Diversified Energy Co PLC

In assessing our performance, the Directors use key performance indicators (“KPIs”) to track our success against our stated

strategy. The Directors assess our KPIs on an annual basis and modify them as needed, taking into account current business

developments. The following KPIs focus on corporate and environmental responsibility, consistent cash flow generation

underpinned by prudent cost management, low leverage and adequate liquidity to protect the sustainability of the business.

Please refer to the APMs section in Additional Information within this Annual Report & Form 20-F for information on how

these metrics are calculated and reconciled to IFRS measures.

Our Business

HISTORY AND DEVELOPMENT OF THE GROUP

The Group, formerly Diversified Gas & Oil PLC, is an

independent energy company engaged in the production,

transportation and marketing of natural gas as well as oil

from its complementary onshore upstream and midstream

assets, primarily located within the Appalachian and Central

Regions of the United States. Our Appalachia assets consist

primarily of producing wells in conventional reservoirs and

the Marcellus and Utica shales, within Pennsylvania, Ohio,

Virginia, West Virginia, Kentucky, and Tennessee, while our

Central Region, located in Oklahoma, Louisiana, and

portions of Texas, includes producing wells in multiple

producing formations, including the Bossier, Haynesville

Shale and Barnett Shale Plays, as well as the Cotton Valley

and the Mid-Continent producing areas. The Group was

incorporated in 2014 in the United Kingdom, and our

predecessor business was founded in 2001 by our Chief

Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., with

an initial focus on primarily natural gas and also oil

production in West Virginia. In recent years, we have grown

rapidly by capitalizing on opportunities to acquire and

enhance producing assets and leveraging the operating

efficiencies that result from economies of scale. Since 2017,

and through December 31, 2023, we have completed 24

acquisitions for a combined purchase price of

approximately$2.7 billion. We had average daily net

production of 821 MMcfepd and 811 MMcfepd for the years

ended December 31, 2023 and December 31,

2022, respectively.

We have consistently driven our operations towards

sustainability and efficiency throughout our history, but we

believe we are also at the forefront of U.S. natural gas and

oil producers in our commitment to sustainability goals.

While the global energy economy is reliant on natural gas

as an energy source, we believe it is imperative that natural

gas wells and pipelines be operated by responsible owners

with a strong commitment to the environment, and we

believe our operational track record demonstrates that

responsibility and stewardship. Given our operational focus

on efficient, environmentally sound natural gas production,

we believe we are ideally positioned to help serve current

energy demands and play a key role in the clean

energy transition.

Other Information

We were incorporated as a public limited company with the

legal name Diversified Gas & Oil PLC under the laws of the

United Kingdom on July 31, 2014 with the company number

9156132. On May 6, 2021, we changed our company name

to Diversified Energy Company PLC.

Our registered office is located at 4th Floor Phoenix House,

1 Station Hill, Reading, Berkshire United Kingdom, RG1 1NB.

In February 2017, our shares were admitted to trading on

the AIM Market of the London Stock Exchange (“AIM”)

under the ticker “DGOC.” In May 2020, our shares were

admitted to the premium listing of the Official List of the

Financial Conduct Authority and to trading on the Main

Market of the LSE. With the change in corporate name in

2021, our shares listed on the LSE began trading under the

new ticker “DEC.” In December 2023, the Group’s shares

were admitted to trading on the New York Stock Exchange

(“NYSE”) under the ticker “DEC.” As of December 31, 2023,

the principal trading market for the Group’s ordinary shares

was the LSE.

Our principal executive offices are located at 1600

Corporate Drive, Birmingham, Alabama 35242, and our

telephone number at that location is +1 205 408 0909. Our

website address is www.div.energy. The information

contained on, or that can be accessed from, our website

does not form part of this Annual Report & Form 20-F. We

have included our website address solely as an inactive

textual reference.

SafetyNo compromisesEnsuring the care and wellbeing of our employees, our families and our communities is our top priority

ProductionEvery unit countsEnsuring every unit we safely produce provides affordable, reliable energy to our communities and generates value for our shareholders

EfficiencyEvery dollar countsEnsuring every dollar we spend protects our employees, our communities and the investment of our shareholders

EnjoymentHave fun delivering great resultsEnsuring our company is a great place to work, encouraging innovation and celebrating our employees’ accomplishments

BUSINESS OVERVIEW

Our strategy is primarily to acquire and manage natural gas

and oil properties while leveraging our associated

midstream assets to maximize cash flows. We seek to

improve the performance and operations of our acquired

assets through our deployment of rigorous field

management programs and/or refreshing infrastructure.

Through operational efficiencies, we demonstrate our

ability to maximize value by enhancing production while

lowering costs and improving well productivity. We adhere

to stringent operating standards, with a strong focus on

health, safety and the environment to ensure the safety of

our employees and the local communities in which we

operate. We believe that acting as a careful steward of our

assets will improve revenue and margins through captured

natural gas emissions while reducing operating costs, which

benefits our profitability. This focus on operational

excellence, including the aim of reducing natural gas

emissions, also benefits the environment and communities

in which we operate.

OUR BUSINESS STRATEGY

—Optimization of long-life, low-decline assets to enhance

margins and improve cash flow

—Generate consistent shareholder returns through vertical

integration, strategic hedging and cost optimization

—Disciplined growth through accretive acquisitions of

producing assets

—Maintain a strong balance sheet with ability to

opportunistically access capital markets

—Operate assets in a safe, efficient manner with what we

believe are industry-leading sustainability initiatives

OUR STRENGTHS

—Low-risk and low-cost portfolio of assets

—Long-life and low-decline production

—High margin assets benefiting from significant scale and

owned midstream and asset retirement infrastructure

and internal product marketing team

—Highly experienced management and operational team

—Track record of successful consolidation and integration

of acquired assets

OUTLOOK

Looking forward, we will continue to prudently manage our

long-life, low-decline asset portfolio and the consistent

cashflows they produce. We plan to maintain our hedging

strategy to protect cash flow. We will seek to retain our

strategic advantages in purposeful growth through a

disciplined acquisition strategy that continues to secure

low-cost financing that supports acquisitive growth while

maintaining low leverage and ample liquidity. In addition,

we intend to remain proactive in our sustainability

endeavors by seeking to secure future capital allocation for

sustainability initiatives.

RESERVE DATA

Summary of Reserves

The following table presents our estimated net proved reserves, Standardized Measure and PV-10 as of December 31, 2023,

using SEC pricing. Standardized Measure has been presented inclusive and exclusive of taxes and is based on the proved

reserve report as of such date by Netherland, Sewell &Associates, Inc. (“NSAI”), our independent petroleum engineering firm.

A copy of the proved reserve report is included as an exhibit to the Annual Report & Form 20-F. Refer to the Preparation of

Reserve Estimates and Estimation of Proved Reserves sections within this Annual Report & Form 20-F for a definition of

proved reserves and the technologies and economic data used in their estimation.

(a)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 volumes, the average Henry Hub spot price of$2.64 per MMBtu as of December 31, 2023 was adjusted for

gravity, quality, local conditions, gathering and transportation fees, and distance from market. For NGLs and oil volumes, the average WTI

price of$78.21 per Bbl as of December 31, 2023 was similarly 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.

(b)The PV-10 of our proved reserves as of December 31, 2023 was prepared without giving effect totaxes or hedges. PV-10 is a non-GAAP and

non-IFRS 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.

Proved Reserves

As of December 31, 2023, our estimated proved reserves totaled 3,849,946 MMcfe, a decrease of 24% from the prior year-end

with a Standardized Measure of$1.7 billion. Natural gas constituted approximately 83% of our total estimated proved reserves

and 83% of our total estimated proved developed reserves. The following table provides a summary of the changes in our

proved reserves during theyears ended December 31, 2023,2022 and 2021.

Extensions and Discoveries

During 2023,1,012 MMcfe were adjusted due to well assignments recorded in the accounting actuals.

During 2022, we elected to participate in select development activities on a non-operated basis generating 13,326 MMcfe

in reserves.

During 2021, no reserves were added from extension or discovery activities.

Revisions to Previous Estimates

During 2023, we recorded 659,379 MMcfe in revisions to previous estimates. The downward revisions were primarily

associated with changes in the trailing 12-month average realized Henry Hub first day spot price, which decreased

approximately 58% as compared to the December 31, 2022 along with a 17% decrease in the 12 month average WTI first day

spot price. These factors primarily drove a net downward revision that impacted well economics and well life.

During 2022, we recorded 379,812 MMcfe in revisions to previous estimates. These positive performance revisions were

primarily associated with changes in the trailing 12-month average realized Henry Hub spot price, which increased

approximately 77% as compared to the December 31, 2021 Henry Hub spot price due to the war between Russia and Ukraine,

as well as other geopolitical factors. These factors primarily drove a net upward revision of 386,064 MMcfe due to changes in

pricing that impacted well economics. These increases were offset by a 6,252 MMcfe downward revision for changes in timing.

During 2021,541,509 MMcfe in revisions to previous estimates were primarily associated with changes in the 12-month average

realized Henry Hub spot price, which increased approximately 81% as compared to December 31, 2020.

Purchase of Reserves in Place

During 2023,126,803 MMcfe of purchases of reserves in place were associated with the Tanos II acquisition. Refer to Note 5 in

the Notes to the Group Financial Statements for additional information about these acquisitions.

During 2022,331,043 MMcfe of purchases of reserves in place were associated with the East Texas and ConocoPhillips

acquisitions. Refer to Note 5 in the Notes to the Group Financial Statements for additional information about

these acquisitions.

During 2021,1,260,514 MMcfe of purchases of reserves in place were associated with the Indigo, Tanos, Blackbeard and

Tapstone acquisitions. Refer to Note 5 in the Notes to the Group Financial Statements for additional information about these

Sales of Reserves in Place

During 2023,369,035 MMcfe of sales of reserves in place were primarily associated with the divestitures of non-core assets.

During 2022,6,912 MMcfe of sales of reserves in place were primarily associated with the divestitures of non-core assets.

During 2021,164,039 MMcfe of sales of reserves in place were primarily associated with the divestment of assets to Oaktree for

their subsequent participation in the Indigo acquisition. Refer to Note 5 in the Notes to the Group Financial Statements for

additional information about divestitures.

Proved Undeveloped Reserves

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 will 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 will engage third parties to complete the existing

development activities, and such reserves are included below as proved undeveloped reserves. We do not have a

development program and, as a result, any additional undrilled locations that we hold cannot be classified as undeveloped

reserves in accordance with SEC rules unless a development plan is in place. As of December 31, 2023, we had no such

development plans and therefore have not classified these undrilled locations as proved undeveloped reserves.

The following table summarizes the changes in our estimated proved undeveloped reserves during theyears ended

December 31, 2023,2022 and 2021:

Extensions and Discoveries

During 2023, no reserves were added from extension or discovery activities.

During 2022, we elected to participate in select development activities where third parties were engaged to complete the

development. Seven of these wells were in progress as of December 31, 2022, generating 8,832 MMcfe in proved

undeveloped reserves.

During 2021, no reserves were added from extension or discovery activities.

Purchase of Reserves in Place

During 2023, the 24,821 MMcfe of purchase of reserves in place were associated with the Tanos II acquisition and related to

four wells in progress that have been drilled and are awaiting hydraulic fracture stimulation.

During 2022, there were no purchases of proved undeveloped reserves in place.

During 2021, the 3,505 MMcfe of purchase of reserves in place were associated with the Tapstone Acquisition and related to

five wells that were under development as of December 31, 2021. We engaged third parties to complete this development

activity and during 2022 these were converted to proved developed reserves. Refer to Note 5 in the Notes to the Group

Financial Statements for additional information about acquisitions.

Sales of Reserves in Place

During 2023, the 8,832 in sales of reserves in place were divested as partof the sale of 80% of the equity interest in DP Lion

Equity Holdco LLC in December 2023. Refer to Note 5 in the Notes to the Group Financial Statements for additional

information.

During 2022, there wereno sales of reserves in place.

During 2021, there wereno sales of reserves in place.

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, 2023. 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 99.9% of our acreage was held by production at

(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, 2023 that will expire in

2024,2025 and 2026 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 in a safe, efficient and responsible manner, however we also

assess areas subject to lease expiration for potential development opportunities when prudent. As of December 31, 2023, we

had no development plans other than the in-progress wells described above and therefore have not classified any other

potential undrilled locations on this acreage as proved undeveloped reserves.

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2023 included in

this Annual Report & Form 20-F were independently

evaluated by our independent engineers, NSAI, in

accordance with petroleum engineering and evaluation

standards published by The Petroleum Resources

Management System jointly published by the Society of

Petroleum Engineers, the World Petroleum Council, the

American Association of Petroleum Geologists and the

Society of Petroleum Evaluation Engineers, as amended and

definitions and guidelines established by the SEC.

NSAI is a worldwide leader of petroleum property analysis

for industry and financial organizations and government

agencies. NSAI was founded in 1961 and performs

consulting petroleum engineering services under Texas

Board of Professional Engineers Registration No. F-2699.

Within NSAI, the technical persons primarily responsible for

auditing the estimates set forth in the NSAI reserves report

incorporated herein are Mr. Robert C. Barg and Mr. William

J. Knights. Mr. Barg, a Licensed Professional Engineer in the

State of Texas (No. 71658), has been practicing consulting

petroleum engineering at NSAI since 1989 and has over six

years of prior industry experience. He graduated from

Purdue University in 1983 with a Bachelor of Science

Degree in Mechanical Engineering. Mr. Knights, a Licensed

Professional Geoscientist in the State of Texas, Geology

(No. 1532), has been practicing consulting petroleum

geoscience at NSAI since 1991 and has over 10 years of prior

industry experience. He graduated from Texas Christian

University in 1981 with a Bachelor of Science Degree in

Geology in 1984 with a Master of Science Degree in

Geology. Both technical principals meet or exceed the

education, training and experience requirements set forth in

the Standards Pertaining to the Estimating and Auditing of

Oil and Gas Reserves Information promulgated by the

Society of Petroleum Engineers; both are proficient in

judiciously applying industry standard practices to

engineering and geoscience evaluations, as well as applying

SEC and other industry reserves definitions and guidelines.

Our internal staff of petroleum engineers and geoscience

professionals work closely with our independent reserve

engineers to ensure the integrity, accuracy and timeliness

of data furnished to our independent reserve engineers for

their reserve evaluation process. Our technical team

regularly meets with the independent reserve engineers 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 has been with the Group since 2018

and has 24 years of experience in petroleum engineering,

with over 20 years of experience evaluating natural gas and

oil reserves, and holds a Bachelor of Science in Petroleum

Engineering. Prior to joining the Group in 2018, our Vice

President of Reservoir Engineering served in various

reservoir engineering roles for public companies engaged in

the exploration and production operations, and is also a

member of the Society of Petroleum Engineers.

Estimation of Proved Reserves

Proved reserves are reserves which, by analysis of

geoscience and engineering data, can be estimated with

reasonable certainty to be economic1ally producible from a

given date forward from known reservoirs under existing

economic conditions, operating methods and government

regulations prior to the time at which contracts providing

the right to operate expires, unless evidence indicates that

renewal is reasonably certain. The term “reasonable

certainty” implies a high degree of confidence that the

quantities of oil or natural gas actually recovered will equal

or exceed the estimate. To achieve reasonable certainty, we

and the independent reserve engineers 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 include, but are not limited to, well logs, geologic

maps and available downhole and production data,

micro-seismic data and well-test data.

Reserve 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 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 Risk Factors for additional information.

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, 2023.

(a)Comprised of wells in the Central Region.

Exploratory and Development Drilling Activities

Information regarding our drilling and development activities is set forth below:

We drilled no exploratory wells (productive or dry) during the years ended December 31, 2023,2022 and 2021.

During 2021, we completed the Tapstone Acquisition, which included five wells in the Central Region that were under

development by Tapstone as of December 31, 2021. We engaged third parties to complete this development activity, however

they remained in progress as of December 31, 2021.

During 2022, we completed the development of thefive wells referenced in the preceding paragraph that had been under

development as of December 31, 2021. We then elected to participate inseven development opportunities on a non-

operating basis in our Appalachian Region. Allseven of the Appalachian development wells remained in progress as of

December 31, 2022.

During 2023, we completed the development oftwo of theseven 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. As of December 31, 2023, four Central Region development wells remain in progress. Refer to Note 5 in

the Notes to the Group Financial Statements for additional information regarding the sale of equity interest in DP Lion Equity

Holdco LLC.

Production Volumes, Average Sales Prices and Operating Costs

(a)LOE is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.

jurisdictions’ valuation of our natural gas and oil properties and midstream assets.

(c)Midstream operating expenses are daily costs incurred to operate our owned midstream assets inclusive of employee and benefit expenses.

(d)Transportation expenses are daily costs incurred from third-party systems to gather, process and transport our natural gas, NGLs and oil.

Significant Fields

The Group operates in four primary fields: (i) Appalachia, which is comprised of the stacked Marcellus and Utica shales and

other conventional formations (that form our Central Region) (ii) East Texas and Louisiana, which consists of the stacked

Cotton Valley, Haynesville, and Bossier shales, (iii) the Barnett Shale and (iv) the Midcontinent region, in North Texas and

Oklahoma, which also consists of various stacked plays. The following table presents production for the Group’s Appalachian

region, which is considered significant, or greater than 15%of the Group’s total proved reserves, for the periods presented.

Customers

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

During theyear ended December 31, 2023, no customers individually comprised more than 10% of total revenues.

During theyear ended December 31, 2022, no customers individually comprised more than 10% of total revenues.

During the year ended December 31, 2021, two customers individually comprised more than 10% of total revenues,

representing 22% of consolidated revenues.

Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers

would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate

potential exposure to credit risk, we may require from time to time for our customers to provide financial security.

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, 2023.

Transportation and Marketing

Diversified Energy Marketing, LLC, our wholly owned

marketing subsidiary, specializes in commodity marketing,

asset optimization, producer services and the strategic

management of our transportation portfolio. Our mission

extends to enhancing operational efficiency and

profitability, leveraging market insights, operational

expertise, strategic asset management and the right sizing

of our contractual transport assets to ensure flow reliability

and access to various markets.

Our comprehensive suite of services encompasses the

marketing of natural gas, NGL’s and oil, risk management,

logistical support and the strategic management of

transportation agreements. This approach is designed to

maximize market presence, financial outcomes, ensure

consistent product flow and capitalize on strengthening

markets through our transportation infrastructure and

vertically integrated midstream systems. Our midstream

infrastructure and strategic arrangements enable us to

access high-demand markets, notably in the U.S. Gulf Coast

region, while leveraging low cost transportation in

Appalachia. The synergistic nature of our asset base allows

for access to advantageous pricing year-round and flow

assurance with minimal firm transportation agreements. As

of December 31, 2023, our transportation arrangements

provide access to 515 MMcfepd of takeaway capacity.

As a dedicated arm of the Group, our marketing team

ensures our operations and strategies are closely aligned

with our broader goals. With a team of experienced

professionals and a deep understanding of the energy

market’s nuances, we are committed to delivering value and

reliability to our stakeholders. We navigate through the

industry’s complexities to achieve operation excellence.

Competition

Our marketing activities compete with numerous other

companies offering the same services, many of which

possess larger financial and other resources than we have.

Some of these competitors are other producers and

affiliates of companies with extensive pipeline systems that

are used for transportation from producers to end users.

Other factors affecting competition are the cost and

availability of alternative fuels, the level of consumer

demand and the cost of and proximity to pipelines and

other transportation facilities. We believe that our ability to

compete effectively within the marketing segment in the

future depends upon establishing and maintaining strong

relationships with customers.

Seasonality

Demand for natural gas and oil generally decreases during

the spring and fall months and increases during the summer

and winter months. However, seasonal anomalies and

consumers’ procurement initiatives can also lessen seasonal

demand fluctuations. Seasonal anomalies can increase

competition for equipment, supplies and personnel and

can lead to shortages and increase costs or delay

Title to Properties

We believe that we have satisfactory title to substantially all

of our active properties in accordance with standards

generally accepted in the oil and natural gas industry. Our

properties are subject to customary royalty and overriding

royalty interests, certain contracts relating to the

exploration, development, operation and marketing of

production from such properties, consents to assignment

and preferential purchase rights, liens for current taxes,

applicable laws and other burdens, encumbrances and

irregularities in title, which we believe do not materially

interfere with the use of or affect the value of such

properties. Prior to acquiring producing wells, we endeavor

to perform a title investigation on an appropriate portion of

the properties that is thorough and is consistent with

standard practice in the natural gas and oil industry.

Generally, we conduct a title examination and perform

curative work with respect to significant defects that we

identify on properties that we operate. We believe that we

have performed reasonable and protective title reviews

with respect to an appropriate cross-section of our

operated natural gas and oil wells.

GOVERNMENT REGULATION

General

Our operations in the United States are subject to various

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 wildlife; 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 be expected to result in fines or

penalties, but could also result in 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 legislation 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 referred to above are

environmental laws and regulations, which 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 us and 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 further regulation could

increase our cost or otherwise affect our ability to produce.

For instance, on March 7, 2024, the U.S. Environmental

Protection Agency (“EPA”) finalized New Source

Performance Standard Subpart OOOOb (NSPS OOOOb) for

new, modified, and reconstructed sources after

December 6, 2022, and Emissions Guideline Subpart

OOOOc (EG OOOOc) for sources existing prior to

December 6, 2022. Most provisions of NSPS OOOOb take

effect immediately while certain requirements have phase-

in periods. EG OOOOc requires individual states to

incorporate similar provisions into their regulations (or rely

upon EPA’s model requirements) and will require

approximately five years to be implemented. The affected

source categories under OOOOb and OOOOc include well

completions, fugitive emissions, liquids unloading, process

controllers, process pumps, storage vessels, and

associated gas.

EPA has also recently proposed two interrelated

regulations. On August 1, 2023, EPA proposed revisions to

the greenhouse gas reporting rule for the oil and natural

gas industry to change the calculation methodology to be

primarily based on actual emission measurements rather

than emission factors. These changes facilitate the

implementation of a methane fee under the Waste Emission

Charge (WEC) rule which was proposed on

January 26, 2024. Both rules are expected to be finalized

by August 2024 as required by the Inflation Reduction Act

(IRA) of 2022. Under the WEC rule, reporters would be

subject to a fee beginning in 2025 at $900 per ton of

methane emissions that exceed thresholds prescribed

under the rule. These methane emissions would be based

on those reported under the greenhouse gas reporting rule.

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

regulations protect plant and animal species that are

threatened or endangered. The Migratory Bird Treaty Act

and the Bald and Golden Eagle Protection Act provides

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.

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

PHMSA pursuant to the NGPSA, as amended by the Pipeline

Safety Act of 1992, the Accountable Pipeline Safety and

Partnership Act of 1996, the 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. In

October 2019, PHMSA finalized the first of three rules that,

collectively, are referred to as the natural gas “Mega Rule.”

The first rule imposed additional safety requirements on

natural gas transmission pipelines, including maximum

operating pressure and integrity management near HCAs

for onshore gas transmission pipelines. PHMSA finalized the

second rule extending federal safety requirements to

onshore gas gathering pipelines with large diameters and

high operating pressures in November 2021. PHMSA

published the final of the three components of the Mega

Rule in August 2022, which took effect in May 2023. The

final rule applies to onshore gas transmission pipelines,

clarifies integrity management regulations, expands

corrosion control requirements, mandates inspection after

extreme weather events, and updates existing repair

criteria for both HCA and non-HCA pipelines. Finally,

PHMSA published a Notice of Proposed Rulemaking

regarding more stringent gas pipeline leak detection and

repair requirements to reduce natural gas emissions on May

18, 2023. The adoption of laws or regulations that apply

more comprehensive or stringent safety standards could

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.

However, legislation has been proposed from time to time,

and various environmental groups have filed lawsuits, that,

if successful, 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, so-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 authorized 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 the PRPs 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 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 Clean Water Act 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. OPA assigns joint and several liability,

without regard to fault, to each liable party for oil removal

costs and a variety of public and private damages.

Although defenses exist to the liability imposed by 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 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

and 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 and terms and conditions of service.

Section 1(b) of the Natural Gas Act exempts natural gas

gathering facilities from regulation by FERC. However, the

distinction between federally unregulated gathering

facilities and FERC regulated transmission facilities is a

fact-based determination, and the classification of facilities

is the subject of ongoing litigation. 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 transportation of oil and NGLs on

interstate pipelines under the provisions of the Interstate

Commerce Act, the Energy Policy Act of 1992 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.

Natural gas, NGLs and crude oil prices are currently

unregulated, 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

might be enacted in the future or what effect, if any, 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.

Climate Change Laws and Regulations

Climate change continues to be a legislative and regulatory

focus. 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 greenhouse

gas emissions, and such laws and regulations that restrict

emissions could increase our costs should the requirements

necessitate the installation of new equipment or the

purchase of emission allowances. For example, the Inflation

Reduction Act, which was signed into law in August 2022,

includes a “methane fee” that is expected to be imposed

beginning with emissions reported for calendar year 2024.

In addition, the current U.S. administration has proposed

more stringent methane pollution limits for new and

existing gas and oil operations. 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, President Biden has recommitted

the United States to the UN-sponsored “Paris Agreement,”

for nations to limit their greenhouse gas emissions through

non-binding, individually-determined reduction goals every

five years after 2020. In April 2021, President Biden

announced a goal of reducing the United States’ emissions

by 50 – 52% below 2005 levels by 2030. 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 fossil fuel subsidies and pursue further

action on non-carbon dioxide greenhouse gases. 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. 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 greenhouse gas emissions would impact our

business, any such future laws and regulations imposing

reporting obligations on, or limiting emissions of

greenhouse gases from, our equipment and operations

could require us to incur costs to implement such measures

associated with our operations.

In addition, activists concerned about the potential effects

of climate change 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 increasing, 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

climate change effects, such as rising sea levels, and

therefore are responsible for roadway and infrastructure

damages, or alleging that the companies have been aware

of the adverse effects of climate change for some time but

defrauded their investors by failing to adequately disclose

those impacts.

Additionally, the SEC published its long-awaited climate

rule in early March 2024, requiring the disclosure of a range

of climate-related risks and financial impacts. We are

currently assessing this rule, and at this time we cannot

predict the costs of implementation or any potential

adverse impacts for either the Group or our customers

resulting from the rule. Additionally, enhanced climate

disclosure requirements could accelerate the trend of

certain stakeholders and lenders restricting or seeking more

stringent conditions with respect to their investments in

certain carbon-intensive sectors.