on Derivatives

The table below sets for the impact of settlements and fair value adjustments on derivatives for the periods presented:

(In thousands)

(a) Represents the cash settlement of derivatives that settled during the period.

(b) Represents the change in fair value of derivatives net of removing the carrying value of derivatives that settled during the period.

The change in this metric was primarily related to losses of $189 million stemming from fair value adjustments on unsettled

derivatives, which were influenced by an increase along the forward commodity curve. The losses were offset by $151 million in gains

45

incurred from settled derivative contracts, as commodity market prices dropped below the predetermined thresholds set in our

derivative arrangements.

Operating Expenses

(In thousands, except per unit data)

Lease Operating Expense (“LOE”): LOE includes costs incurred to maintain producing properties. Such costs include direct and

contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.

The increase in LOE per Mcfe was primarily related to the Oaktree, Crescent Pass, and East Texas II acquisitions in 2024.

Specifically, these acquisitions resulted in a greater exposure to liquids production, which tend to incur elevated operating costs.

Production Taxes: Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural

gas, NGLs and oil production at fixed rates established by federal, state, or local taxing authorities. Property taxes are generally

based on the taxing jurisdictions’ valuation of our natural gas and oil properties and midstream assets.

The decrease in production taxes per Mcfe was primarily related to a decrease in severance and property taxes as a result of a decrease

in revenue due to lower production and commodity prices, as well as lower valuations for property taxes experienced during the year.

Midstream Operating Expense: Midstream operating expenses are costs incurred to operate our owned midstream assets inclusive of

employee and benefit expenses.

The increase in midstream operating expense per Mcfe was primarily related to growth in our midstream operations due to Central

Region expansion through the acquisitions of Oaktree, Crescent Pass, and East Texas II.

Transportation Expense: Transportation expenses are costs incurred from third-party systems to gather, process and transport our

natural gas, NGLs and oil.

The decrease in transportation expense per Mcfe was primarily related to decreases in commodity price-linked components of third-

party midstream rates and costs.

Accretion of Asset Retirement Obligation (“Accretion”): Accretion represents the change in the carrying amount of the asset

retirement obligation (“ARO”) over time. This expense reflects the gradual recognition of the future costs associated with retiring

natural gas and oil wells.

The increase in accretion was primarily related to the inclusion of assets from the Oaktree, Crescent Pass, and East Texas II

acquisitions, along with normal declines in production from mature wells.

General & Administrative Expense (“G&A”): G&A includes overhead, including payroll and benefits for our corporate staff, costs of

maintaining our headquarters, costs of managing our operations, franchise taxes, audit and other professional fees, legal compliance,

equity compensation, and non-recurring costs primarily related to acquisitions.

The increase in G&A per MCFe was primarily related to additional administrative costs and professional services to support our

ongoing growth through acquisitions. Additionally, we also experienced increased costs associated with litigation expense. These

increases were partially offset by a reduction in legal and consulting services.

46

Depreciation, Depletion & Amortization Expense (“DD&A”): DD&A expenses are non-cash charges that allocate the cost of assets

and natural resources over their useful lives, reflecting their wear and tear, usage, or consumption.

The increase in DD&A was primarily related to an increase in our DD&A rate, which was partially offset by a 3% decrease in

production over the period. The increase in our DD&A rate was due to the decrease in our estimated proved reserves relative to our

depreciable base, driven primarily by changes in commodity prices year-over-year as well as the sale of equity interest in DP Lion

Equity Holdco LLC in December 2023. The decrease in proved reserves was partially offset by the acquisition of the Oaktree,

Crescent Pass, and East Texas II assets in 2024.

Gain (Loss) on Natural Gas and Oil Properties and Equipment: Gains and (losses) on natural gas and oil properties and equipment

represents the difference between cash proceeds and recorded basis of sales of natural gas and oil properties and equipment.

The change in this metric was primarily related to non-core acreage and asset sales. In 2024, we recognized a gain of $27 million from

acreage sales compared to $24 million in 2023. This increase was offset by the disposal of various property, plant and equipment in

the normal course of business, which resulted in a loss on natural gas and oil properties and equipment of $0.9 million in 2024,

compared to a gain of $4.6 million in 2023.

Other Income (Expense)

(In thousands)

Gain (Loss) on Sale of Equity Interest

The change in this metric is related to the divestiture of 80% of the equity ownership in DP Lion Equity Holdco LLC to outside

investors, which generated cash proceeds of $30 million. The consideration exceeded the fair value of the Company’s portion of the

assets and liabilities divested resulting in a gain on sale of the equity interest of $11 million.

Interest Expense

(In thousands)

The increase in interest expense was primarily related to interest on the new ABS IX Notes, Oaktree Seller’s Note, and Term Loan II.

The increase was partially offset by lower outstanding balances on our existing ABS structures.

As of December 31, 2024 and 2023, total borrowings were $1.7 billion and $1.3 billion, respectively. For the year ended

December 31, 2024, the weighted average interest rate on borrowings was 7.37% compared to 6.03% for the year ended December 31,

2023. As of December 31, 2024, 83% of our borrowings resided in fixed-rate, hedge-protected, amortizing structures compared to

87% as of December 31, 2023.

Loss on Debt Extinguishment

The change in this metric was primarily related to losses recognized on the early retirement of debt in 2024. During the year, we

repaid the ABS III and ABS V notes using proceeds from new ABS VIII issuance, resulting in a loss of $10.6 million. We also repaid

the ABS Facility Warehouse Notes using proceeds from the ABS IX issuance, resulting in a loss of $1.6 million. Additionally, the

amendment and expansion of Term Loan II led to a further loss of $2.5 million. The amendment to the Credit Facility also resulted in

a loss of $1.6 million

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Other Income (Expense)

The change in this metric was primarily related to $1.1 million in dividend distributions received from our investment in DP Lion

Equity Holdco during 2024, whereas no such distributions were received in 2023.

Income Tax Benefit (Expense)

The differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:

(in thousands)

(a) The impact and the presentation of the federal tax credits on our effective tax rate can be positive or negative based on the

Company’s annual pre-tax income or loss.

The effective tax rates for the years ended December 31, 2024 and 2023 were 58.4% and 24.2%, respectively. The effective tax rate

can be materially impacted by the recognition of the marginal well tax credit available to qualified producers as reflected in our 2024

effective tax rate. A marginal well tax credit was not available for the 2023 tax year. The federal government provides these credits to

incentivize companies to continue operating lower-output wells during periods of low prices. This support helps sustain production,

preserve the jobs associated with these operations, and ensures that communities continue to receive state and local tax income. Such

revenue is vital for funding schools, law enforcement, social initiatives, and other essential public services.

State and local income taxes are more than 50% comprised of Oklahoma and West Virginia.

The provision for income taxes in the Consolidated Statement of Operations is summarized below:

(In thousands)

Tax benefit of $145 million for the year ended December 31, 2024 changed $384 million, or 161%, compared to an expense of $239

million for the year ended December 31, 2024. The change in this metric was primarily related to the change in the income or loss

before taxation and a change in the effective tax rate.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operating activities and available capacity under our Credit Facility. As of

December 31, 2025, we had approximately $335 million of liquidity, consisting of $30 million of cash on hand and $305 million of

availability under our Credit Facility. As of February 25, 2026 we had approximately $577 million of liquidity, consisting of $31

million of cash on hand and $546 million of availability under our Credit Facility.

48

When we acquire assets, we typically complement our Credit Facility with long-term, fixed-rate, fully-amortizing, asset-backed debt

secured by certain natural gas and oil assets. The asset-backed debt is non-recourse back to the Company. This financing strategy

aligns with the long-life nature of our assets, offering us lower borrowing rates and a clear path to reduce leverage through scheduled

principal payments. For larger acquisitions that require greater capital outlays, we have in the past and may in the future raise funds

through equity offerings to maintain an appropriate leverage profile.

We closely monitor our working capital to ensure it remains sufficient for business operations, as well as for payment of dividends to

shareholders and repurchases of common stock. Alongside managing working capital, we take a disciplined approach to controlling

operating costs and allocating capital resources. This approach ensures that capital investments generate returns that support our

strategic initiatives.

Capital expenditures were $185 million for the year ended December 31, 2025, compared to $52 million for the year ended

December 31, 2024. The increase in capital expenditures was primarily related to the development of new wells via a non-operated

development agreement that came with the undeveloped locations acquired in the Maverick acquisition. We expect to meet our capital

expenditure needs for the foreseeable future from our operating cash flows and our existing cash and cash equivalents. Our future

capital requirements will depend on several factors, including the pace of our growth, fluctuations in commodity prices, and future

acquisitions.

The majority of our capital expenditures are directed towards upstream and midstream operations, including pipelines and

compression. The remaining expenditures focus on production optimization, technology, plugging requirements, fleet, reducing

emissions, and, when prudent, development activities aimed at replacing production. Our strategy to acquire and operate mature wells

with shallow decline rates allows us to avoid the large capital expenditures associated with drilling and completion activities of

development focused companies.

Looking ahead, we aim to create stable cash flows by maintaining our hedging strategy and capitalizing on market opportunities to

enhance the hedged commodity prices of our production. We plan to preserve our strategic advantages through purposeful growth,

supported by a disciplined capital expenditure program. We believe this approach will help ensure we secure low-cost financing for

acquisitive growth while maintaining appropriate leverage and sufficient liquidity.

With respect to other known current obligations, we believe that our sources of liquidity and capital resources will be sufficient to

meet our existing business needs for at least the next 12 months. However, our ability to satisfy our working capital requirements, debt

service obligations, and planned capital expenditures will depend upon our future operating performance, which will be affected by

prevailing economic conditions in the natural gas and oil industry and other financial and business factors, some of which are beyond

our control.

Liquidity

(In thousands)

(a) Represents available borrowings under the Credit Facility of $340 million as of December 31, 2025 less outstanding letters of

credit of $35 million as of such date. Represents available borrowings under the Credit Facility of $101 million as of

December 31, 2024 less outstanding letters of credit of $14 million as of such date. Represents available borrowings under the

Credit Facility of $146 million as of December 31, 2023 less outstanding letters of credit of $11 million as of such date.

Debt

As of December 31, 2025, 2024, and 2023, we had $3.0 billion, $1.7 billion and $1.3 billion in total debt outstanding, respectively.

Asset Retirement Obligations

As of December 31, 2025, 2024, and 2023, we had $864 million, $619 million and $463 million in total asset retirement obligations on

a discounted basis, respectively.

49

Cash Flows

(In thousands)

Net Cash Provided by Operating Activities

The change in net cash provided by operating activities was primarily related to an increase in production, as a result of current year

acquisitions, and higher prices for the natural gas, NGL, and oil volumes sold.

Net Cash (Used in) Investing Activities

The change in net cash used in investing activities was primarily related to the acquisitions of Summit, Maverick, and Canvas in the

current year, in addition to increased drilling capital spend related to participating in the development of certain non-operated wells

acquired with Maverick. These increases were partially offset by increased cash proceeds from the sale of undeveloped acreage.

Net Cash Provided by Financing Activities

The increase in net cash provided by financing activities was primarily related to an increase in ABS activity during the year,

associated with both acquisitions and refinancings, as well as proceeds from the April Nordic Bonds issuance and the February equity

issuance. These increases were partially offset by cash outflows related to hedge modifications associated with the ABS refinancings.

(In thousands)

Net Cash Provided by Operating Activities

The change in net cash provided by operating activities was primarily related to lower prices for the natural gas, NGL, and oil volumes

sold.

Net Cash (Used in) Investing Activities

The change in net cash used in investing activities was primarily related to a net increase in cash outflows for acquisitions, divestitures

and disposal activity, which was partially offset by a decrease in cash outflows for capital expenditures, due to decreased development

activity in 2024.

Net Cash Provided by (Used in) Financing Activities

The increase in net cash provided by (used in) financing activities was primarily related to an increase in ABS activity during the year,

associated with both acquisitions and refinancings, which provided net proceeds. Also contributing to the increase was a reduction in

dividends paid in 2024. Partially offsetting these increases was a decrease in equity proceeds as a result of the 2023 equity issuance.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that give rise to material off-balance sheet obligations. As of

December 31, 2025 and December 31, 2024, our material off-balance sheet arrangements and transactions include operating service

arrangements of $371 million and letters of credit outstanding against our Credit Facility of $35 million. Refer to Contractual

Obligations for additional information.

There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably

likely to materially affect our liquidity or availability of capital resources.

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Contractual Obligations

We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual

obligations as of December 31, 2025 were as follows:

(In thousands)

(a) Represents our asset retirement obligation on an undiscounted basis. On a discounted basis the liability is $889 million as of

December 31, 2025 as presented in the Consolidated Balance Sheets.

(b) Represents taxes payable, deferred tax liability, and other current and noncurrent liabilities.

(c) Represents reserved capacity to transport gas from production locations through pipelines to the ultimate sales meters.

For more detailed information on asset retirement obligations, leases, debt, accounts payable and accrued liabilities, and other

liabilities, refer to Notes 13, 14, 15, 16, and 17 within the Notes to the Consolidated Financial Statements.

Litigation and Regulatory Proceedings & Environmental Matters

For Information regarding legal proceedings and environmental matters refer to Note 19 to the Notes to the Consolidated Financial

Statements.

Critical Accounting Estimates & Judgments

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions. The accounting

estimates and assumptions that involve a significant level of estimation uncertainty and have or are reasonably likely to have a

material impact on our financial condition or results of operations are discussed below.

For discussion regarding our significant accounting policies, refer to Note 2 in the Notes to the Consolidated Financial Statements for

additional information regarding our significant accounting policies, estimates, and judgments.

Natural Gas and Oil Reserves

Estimates of proved natural gas and oil reserves are used in calculating DD&A of proved natural gas and oil property costs, the present

value of estimated future net revenues, estimates of future taxable income used in assessing the realizability of deferred tax assets, and

the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the

estimation of proved natural gas and oil reserves and in the projection of future rates of production.

The process of estimating proved natural gas and oil reserves requires that our independent and internal reserve engineers exercise

judgment on the future production rates. The accuracy of any reserve estimate is a function of the quality of data available and of

engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production,

results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These

revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent

in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from

our estimates. See Supplemental Natural Gas & Oil Information included in Item 8 of Part II of this report for further information.

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Impairment of Proved Properties

We assess our proved natural gas and oil properties for impairment on an asset group basis whenever events and circumstances

indicate that there could be a possible decline in the recoverability of the net book value of such property. We estimate the expected

future net cash flows of our proved natural gas and oil properties and compare these undiscounted cash flows to the net book value of

the proved natural gas and oil properties to determine if the net book value is recoverable. If the net book value exceeds the estimated

undiscounted future net cash flows, we will recognize an impairment to reduce the net book value of the proved natural gas and oil

properties to fair value. The assumptions used to determine fair value include, but are not limited to, future commodity prices, future

production estimates, operating costs, and discount rates, which are based on a weighted average cost of capital. Fair value estimates

are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment is

measured.

Business Combinations

We account for business combinations using the acquisition method, which is the only method permitted under FASB ASC Topic 805,

Business Combinations and involves the use of significant judgment. Under the acquisition method of accounting, a business

combination is accounted for at a purchase price based on the fair value of the consideration given. The assets and liabilities acquired

are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The

excess, if any, of the consideration given to acquire an entity over the net amounts assigned to its assets acquired and liabilities

assumed is recognized as goodwill. The excess, if any, of the fair value of assets acquired and liabilities assumed over the cost of an

acquired entity is recognized immediately to earnings as a gain on bargain purchase.

The Company’s principal assets are its natural gas and oil properties, which are accounted for under the successful efforts accounting

method. The Company determines the fair value of acquired proved natural gas and oil properties based on the discounted future net

cash flows expected to be generated from these assets. Discounted cash flow models by operating area are prepared using the

estimated future revenues and operating costs for all proved developed properties and undeveloped properties comprising the proved

reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) future

production volumes based on estimated reserves, (ii) future operating and development costs, (iii) future commodity prices escalated

by an inflationary rate after five years, adjusted for differentials, and (iv) a market-based weighted average cost of capital by operating

area. The Company utilizes NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs

used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount

rates utilized are derived using a weighted average cost of capital computation, which includes an estimated cost of debt and equity for

market participants with similar geographies and asset development type by operating area. Additionally, the fair value of unproved oil

and gas properties is determined using a market approach, which considers recent comparable transactions for similar assets. More

information regarding conclusions reached with respect to this judgment is included in Note 2 to the Notes to the Consolidated

Financial Statements.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions.

We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We

routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have

recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. In assessing the

need for a valuation allowance or adjustments to existing valuation allowances, we consider a variety of positive and negative

evidence, which may include a projection of income exclusive of existing timing differences. Our judgment regarding the realizability

of deferred tax assets is thus partially affected by estimates of future financial results.

Management monitors company-specific, natural gas and oil industry and worldwide economic factors and assesses the likelihood that

our net deferred tax assets will be utilized prior to their expiration. Refer to Note 4 in the Notes to the Consolidated Financial

Statements for additional discussion.

Asset Retirement Obligations

We accrue a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas

wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically

at the time the well is drilled.

Calculating our asset retirement obligations is a "critical accounting estimate" because we must assess the expected amount and timing

of asset retirement obligation settlement. In addition, we must determine the estimated present value of future liabilities. Future results

of operations for any quarterly or annual period could be materially affected by changes in our assumptions. If the expected amount

and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future

periods. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can

materially affect our estimates. Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional discussion.

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Recently Issued Accounting Pronouncements

Refer to Note 2 in the Notes to the Consolidated Financial Statements for information regarding recent accounting pronouncements

applicable to our Consolidated Financial Statements.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our

potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs

and oil prices, as well as interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather

indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our

ongoing market risk exposures.

Commodity Price Risk

Our revenues are primarily derived from the sale of natural gas, NGLs, and oil production, subjecting us to commodity price risk.

Commodity prices for natural gas, NGLs and oil can be volatile and may fluctuate due to relatively small changes in supply, weather

conditions, economic conditions, and government actions. For the year ended December 31, 2025, our natural gas, NGLs, and oil

revenue was $830 million, $208 million, and $501 million, respectively. Based on production, natural gas, NGLs and oil revenue for

the year ended December 31, 2025 would have increased or decreased by approximately $83 million, $21 million, and $50 million,

respectively, for each 10% increase or decrease in prices.

To mitigate the risk of fluctuations in commodity prices, we enter into derivatives. The total volumes hedged through the use of these

instruments vary from period to period. Generally our objective is to hedge approximately 60% to 80% of anticipated production

volumes for the next 12 months, at least 50% for months 13 to 24, and a minimum of 30% for months 25 to 36. For additional

information regarding derivatives, refer to Note 8 in the Notes to the Consolidated Financial Statements.

By removing price volatility from a significant portion of our expected production through 2028, we have mitigated, but not

eliminated, the potential effects of changing prices on operating cash flow for those periods. While these derivative contracts help

mitigate the negative effects of falling commodity prices, they also limit the benefits we would receive from increases in commodity

prices.

As of December 31, 2025, the fair value of our natural gas derivatives was a net liability of $494 million, NGLs derivatives were in a

net asset position of $34 million, and our oil derivatives were in a net asset position of $99 million. For the year ended December 31,

2025, a 10% fluctuation in commodity prices would have a corresponding impact of approximately $49 million, $3 million, and $10

million on natural gas, NGLs and oil derivatives, respectively.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates. Our borrowings primarily consist of fixed-rate amortizing

notes and a variable rate Credit Facility as illustrated below.

(in thousands)

(a) The interest rate on the ABS Notes, Nordic Bonds, and other notes payable represents the weighted average fixed rate of the

notes, while the interest rate presented for the Credit Facility represents the floating rate as of December 31, 2025.

(b) Includes $23 million in notes payable issued by a third party financial institution in November 2024 collateralized by two natural

gas processing plants and various natural gas compressors and related support equipment in the Central Region, as of

December 31, 2025.

For additional information regarding the ABS notes, Nordic Bonds, and Credit Facility, refer to Note 15 in the Notes to the

Consolidated Financial Statements.

For the year ended December 31, 2025, a 100 basis point adjustment in the borrowing rate for the Credit Facility would result in a

corresponding effect on interest expense of approximately $5 million. This represents a reasonably possible change in interest rate

risk.

We strive to maintain a prudent balance of floating and fixed-rate borrowing exposure, particularly during uncertain market

conditions. As part of our risk mitigation strategy, we occasionally enter into swap arrangements to adjust our exposure to floating or

fixed interest rates, depending on changes in the composition of borrowings in our portfolio. Consequently, the total principal hedged

through the use of derivatives varies from period to period.

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As of December 31, 2025, the fair value of our interest rate swaps represents a liability of $0.1 million. For additional information

regarding derivatives, refer to Note 8 in the Notes to the Consolidated Financial Statements.

Counterparty & Customer Credit Risk

We are exposed to counterparty and customer credit risk from the hedging and sale of our natural gas, NGLs and oil.

Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we only enter into commodity contracts

with counterparties that are highly rated or deemed by us to have acceptable credit strength and competence. Counterparty non-

performance risk is considered in the valuation of our derivative instruments, but has not had an impact on the value of our derivatives.

We also attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2025, our commodity

contracts derivative instruments were spread among 13 counterparties.

For additional information regarding derivatives, refer to Note 8 in the Notes to the Consolidated Financial Statements

Accounts receivable from customers represent amounts due for the purchase of these commodities, and their collectability depends on

the financial condition of each customer. We review the financial condition of customers before extending credit and generally do not

require collateral to support their accounts receivable. As of December 31, 2025, we had no customers that comprised over 10% of our

total accounts receivable from customers. Net of the applicable allowance for credit losses, our accounts receivable from customers

were $347 million as of December 31, 2025.

The Company is also exposed to credit risk from joint interest owners, which are entities that own a working interest in the properties

operated by the Company. Joint interest receivables are classified under accounts receivable, net, in the Consolidated Statement of

Financial Position. The Company has the ability to withhold future revenue payments to recover any non-payment of joint interest

receivables. As of December 31, 2025, our joint interest receivables, net of the applicable allowance for credit losses, were $61

million.

Accounts receivable are current, and the Company believes these net receivables are collectible. For additional information regarding

accounts receivable, refer to Note 9 in the Notes to the Consolidated Financial Statements.

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Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures, as defined in U.S. Securities Exchange Act of 1934, as amended

(“Exchange Act”) Rule 13a-15(e), that are designed to ensure that information required to be disclosed in our reports filed or

submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and

forms of the SEC, and such information is accumulated and communicated to our management, including our Chief Executive Officer

and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Chief Executive Officer and

Chief Financial Officer, with the participation of management, have evaluated the effectiveness of the Company’s disclosure controls

and procedures in relation to Exchange Act Rule 13a-15(b), and have concluded that the Company’s disclosure controls and

procedures were effective as of December 31, 2025.

Management’s Annual Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over

financial reporting is a process, designed by, or under the supervision of, the Chief Executive Officer and Chief Financial Officer, or

persons performing similar functions, and effected by the Company’s board of directors, management and other personnel to provide

reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in

accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those

policies and procedures that:

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the

assets of the Company;

• Provide reasonable assurances that transactions are recorded as necessary to permit the preparation of financial statements in

accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made

only in accordance with the authorizations of management and Directors of the Company; and

• Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use, or disposition of the

Company’s assets that could have a material effect on its financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections

of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in

conditions, or that the degree of compliance with policies and procedures may deteriorate.

Management of the Company evaluated the effectiveness of the Company’s internal control over financial reporting as of

December 31, 2025 based on criteria established in the Internal Control-Integrated Framework (2013), issued by the Committee of

Sponsoring Organizations of the Treadway Commission.

Following this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of

December 31, 2025.

Management’s assessment and conclusion on the effectiveness of the Company’s internal control over financial reporting as of

December 31, 2025 excludes an assessment of the internal control over financial reporting of Canvas Energy, which was acquired in

2025. Canvas Energy is included in our consolidated financial statements and represented approximately 9% of our total assets as of

December 31, 2025 and approximately 1% of our consolidated revenues for the year ended December 31, 2025.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2025, has been audited by

PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8

within this Annual Report on Form 10-K.

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2025, which materially

affected, or were reasonably likely to materially affect, our internal control over financial reporting.