Form: 20-F

Annual and transition report of foreign private issuers [Sections 13 or 15(d)]

March 17, 2025

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
(Mark One)
¨  REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
þ  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2024
OR
¨  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
¨  SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report
For the transition period from        to       
Commission file number: 001-41870
06_426107-1_logo_DE.jpg
Diversified Energy Company PLC
(Exact name of Registrant as specified in its charter)
Not Applicable
England and Wales
(Translation of Registrant’s name into English)
(Jurisdiction of incorporation or organization)
1600 Corporate Drive Birmingham, Alabama 35242
Tel: +1 205 408 0909
Bradley G. Gray
Diversified Energy Company PLC
1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909
(Address of principal executive offices)
(Name, Telephone, E-mail and/or Facsimile number and Address of
Company Contact Person)
Securities registered or to be registered, pursuant to Section 12(b) of the Act
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Ordinary shares, nominal (par) value £0.20 per share
DEC
New York Stock Exchange
Ordinary shares, nominal (par) value £0.20 per share
DEC
London Stock Exchange
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital stock or common stock as of the close of the period covered by the annual report: N/A
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ¨Noþ
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934.  Yes  ¨No þ
Note — Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their
obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§
232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large
accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
¨ Large accelerated filer
þ Accelerated filer
¨ Non-accelerated filer
¨ Emerging growth company
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended
transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial
reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the
correction of an error to previously issued financial statements. ¨
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the
registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ¨
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
¨ U.S. GAAP
þ International Financial Reporting Standards as issued by the International Accounting Standards Board
¨ Other
If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow.  Item 17 ¨  Item 18
¨
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ¨Noþ
(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934
subsequent to the distribution of securities under a plan confirmed by a court.  Yes ¨ No ¨
DE Logo Horiz-RGB-BLU+BLK.jpg
Diversified Energy Company PLC
2024 Annual Report & Form 20-F
For the Year Ended December 31, 2024
Table of Contents
Page
We have prepared our financial statements and the notes thereto in accordance with IFRS as issued by the International Accounting Standards Board.
To provide metrics that we believe enhance the comparability of our results to similar companies, throughout this Annual Report & Form 20-F, we refer
to Alternative Performance Measures (“APMs”). APMs are intended to be used in addition to, and not as an alternative for the financial information
contained within the Group Financial Statements, nor as a substitute for IFRS. In APMs within this Annual Report & Form 20-F, we define, provide
calculations and reconcile each APM to its nearest IFRS measure. These APMs include “adjusted EBITDA,” “net debt,” “net debt-to-adjusted EBITDA,”
“total revenue, inclusive of settled hedges,” “adjusted EBITDA margin,” “free cash flow,” “adjusted operating cost per Mcfe,” “employees, administrative
costs and professional services,” and “PV-10.”
1
Cross Reference to Form 20-F
Pages
Part I
Item 1.
Identity of Directors, Senior Management and Advisers
N/A
Item 2.
Offer Statistics and Expected Timetable
N/A
Item 3.
Key Information
A.
[Reserved]
B.
Capitalization and indebtedness
N/A
C.
Reasons for the offer and use of proceeds
N/A
D.
Risk factors
34-50
Item 4.
Information on the Group
A.
History and development of the Group
3, 7, 103
B.
Business overview
7-14
C.
Organizational structure
D.
Property, plant and equipment
3, 107, 120, 133
Item 4A.
Unresolved Staff Comments
N/A
Item 5.
Operating and Financial Review and Prospects
A.
Operating results
20-26
B.
Liquidity and capital resources
C.
Research and development, patents and licenses, etc.
N/A
D.
Trend information
E.
Critical accounting estimates
Item 6.
Directors, Senior Management and Employees
A.
Directors and senior management
53, 57-59
B.
Compensation
72-93, 129, 131
C.
Board practices
52-55, 63-64
D.
Employees
E.
Share ownership
61, 63, 129, 131
F.
Disclosure of a registrant’s action to recover erroneously awarded compensation
N/A
Item 7.
Major Shareholders and Related Party Transactions
A.
Major shareholders
61, 63
B.
Related party transactions
C.
Interests of experts and counsel
N/A
Item 8.
Financial Information
A.
Consolidated Statements and Other Financial Information
B.
Significant Changes
N/A
Item 9.
The Offer and Listing
A.
Offer and listing details
B.
Plan of distribution
N/A
C.
Markets
D.
Selling shareholders
N/A
E.
Dilution
N/A
F.
Expenses of the issue
N/A
2
Pages
Item 10.
Additional Information
A.
Share capital
N/A
B.
Memorandum and articles of association
[OPEN]
C.
Material contracts
D.
Exchange controls
E.
Taxation
F.
Dividends and paying agents
N/A
G.
Statement by experts
N/A
H.
Documents on display
I.
Subsidiary information
N/A
J.
Annual report to security holders
N/A
Item 11.
Quantitative and Qualitative Disclosures About Market Risk
Item 12.
Description of Securities Other than Equity Securities
A.
Debt securities
N/A
B.
Warrants and rights
N/A
C.
Other securities
N/A
D.
American depositary shares
N/A
Part II
Item 13.
Defaults, Dividend Arrearages and Delinquencies
N/A
Item 14.
Material Modifications to the Rights of Security Holders and Use of Proceeds
N/A
Item 15.
Controls and Procedures
A.
Disclosure Controls and Procedures
B.
Management’s annual report on internal control over financial reporting
C.
Attestation report of the registered public accounting firm
D.
Changes in internal control over financial reporting
N/A
Item 16.
[Reserved]
N/A
Item 16A.
Audit Committee Financial Expert
Item 16B.
Code of Ethics
Item 16C.
Principal Accountant Fees and Services
71, 116
Item 16D.
Exemptions from the Listing Standards for Audit Committees
N/A
Item 16E.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Item 16F.
Change in Registrant’s Certifying Accountant
N/A
Item 16G.
Corporate Governance
N/A
Item 16H.
Mine Safety Disclosure
N/A
Item 16I.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
N/A
Item 16J.
Insider Trading Policies
Item 16K.
Cybersecurity
Part III
Item 17.
Financial Statements
N/A
Item 18.
Financial Statements
Item 19.
Exhibits
3
Strategic Report
Overview of Our Business
Diversified Energy Company PLC (the “Parent” or “Company”) and its wholly owned subsidiaries (the
“Group,” “DEC,” or “Diversified”) is an independent energy company engaged in the production,
transportation and marketing of natural gas, natural gas liquids and crude oil.
Our proven business model creates sustainable value in today's energy markets by investing in producing assets, reducing emissions and improving asset
integrity while generating significant, hedge-protected cash flows. We acquire, optimize, produce and transport natural gas, natural gas liquids and oil from
existing wells and then retire our wells at the end of their lives to optimally steward the resource previously developed by our peers, reducing the environmental
footprint, while sustaining important jobs and tax revenues for many local communities. While most companies in our sector are built to explore and develop new
reserves, we fully exploit existing reserves through our focus on safely and efficiently operating existing wells to maximize their productive lives and economic
capabilities, which in turn reduces the industry’s footprint on our planet.
A Differentiated Business Model
Our business model is unique among the natural gas and oil industry in that we do not rely on capital-intensive drilling and development. Rather, our
stewardship model focuses on acquiring existing long-life, low-decline producing wells and, at times, their associated midstream assets, and then
efficiently managing the assets to improve or restore production, reduce unit operating costs, improve operational safety, reduce emissions and
generate consistent free cash flow before safely and permanently retiring those assets at the end of their useful lives.
Daily Operating Priorities
Our guiding daily principles underline our commitment to value creation without compromising the safety of employees. These principles - Safety,
Production, Efficiency and Enjoyment - drive the success of our business model. Our workforce gives precedence to these principles in their daily work.
Geographic Operating Areas
Appalachian Region
The Appalachian Region spans Pennsylvania, Virginia, West Virginia, Kentucky, Tennessee and Ohio and consists of two productive unconventional shale
formations, along with numerous conventional formations. We entered the Appalachian Region in 2001 and currently operate within the Marcellus Shale
and the slightly deeper Utica Shale, as well as many conventional formations.
Central Region
Our Central Region includes parts of Texas, Louisiana and Oklahoma, and is home to a number of asset rich natural gas and oil formations. We entered
the Central Region in 2021 and currently operate within the Haynesville, Bossier, Cotton Valley, Barnett and Mid Continent plays.
4
Key Facts for 2024
Net Loss
Total Revenue
Adjusted EBITDA Margin(a)
Adjusted EBITDA(a)
$87 million
$795 million
50%
$472 million
Production Mix
Production
PV-10 Value of Reserves
Asset Acquisitions
84%
natural gas
244,298
natural gas (MMcf)
$1.6
billion(b)
3 acquisitions
12%
NGLs
5,980
NGLs (MBbls)
3,627,589
MMcfe
$585 million, gross
4%
oil
1,568
oil (MBbls)
$388 million, net
Scope 1 Methane
Emissions Intensity
No-Leak Rate
on Surveyed Assets
Total Recordable
Incident Rate
Reportable
Spill Intensity
0.7
MT CO2e/MMcfe
98%
Group-wide
0.89
per 200,000
work hours
0.08
oil & water
per MBbl
(a)Refer to APMs within this Annual Report & Form 20-F for information on how this metric is calculated and reconciled to IFRS measures.
(b)Based on SEC pricing.
Strategy
Our growth and ability to generate consistent shareholder returns stems from our unique business model and successful execution of low-risk,
disciplined and proven operating techniques.
1   Acquire long-life stable assets
We practice a disciplined approach to acquire long-life stable assets by targeting low-decline producing assets that are value accretive, high margin and
strategically complementary, while also applying extensive environmental, social, land and legal due diligence.
2024 Achievements
Targets for 2025
Completed three acquisitions in our Central Region, including:
Oaktree working interest acquisition for gross consideration of
$410 million and net consideration of $222 million, contributing
approximately $66 million MMcfepd to 2024 revenue.
Crescent Pass acquisition for gross consideration of $106 million
and net consideration of $98 million, contributing approximately
$10 million MMcfepd to 2024 revenue.
East Texas II acquisition for gross consideration of $69 million
and net consideration of $68 million, contributing approximately
$5 million MMcfepd to 2024 revenue.
Successfully merge assets acquired in the recently completed
acquisition of Maverick Natural Resources, LLC (“Maverick”) to
build scale and achieve synergies.
Effectively integrate acquisitions into our existing operations,
ensuring seamless transitions and alignment with our strategic
objectives to drive growth and maximize synergies.
We will continue our disciplined acquisition strategy, targeting
assets that meet our strict investment standards.
We will maintain liquidity rigor, ensuring we are well-positioned to
capitalize on market opportunities as they emerge.
Our growth strategy will prioritize expanding in complementary
and synergistic ways, while building strong partnerships with
development-focused producers in our key operating regions.
Link to Risks:
1 2 4
Link to KPIs:
1 5
2   Operate our assets in a safe, efficient and responsible manner
Our operational strategy and success is closely aligned with the culture we created with our daily operational priorities. Our team embodies these
priorities through our Smarter Asset Management (“SAM”) program, working tirelessly to ensure the safe delivery of clean, affordable and reliable
energy.
2024 Achievements
Targets for 2025
Annual production of 791 MMcfepd.
Exit rate of 864 MMcfepd.
Adjusted EBITDA margin of 50%.
Achieved a 98% no-leak rate on surveyed assets.
LTIR of 0.38 per 200,000 work hours, a decline of 63% year-over-
year.
We will remain committed to our daily operating priorities: Safety,
Production, Efficiency, and Enjoyment.
Our dedication to responsible stewardship remains steadfast. We
will focus intently on continuous improvement in all aspects of
sustainability, striving to exceed our stakeholders’ expectations.
We will continue to prioritize the SAM program to sustain margins,
mitigate natural declines, and leverage expense efficiency
opportunities.
Link to Risks:
1 2 4 5 6 7
Link to KPIs:
3 4 5 6 7
5
3   Generate Reliable Free Cash Flow
Our business model is inherently designed to generate free cash flow. Furthermore, we aspire to make cash flows predictable and reliable so we can
consistently generate shareholder return, pay down debt, fund acquisitive growth, and accomplish our sustainability goals and ambitions.
2024 Achievements
Targets for 2025
Repaid $206 million in asset-backed debt securitizations.
Repurchased 1,638,030 shares, representing $21 million in
shareholder value above and beyond the $84 million in dividend
distributions.
$151 million gain on settled derivative instruments.
Recorded $8 million in coal mine methane revenues.
Divested certain non-core undeveloped acreage across our
footprint for a total of $59 million.
We will continue our effective hedging strategy to protect cash
flows. Additionally, we will capitalize on accretive market
opportunities to elevate our hedge book floor.
We will continue to apply our Smarter Asset Management program
to maintain low decline rates across our producing assets and
review opportunities to optimize both core and non-core assets.
We will remain dedicated to prudent cash flow growth through
accretive acquisitions that complement our existing asset base.
Link to Risks:
1 2 3 4 7
Link to KPIs:
1 2 3 4 5
4   Retire assets safely and responsibly
At the end of a well’s economic life, our safe and systematic asset retirement program ensures wells are permanently retired and well sites are
responsibly restored to their natural condition. Our retirement program underscores our strong commitment to a healthy environment, the surrounding
community, our neighbors, and state regulatory authorities.
2024 Achievements
Targets for 2025
Expanded our asset retirement operations to 18 teams and 18
rigs.
Retired 202 DEC-owned wells in the Appalachian Region and a
further 13 DEC-owned wells in our Central Region, surpassing our
goal to retire 200 wells in 2024 and exceeding our collective state
commitments in Appalachia.
Additionally, we retired 85 third party-owned wells in the
Appalachian Region, including 51 state and federal orphan wells
and 34 for third party operators, bringing the total wells retired by
the Next LVL team to 287 wells.
We will continue to safely retire wells, aiming to exceed state
asset retirement program commitments by identifying and retiring
wells at the end of their productive lives.
We will continue to leverage the benefits of vertical integration
through our expanded internal asset retirement capacity.
We will maintain constructive and collaborative dialogue with
states and industry associations to innovate and ensure best
practices in well retirement.
Link to Risks:
1 2   4 5 6
Link to KPIs:
2 4 5 6
Key Performance Indicators
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.
Refer to APMs within this Annual Report & Form 20-F for information on how these metrics are calculated and reconciled to IFRS measures.
1   Net Debt-to-Adjusted EBITDA
2024
2023
2022
Net debt-to-pro forma adjusted EBITDA
3.0x
2.2x
2.4x
During 2024 our leverage ratio increased to 3.0x primarily due to financing the majority of our acquisitions with debt. We actively manage our balance
sheet and seek to maintain a long-term leverage ratio of approximately 2.5x.
Link to Strategy:
1 3
Link to Risks:
1 3 4 5 6 7
2   Adjusted EBITDA Margin
2024
2023
2022
Adjusted EBITDA Margin
50%
52%
49%
Total revenue, inclusive of settled hedges and adjusted EBITDA decreased 10% and 14%, respectively, in 2024, while adjusted EBITDA margin
remained relatively consistent at 50%. The decrease in total revenue, inclusive of settled hedges was primarily due to a decrease in the average realized
sales price, lower production, a decline in hedge settlement gains, and normal declines. The decrease in adjusted EBITDA was driven by a decrease in
commodity pricing and lower production.
Link to Strategy:
3 4
Link to Risks:
1 2 3 4 5 6 7
6
3   Adjusted Operating Cost per Mcfe
2024
2023
2022
Adjusted Operating Cost per Mcfe
$1.78
$1.76
$1.77
Adjusted operating cost per Mcfe for 2024 was $1.78, an increase of 1% compared with 2023. This increase was primarily due to higher employees,
administrative costs and professional services due to investments made in staff and systems and costs related to litigation expense.
Link to Strategy:
2 3
Link to Risks
1 4 5 6
4   Net Cash Provided by Operating Activities
2024
2023
2022
Net Cash Provided by Operating Activities (in millions)
$346
$410
$388
Net cash provided by operating activities for 2024 was $346 million, a decrease of 16% compared with 2023. This decrease was due to the decrease in
total revenue resulting from decreases in pricing and production. However, this was partially offset by changes in working capital, which generated $50
million less in cash outflows compared to 2023.
Link to Strategy:
2 3 4
Link to Risks:
1 2 3 5 6 7
5   Emissions Intensity
2024
2023
2022
Emissions Intensity (MT CO2e/MMcfe)
0.7
0.8
1.2
Realized a 13% year-over-year reduction in Scope 1 methane emissions intensity, achieved through investments in leak detection technologies,
replacing natural gas-driven pneumatics with instrument air or solar solutions, and enhanced aerial emissions surveillance in our Central Region.
Link to Strategy:
1 2 3 4
Link to Risks:
2 5
6   Meet or Exceed State Asset Retirement Goals
2024
2023
2022
DEC-owned well retirements(a)
215
222
214
Wells retired by Next LVL
287
383
262
(a)DEC wells inclusive of 13, 21 and 14 Central Region wells retired during 2024, 2023 and 2022, respectively.
A total of 215 DEC-owned wells, including 13 in the Central Region, were retired across our operating footprint, surpassing our goal to retire 200 wells
and exceeding our collective state commitments in Appalachia. Additionally, Next LVL Energy plugged a total of 287 wells in Appalachia, including 202
DEC-owned wells and 85 third party-owned wells consisting of 51 state and federal orphan wells and 34 for third party operators.
Link to Strategy:
.4.
Link to Risks:
2 4 5
7   Safety Performance
2024
2023
2022
TRIR (per 200,000 work hours)
0.89
1.28
0.73
LTIR (per 200,000 work hours)
0.38
1.04
0.66
MVA (incidents per million miles)
0.34
0.55
0.69
Our 2024 TRIR was 0.89, a 30% improvement from 2023, driven by a foreman-led safety approach, enhanced good catch/near miss reporting, and a
new safety program for short-service field employees. Additionally, our 2024 LTIR was 0.38, reflecting a 63% improvement from 2023, attributable to
the same initiatives.
Moreover, our 2024 MVA rate was 0.34, a 38% improvement from 2023. This improvement was primarily due to specific actions taken to enhance
performance and accountability, including the implementation of vehicle telemetric monitoring.
Link to Strategy:
.2.
Link to Risks:
5 6
7
Our Business
History & Development of the Business
We are an independent energy company focused on natural gas and liquids production, transportation, marketing and well retirement, primarily located
within the Appalachian and Central regions of the United States. We were incorporated in 2014 in the United Kingdom, and our predecessor business
was co-founded in 2001 by our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., with an initial focus on primarily natural gas and oil
production in West Virginia. In recent years, we have grown rapidly by capitalizing on opportunities to acquire and enhance producing assets and by
leveraging the operating efficiencies that result from economies of scale. As of December 31, 2024, we have completed 27 acquisitions since 2017 for a
combined purchase price of approximately $3.1 billion. In addition, on March 14, 2025, we completed our previously announced acquisition of Maverick
for a gross purchase price of approximately $1,275 million.
Throughout our history, we have prioritized sustainability and efficiency in our operations. Recognizing the global reliance on natural gas, we emphasize
the importance of responsible ownership and environmental stewardship in managing natural gas and crude oil wells and pipelines. Our proven track
record of acquiring, integrating and responsibly operating assets reflects this commitment. With our focus on efficient and environmentally sound energy
production, we are well-positioned to assist in meeting national and global energy demands.
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 09156132. 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.” Following the changes to the UK Listing Rules on July 29, 2024, the Company
continues to remain listed on the new equity shares (commercial companies) category of the Official List of the Financial Conduct Authority. As of
December 31, 2024, 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.
Business Overview
Our Business Model
Acquire - We maintain a disciplined approach to evaluating opportunities to ensure that we only pursue those properties that possess a consistent
asset profile. We target existing long-life, stable assets with synergistic opportunities that produce predictable and stable cash flows, are value
accretive, margin enhancing and strategically complementary.
Optimize - The primarily mature nature of the assets we acquire provides us with a portfolio of low-cost optimization opportunities. These
optimization activities, applied through our internally developed SAM program, are strategically important as they aid in offsetting natural
production declines, creating expense efficiency and reducing emissions.
Produce - Our culture makes the difference as our team of industry veterans strive to efficiently produce as many units as possible in a safe and
environmentally responsible manner, aligning safety, environmental and financial best interests.
Transport - We seek to acquire midstream systems into which we are a large producer and more fully integrate those assets into our upstream
portfolio to provide immediate and long-term synergies.
Retire - We embrace our commitment to be a responsible operator of existing assets. With safety and environmental stewardship as top priorities,
we design our asset retirement program to permanently retire wells that have reached the end of their producing lives. Between 2022 and 2024,
we made investments that allowed us to expand our asset retirement capabilities through a series of acquisitions.
Our Strengths
Low-risk and low-cost portfolio of assets
Long-life and low-decline production
High margin assets that leverage significant scale, supported by owned midstream and asset retirement infrastructure, along with an internal
product marketing team
A management and operational team with extensive experience
Proven history of successfully consolidating and integrating acquired assets
Outlook
Looking ahead, we will continue to prudently manage our long-life, low-decline asset portfolio and the consistent cash flows they generate. We plan to
maintain our hedging strategy to safeguard cash flow. Our goal is to retain our strategic advantages through purposeful growth, employing a disciplined
acquisition strategy that secures low-cost financing to support acquisitive growth while maintaining low leverage and prudent liquidity. Additionally, we
intend to stay proactive in our sustainability efforts by continuing to allocate capital to future sustainability initiatives.
8
Reserve Data
Summary of Reserves
The following table presents our estimated net proved reserves, Standardized Measure and PV-10 as of December 31, 2024, using SEC pricing.
Standardized Measure and PV-10 are 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 this Annual Report & Form 20-F. Refer to
Preparation of Reserve Estimates and Estimation of Proved Reserves within this Annual Report & Form 20-F for a definition of proved reserves and the
technologies and economic data used in their estimation.
December 31, 2024
SEC Pricing(a)
Proved developed reserves
Natural gas (MMcf)
2,895,619
NGLs (MBbls)
103,471
Oil (MBbls)
18,524
Total proved developed reserves (MMcfe)
3,627,589
Proved undeveloped reserves
Natural gas (MMcf)
NGLs (MBbls)
Oil (MBbls)
Total proved undeveloped reserves (MMcfe)
Total proved reserves
Natural gas (MMcf)
2,895,619
NGLs (MBbls)
103,471
Oil (MBbls)
18,524
Total proved reserves (MMcfe)
3,627,589
Prices used
Natural gas (Mmbtu)
$2.13
Oil and NGLs (Bbls)
$76.32
PV-10 (thousands)
Pre-tax (Non-GAAP)(b)
$1,591,772
PV of Taxes
(194,851)
Standardized Measure
$1,396,921
Percent of estimated total proved reserves that are:
Natural gas
80%
Proved developed
100%
Proved undeveloped
—%
(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 $2.13 per MMBtu as of December 31, 2024 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 $76.32 per Bbl as of December 31, 2024 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, 2024 was prepared without giving effect to taxes 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.
9
Proved Reserves
As of December 31, 2024, our estimated proved reserves totaled 3,627,589 MMcfe, a decrease of 6% from the prior year-end, with a Standardized
Measure of $1.4 billion. Natural gas constituted approximately 80% of our total estimated proved reserves and 80% of our total estimated proved
developed reserves. The following table provides a summary of the changes in our proved reserves during the years ended December 31, 2024, 2023
and 2022.
Total (MMcfe)
Total proved reserves as of December 31, 2021
4,629,029
Extensions and discoveries
13,326
Revisions to previous estimates
379,812
Purchase of reserves in place
331,043
Sales of reserves in place
(6,912)
Production
(296,121)
Total proved reserves as of December 31, 2022
5,050,177
Extensions and discoveries
1,012
Revisions to previous estimates
(659,379)
Purchase of reserves in place
126,803
Sales of reserves in place
(369,035)
Production
(299,632)
Total proved reserves as of December 31, 2023
3,849,946
Extensions and discoveries
1,287
Revisions to previous estimates
(106,936)
Purchase of reserves in place
173,056
Sales of reserves in place
(178)
Production
(289,586)
Total proved reserves as of December 31, 2024
3,627,589
Extensions and Discoveries
During 2024, 1,287 MMcfe were adjusted due to well assignments recorded in the accounting actuals.
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.
Revisions to Previous Estimates
During 2024, we recorded 106,936 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 19% as compared to the December 31, 2023. These
factors drove a net downward revision that impacted well economics and well life.
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 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.
Purchase of Reserves in Place
During 2024, 173,056 MMcfe of purchases of reserves in place were associated with the Oaktree, Crescent Pass and East Texas II acquisitions.
During 2023, 126,803 MMcfe of purchases of reserves in place were associated with the Tanos II acquisition.
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 acquisitions and divestitures.
Sales of Reserves in Place
During 2024, 178 MMcfe of sales of reserves in place were primarily associated with the divestitures of non-core assets.
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.
10
Refer to Note 5 in the Notes to the Group Financial Statements for additional information about acquisitions and 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 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 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, 2024, 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 the years ended December 31, 2024, 2023 and 2022:
Total (MMcfe)
Proved undeveloped reserves as of December 31, 2021
3,505
Extensions and discoveries
8,832
Revisions to previous estimates
Purchase of reserves in place
Sales of reserves in place
Converted to proved developed reserves
(3,505)
Proved undeveloped reserves as of December 31, 2022
8,832
Extensions and discoveries
Revisions to previous estimates
Purchase of reserves in place
24,821
Sales of reserves in place
(8,832)
Converted to proved developed reserves
Proved undeveloped reserves as of December 31, 2023
24,821
Extensions and discoveries
Revisions to previous estimates
(8,528)
Purchase of reserves in place
Sales of reserves in place
Converted to proved developed reserves
(16,293)
Proved undeveloped reserves as of December 31, 2024
Extensions and Discoveries
During 2024, no reserves were added from extension or discovery activities.
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, 2023, generating 8,832 MMcfe in proved undeveloped reserves.
Revisions of Previous Estimates
During 2024, there were 8,528 MMcfe of revisions to previous estimates as a result of changes in engineering assumptions due to performance. These
revisions were related to the completion of one Tanos II well in 2024 that was under development as of December 31, 2023.
During 2023, no reserves were added from extension or discovery activities.
During 2022, no reserves were added from extension or discovery activities.
Purchase of Reserves in Place
During 2024, there were no purchases of proved undeveloped 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.
Refer to Note 5 in the Notes to the Group Financial Statements for additional information about acquisitions and divestitures.
Sales of Reserves in Place
During 2024, there were no sales of reserves in place.
During 2023, the 8,832 in sales of reserves in place were divested as part of the sale of 80% of the equity interest in DP Lion Equity Holdco LLC in
December 2023.
11
During 2022, there were no sales of reserves in place.
Refer to Note 5 in the Notes to the Group Financial Statements for additional information about acquisitions and divestitures.
Converted to Proved Developed Reserves
During 2024, there were 16,293 undeveloped reserves converted to developed reserves as a result of completing three Tanos II wells in 2024 that were
under development as of December 31, 2023.
During 2023, the were no undeveloped reserves converted to developed reserves.
During 2022, 3,505 MMcfe of undeveloped reserves were converted to developed reserves as a result of completing five Tapstone wells in 2022 that
were under development as of December 31, 2021.
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, 2024. 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 December 31, 2024.
Developed Acreage
Undeveloped Acreage
Total Acreage
Gross(a)
Net(b)
Gross(a)
Net(b)
Gross(a)
Net(b)
As of December 31, 2024
7,073,071
3,917,121
8,418,195
5,572,567
15,491,266
9,489,688
(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, 2024 that will expire in 2025, 2026 and 2027
unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such acreage is extended or
renewed.
Gross
Net
2025
25,721
2,884
2026
2,690
59
2027
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. As of December 31, 2024, we had no development plans 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, 2024 included in this Annual Report & Form 20-F were evaluated 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.
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 and 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 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 Group since 2018 with 26 years of experience in petroleum engineering and over 23 years of experience evaluating
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natural gas and oil reserves. Prior to joining the Group 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 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, 2024.
As of
December 31, 2024
Natural gas wells
73,055
Oil wells
3,455
Total gross productive wells
76,510
Natural gas wells
62,384
Oil wells
1,796
Total net productive wells
64,180
As of
December 31, 2024
Total gross in progress wells
Total net in progress wells
Exploratory and Development Drilling Activities
Information regarding our drilling and development activities is set forth below:
Development
Productive Wells
Dry Wells
Total
Year
Gross
Net
Gross
Net
Gross
Net
2024
2023
4
4
4
4
2022
5
2
5
2
We drilled no exploratory wells (productive or dry) during the years ended December 31, 2024, 2023 and 2022.
During 2022, we completed the development of the five wells that had been under development as of December 31, 2021. We then elected to
participate in seven development opportunities on a non-operating basis in our Appalachian Region. All seven of the Appalachian development wells
remained in progress as of December 31, 2022.
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 remain 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 no development wells in progress.
Refer to Note 5 in the Notes to the Group Financial Statements for additional information regarding the acquisitions and divestitures.
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Production Volumes, Average Sales Prices and Operating Costs
Year Ended
December 31, 2024
December 31, 2023
December 31, 2022
Production
Natural Gas (MMcf)
244,298
256,378
255,597
NGLs (MBbls)
5,980
5,832
5,200
Oil (MBbls)
1,568
1,377
1,554
Total production (MMcfe)
289,586
299,632
296,121
Average realized sales price
(excluding impact of derivatives settled in cash)
Natural gas (Mcf)
$1.90
$2.17
$6.04
NGLs (Bbls)
25.17
24.23
36.29
Oil (Bbls)
74.71
75.46
89.85
Total (Mcfe)
$2.53
$2.68
$6.33
Average realized sales price
(including impact of derivatives settled in cash)
Natural gas (Mcf)
$2.57
$2.86
$2.98
NGLs (Bbls)
24.32
26.05
19.84
Oil (Bbls)
69.54
68.44
72.00
Total (Mcfe)
$3.05
$3.27
$3.30
Operating costs per Mcfe
LOE(a)
$0.80
$0.71
$0.62
Production taxes(b)
0.12
0.21
0.25
Midstream operating expense(c)
0.24
0.23
0.24
Transportation expense(d)
0.31
0.32
0.40
Total operating expense per Mcfe
$1.47
$1.47
$1.51
(a)LOE is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.
(b)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.
(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
We operate in four primary producing areas: (i) Appalachia, (ii) East Texas and Louisiana, (iii) the Barnett Shale, and (iv) the mid-continent region. The
following table presents production for our Appalachian Region, which is considered significant, or greater than 15% of our total proved reserves, for the
periods presented.
Year Ended
APPALACHIA
December 31, 2024
December 31, 2023
December 31, 2022
Production
Natural Gas (MMcf)
139,900
167,930
180,194
NGLs (MBbls)
2,931
3,018
2,810
Oil (MBbls)
390
394
423
Total production (MMcfe)
159,826
188,402
199,592
Customers
Our production is generally sold on month-to-month contracts at prevailing market prices.
During the years ended December 31, 2024, 2023 and 2022, 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.
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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, 2024.
Natural gas (MMcf)
2025
77,187
2026
52,802
2027
130,911
Thereafter
242,276
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. Our mission is to enhance operational efficiency and profitability by leveraging market insights,
operational expertise and strategic asset management to ensure reliable flow market access.
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
ensures advantageous pricing and flow assurance with minimal firm transportation agreements. As of December 31, 2024, our transportation
arrangements provide access to 522 MMcfepd of takeaway capacity.
As a dedicated arm of DEC, our marketing team aligns closely with our broader goals. 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
Our marketing activities face competition from numerous companies, many with greater financial and other resources. Competitors include other
producers and affiliates with extensive pipeline systems for transportation from producers to end users. Competition is also influenced by the cost and
availability of alternative fuels, consumer demand, and the cost of and proximity of pipelines and other transportation facilities. We believe that our
future success in the marketing segment depends on establishing and maintaining strong customer relationships.
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 nearly all 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 thorough 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.
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 (including county and municipal level) 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 referred to above 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.
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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 8, 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 took
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
NSPS OOOOb and EG OOOOc include well completions, fugitive emissions, liquids unloading, process controllers, process pumps, storage vessels, and
associated gas.
EPA last year also 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 were finalized in late 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. We achieved zero excess emissions under the WEC program in 2024 and therefore, are not
required to pay any WEC fees in 2025. President Trump announced following his election in November 2024 an intent to work with the Republican-
majority Congress to repeal any such “methane fee” (the WEC). In February 2025, Congress passed joint resolution H.J. Res. 35 disapproving EPA’s
2024 WEC rule under the Congressional Review Act; if the joint resolution becomes law, the WEC rule will have no force or effect.
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 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 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. 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, on January 17, 2025, PHMSA published the final rule instituting more stringent gas pipeline leak detection and repair requirements, performance
standards for advanced leak detection programs, methane emission mitigation requirements, pressure control design and maintenance requirements,
reporting and recordkeeping. This forthcoming final rule is to be effective 180 days from formal publishing in the Federal Register. On January 20, 2025
the Trump Administration issued an Executive Order, Regulatory Freeze Pending Review, which withdrew all rules which had been sent to the Office of
the Federal Register but not yet published, so they could be reviewed and approved. This PHMSA final rule has yet to be published in the Federal
Register. The adoption of laws or regulations that apply more comprehensive or stringent safety standards can increase the expenses we incur for
gathering service.
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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,
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.
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 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.
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 and 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
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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 greenhouse gas 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 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. However, the United States indicated in January 2025 it will withdraw from the Paris Agreement, and changes undertaken by the
new U.S. Presidential Administration have or may in the future reverse or rescind climate-related initiatives and regulations adopted by prior
administrations and focus on driving increased U.S. energy production. 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.
Sustainability Review
We are committed to addressing key environmental issues from our operations, as well as relevant social issues for the people across our operations,
while upholding the values and principles upon which we were founded. We adhere to high operating standards with a strong focus on environmental
protection, employee health and safety, and positive community engagement.
We proudly accept the responsibility and privilege of being part of the solution to the significant challenges of our nation’s energy, environment, and
economic security. By providing a reliable supply of abundant domestic energy from assets with a smaller environmental footprint than newly drilled
wells, we support our nation’s energy security. We invest in and implement measures to reduce emissions at our facilities, produce differentiated natural
gas through industry-recognized emissions detection, measurement, and mitigation processes, and retire orphan wells for several states, contributing to
environmental best practices. Additionally, we provide affordable and sustainable domestic energy, direct and indirect employment, mineral royalties,
and support tax revenues for the communities where we operate, contributing to economic prosperity, opportunity, and security.
We invite you to explore our annual Sustainability Report, typically released in the second calendar quarter, to gain insights into our actions aimed at
identifying, improving, and monitoring our sustainability efforts focused on planet, people, and principles. Our Sustainability Reports are available on our
website at www.div.energy.
Incentivizing Performance
Our commitment to climate and business resiliency is reflected, in part, in our compensation plans for executives and senior leaders. Depending on their
respective roles in the Group, these leaders have a proportion of their variable pay each year tied to the delivery of sustainability and climate-related
targets.
The Board and its Remuneration Committee annually review the appropriateness of the measures incorporated into the Executive Director’s annual
bonus plan and have consistently increased the non-financial sustainability-related component within the plan. For the year ended 2024, this component
represented 30% of the total eligible bonus, including a 15% environmental component directly related to methane intensity reductions and pneumatic
valve replacements. This plan and its results are audited annually.
Since 2022, 20% of the Executive Director’s long-term incentive plan (“LTIP”) also has been tied to non-financial climate targets. Audited annually, the
LTIP contains a three-year vesting period with 20% of the incentive specifically tied to tactical methods to achieve additional methane intensity
reductions in our climate journey.
For the Executive Director in the 2025 calendar year, the annual bonus and LTIP percentages tied to non-financial sustainability-related performance
remain at 25% and 20%, respectively.
Similar short- and long-term climate-related incentive compensation metrics are also applicable to members of senior leadership who play an active role
in executing the Group’s tactical emission reduction plans as well as executing other operational and environmental stewardship initiatives.
For more information on the performance conditions attached to executive remuneration incentive arrangements, refer to the Remuneration
Committee's Report within this Annual Report & Form 20-F.
18
Section 172 Companies Act Statement
In compliance with sections 172 (‘Section 172”) and 414CZA of the UK Companies Act, the Board makes the following statement in relation to the year
ended December 31, 2024:
Our stakeholders are the many individuals and organizations that are affected by or interact with our operations and with whom we therefore seek to
proactively and positively engage. We strive to maintain productive, mutually beneficial relationships with each stakeholder group by treating all
stakeholders with fairness and respect and by providing timely and effective information and responses.
We maintain several communication methods that afford two-way engagement with our stakeholder groups, including interactions via face-to-face,
telephone, or email exchange; published company reports, press releases, and investor presentations; industry or conference participation; and other
company engagement.
As the owner and operator of long-life assets, we aim to make decisions that consider both the long-term success of Diversified and value creation for
our stakeholders. Engaging with our stakeholders informs our decision-making, including consideration of our long-term strategic objectives and the
activities that support these aims, such as merger and acquisition diligence and the management of climate risk.
The following information provides a summary of stakeholder engagements from 2024.
Employees
We know our employees are essential to our success and growth. We recognize the need for a skilled and committed workforce, with a diverse range of
experience and perspectives, and we value the contribution it affords.
Key Areas of Focus
Incident management
Employee, driver and process safety
Employee development
Workplace culture
Action and Engagement
Our CEO and other executive management periodically conduct town hall meetings and field visits to personally and directly engage with employees and
to provide opportunities for employees to have direct management engagement. Our Board’s Non-Executive Director Employee Representative, Sandra
M. Stash, also periodically engages with the workforce to receive employee feedback on our business strategy, corporate culture and remuneration
policies, and shares this feedback with the Board. The valuable feedback from these meetings, along with that resulting from a periodic corporate-wide
Employee Experience Survey, when applicable, is used to strengthen future employee engagement and initiatives. We also regularly conduct new hire
surveys regarding the onboarding process and exit interviews, both important tools to further improve employee experiences.
In 2024, our CEO, accompanied by members of the executive and senior management teams, visited several locations across our operating footprint,
conducting town hall meetings with some 60% of total employees and presenting updates on strategic operational and financial company initiatives. To
better support our employees, we expanded our family-focused programs to include an Employee Adoption Program, which provides financial assistance
and maternal or paternal leave for the adoption process, and further continued our focus on mental and physical well-being through health and fitness
challenges and educational webinars.
Communities
We actively support sustainable socio-economic development in the communities in which we live and work and aim to minimize any potential negative
impacts from our operations. Community engagement includes developing and maintaining trusted relationships with our land and mineral owners with
the recognition that these relationships are key to our acquisitive business strategy and ability to achieve our operational goals. From personal and
socio-economic investment to strategic academic and educational support, our employees engage and serve their local communities through effective
partnerships that make a real difference.
Key Areas of Focus
Incident management
Effective grievance mechanisms
Environmental protection
Royalty payments
Socio-economic investment and outreach
Local hiring
Action and Engagement
Through our formalized Community Giving and Engagement Program and other corporate initiatives throughout our operating footprint, in 2024 we
provided approximately $2.1 million in financial support to numerous organizations, including adult and children’s health and well-being programs, local
food banks, secondary and higher educational programs and initiatives, student athlete-related ventures and engagements, and municipal services. We
were especially pleased to support children’s initiatives which included, for the fourth consecutive year, distributing $205,000 worth of winter coats to
more than 2,700 children in nine schools through Operation Warm. We also supported 12 different foster care organizations and provided meals for the
associated families and workers within these organizations.
Our employees responded to more than 33,000 inquiries from our royalty and surface owners through our corporate call center. We also distributed
approximately $167 million in royalty payments to more than 84,000 royalty owners in 2024.
Equity and Debt Investors
We actively engage with our capital market partners, financial institutions and rating agencies to support a full understanding of our business and
progress against our strategic priorities.
19
Key Areas of Focus
Emissions reductions
Climate risk and energy transition
Incident management
Risk management
Corporate Governance
Financial stability
Access to funding
Action and Engagement
We regularly provide financial, operational and other sustainability performance updates to our equity and debt investors. These updates may be in the
form of investor relations presentations, press releases, website updates, or direct calls and meetings, inclusive of the CEO, CFO, SVP-Investor
Relations, SVP-Sustainability, SVP-EHS and/or Board Chairman, as applicable. The Annual General Meeting (“AGM”) also provides an opportunity for
shareholders to engage with the Board and Executive Management.
Our increasing participation in energy conferences, industry events and non-deal roadshows has provided added opportunities for discussions with
current and potential Credit Facility lenders and ABS investors particularly interested in our sustainability and emissions reductions strategies, activities
and results. Reflective of that interest by ABS investors and our commitment to climate and operating targets, certain of our ABS transactions, as well as
our sustainability-linked Credit Facility, have included interest rate impacts tied to certain of these sustainability targets.
Governments
We seek to develop and maintain positive relationships and regular dialogue with various stakeholder groups within our federal, state and local
governments.
Key Areas of Focus
Legal compliance
Tax payments to governments
Safe and efficient asset retirement
Emissions reductions
Risk management
Environmental protection
Action and Engagement
Executive and operational management engage with federal, state and local regulators to address legislative, regulatory and operational matters
important to our company and our industry. With risk identification and protection of the local environment and biodiversity in mind, we proactively
engage applicable regulatory agencies before commencing a project to foster transparent dialogue during the completion and approval of applicable
environmental assessments and related actions.
We seek to keep regulatory agencies appraised of our operational and well retirement activities and to provide objective and measurable progress
indicators. Our Next LVL Energy well retirement subsidiary supports company efforts to exceed annual state plugging requirements and well retirement
needs of other oil and gas operators in the Appalachia Region as well as the individual states in their respective federal orphan well retirement
programs.
Customers
We believe hydrocarbon production is, and will continue to be, essential to supporting modern human life. Therefore, we work hard to deliver
environmentally-focused, responsibly produced natural gas, NGLs and oil that satisfy regulatory requirements and meet the energy demands of our local
communities and customers while supporting our climate goals.
Key Areas of Focus
Incident management
Process safety
Access to funding
Action and Engagement
We delivered 791 MMcfepd in 2024 with no cited process and pipeline safety events or associated civil penalties. We continue to use our
pipeline awareness programs to provide relevant information and education to those who interact with our assets or employees.
Business Partners
We aim to establish mutually beneficial relationships with our business partners. As operator, we work on behalf of our joint operating partners to safely
and efficiently manage the assets and deliver our products. Further, we strive to develop strong relationships with our contractors and suppliers that are
built on trust, transparency and quality products and services.
Key Areas of Focus
Access to funding
Risk management
Employee and process safety
Accident prevention
Procurement management
20
Action and Engagement
We fulfill our responsibility as operator by responsibly managing the wells, ensuring payment of related expenses, and distributing to our joint interest
partners the applicable revenues and royalties from the wells’ commodity sales.
We use local contractors and suppliers in each of the states in which we conduct our operations. We engage the expertise and capability of a leading
supply chain risk management firm to continuously screen and monitor contractor safety performance and compliance through stringent operating
guidelines. With a network of approximately 700 contractors, this real-time monitoring helps to ensure our contractors are providing us with the
necessary product and service quality to meet the expectations of our stakeholders and supports ongoing agreements with those contractors who satisfy
our safety thresholds.
Financial Review
Operating Results
Key Factors Affecting Our Performance
Our financial condition and results of operations have been, and will continue to be, affected by a number of important factors, including the following:
Strategic Acquisitions
We have made, and will continue to make, strategic acquisitions to strengthen our current market presence and expand into new markets. We have
made the following business combinations or asset acquisitions for a total aggregate consideration of $939 million during the years ended December 31,
2024, 2023 and 2022, comprised of:
October 2024: The East Texas II Acquisition, in which we acquired certain upstream assets and related infrastructure in the Central Region;
August 2024: The Crescent Pass Acquisition, in which we acquired certain upstream assets and related infrastructure in the Central Region;
June 2024: The Oaktree Acquisition, in which we acquired Oaktree’s proportionate working interest in the East Texas, Tapstone, Tanos and Indigo
acquisitions;
March 2023: The Tanos II Assets Acquisition, in which we acquired certain upstream assets and related infrastructure in the Central Region;
September 2022: The ConocoPhillips Assets Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the
Central Region;
July 2022: Certain plugging infrastructure in the Appalachian Region;
May 2022: Certain plugging infrastructure in the Appalachian Region;
April 2022:
The East Texas I Acquisition, in which we acquired working interests in certain upstream assets and related facilities within the Central Region
from a private seller, in conjunction with Oaktree;
Certain midstream assets, inclusive of a processing facility, in the Central Region that was contiguous to our East Texas I assets; and
February 2022: Certain plugging infrastructure in the Appalachian Region.
Our strategic acquisitions may impact the comparability of our financial results across different periods. We plan to continue selectively pursuing
acquisitions to continue to produce reliable free cash flow for our shareholders. We will evaluate and execute opportunities that complement and scale
our business, optimize profitability, expand into adjacent markets, and add new capabilities.
Recent Developments
In March 2025, the Group announced the completion of its previously announced Maverick acquisition for a gross purchase price of approximately
$1,275 million. The transaction was funded through the assumption of approximately $700 million of Maverick debt outstanding, the issuance of
21,194,213 new ordinary shares direct to the unitholders of Maverick, and approximately $207 million in cash on hand.
In March 2025, in connection with the close of the Maverick acquisition, the Group amended and restated the credit agreement governing its Credit
Facility. The amendment extended the maturity of the Credit Facility to March 2029 and increased the borrowing base to $900 million, primarily
resulting from the additional collateral acquired from Maverick. There were no other material changes to pricing or terms. The Group utilized the
proceeds from the upsized borrowing base to fund a portion of the Maverick acquisition and repay the outstanding principal on Term Loan II.
In February 2025, the Group 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 at par value (“the ABS X Notes”). The Group utilized the proceeds from
the ABS X Notes to refinance the ABS I Notes, ABS II Notes, and Term Loan I, and to fund the Summit Natural Resources (“Summit”) transaction.
In February 2025, the Group announced the completion of its previously announced acquisition of certain upstream assets and related
infrastructure within Virginia, West Virginia, and Alabama of the Appalachian Region from Summit for a gross purchase price of approximately $45
million before customary purchase price adjustments. The transaction was funded through the new ABS X Notes collateralized, in part, by the
acquired assets.
In February 2025, the Company issued 8,500,000 new ordinary shares at $14.50 per share to raise gross proceeds of $123 million. In addition, the
Company has granted the underwriters a 30-day option to purchase up to an additional 850,000 ordinary shares at the public offering price, less
underwriting discount. The Group used the net proceeds to repay a portion of the debt to be incurred in connection with the Maverick transaction.
Refer to Notes 5, 16, and 21 in the Notes to the Group Financial Statements for additional information regarding acquisitions, share capital, and debt.
Segment Reporting
Our operations consist of one reportable segment in the United States under IFRS 8. Refer to Note 2 in the Notes to the Group Financial Statements for
a description of our segment reporting.
Results of Operations
Refer to APMs within this Annual Report & Form 20-F for information on how certain of the metrics below are calculated and reconciled to IFRS
measures. Discussion related to prior period results can be found in the Results of Operations section of our 2023 Annual Report & Form 20-F on our
website at www.div.energy.
21
Year Ended
December 31, 2024
December 31, 2023
Change
% Change
Net production
Natural gas (MMcf)
244,298
256,378
(12,080)
(5%)
NGLs (MBbls)
5,980
5,832
148
3%
Oil (MBbls)
1,568
1,377
191
14%
Total production (MMcfe)
289,586
299,632
(10,046)
(3%)
Average daily production (MMcfepd)
791
821
(30)
(4%)
% Natural gas (Mcfe basis)
84%
86%
Average realized sales price
(excluding impact of derivatives settled in cash)
Natural gas (Mcf)
$1.90
$2.17
$(0.27)
(12%)
NGLs (Bbls)
25.17
24.23
0.94
4%
Oil (Bbls)
74.71
75.46
(0.75)
(1%)
Total (Mcfe)
$2.53
$2.68
$(0.15)
(6%)
Average realized sales price
(including impact of derivatives settled in cash)
Natural gas (Mcf)
$2.57
$2.86
$(0.29)
(10%)
NGLs (Bbls)
24.32
26.05
(1.73)
(7%)
Oil (Bbls)
69.54
68.44
1.10
2%
Total (Mcfe)
$3.05
$3.27
$(0.22)
(7%)
Revenue (in thousands)
Natural gas
$464,600
$557,167
$(92,567)
(17%)
NGLs
150,513
141,321
9,192
7%
Oil
117,146
103,911
13,235
13%
Total commodity revenue
$732,259
$802,399
$(70,140)
(9%)
Midstream revenue
32,535
30,565
1,970
6%
Other revenue
30,047
35,299
(5,252)
(15%)
Total revenue
$794,841
$868,263
$(73,422)
(8%)
Gain (loss) on derivative settlements
(in thousands)
Natural gas
$164,452
$177,139
$(12,687)
(7%)
NGLs
(5,055)
10,594
(15,649)
(148%)
Oil
(8,108)
(9,669)
1,561
(16%)
Net gain (loss) on commodity derivative settlements(a)
$151,289
$178,064
$(26,775)
(15%)
Total revenue, inclusive of settled hedges
$946,130
$1,046,327
$(100,197)
(10%)
22
Year Ended
December 31, 2024
December 31, 2023
Change
% Change
Per Mcfe Metrics
Average realized sales price
(including impact of derivatives settled in cash)
$3.05
$3.27
$(0.22)
(7%)
Midstream and other revenue
0.22
0.22
—%
LOE
(0.80)
(0.71)
(0.09)
13%
Midstream operating expense
(0.24)
(0.23)
(0.01)
4%
Employees, administrative costs and professional services
(0.30)
(0.26)
(0.04)
15%
Recurring allowance for credit losses
(0.03)
0.03
(100%)
Production taxes
(0.12)
(0.21)
0.09
(43%)
Transportation expense
(0.31)
(0.32)
0.01
(3%)
Proceeds received from leasehold sales(b)
0.14
0.09
0.05
56%
Adjusted EBITDA per Mcfe
$1.64
$1.82
$(0.18)
(10%)
Adjusted EBITDA margin
50%
52%
Other financial metrics (in thousands)
Operating profit (loss)
$(43,026)
$1,161,051
$(1,204,077)
(104%)
Net income (loss)
$(87,001)
$759,701
$(846,702)
(111%)
Adjusted EBITDA
$472,309
$546,788
$(74,479)
(14%)
(a)Net gain (loss) on commodity derivative settlements represents cash (paid) or received on commodity derivative contracts. This excludes settlements on foreign
currency and interest rate derivatives as well as the gain (loss) on fair value adjustments for unsettled financial instruments for each of the periods presented.
(b)Proceeds received from leasehold sales consists of $27 million, $24 million and $2 million in cash proceeds received for leasehold sales during the years ended
December 31, 2024, 2023 and 2022, respectively, less $14 million and $4 million of basis in leasehold sales for the years ended December 31, 2024 and 2023,
respectively.
Forward-Looking Statements
This Annual Report & Form 20-F contains forward-looking statements that can be identified by the following terminology, including the terms “may,”
“might,” “will,” “could,” “would,” “should,” “expect,” “plan,” “anticipate,” “intend,” “seek,” “believe,” “estimate,” “predict,” “potential,” “continue,”
“contemplate,” “possible,” or the negative of these terms or other variations or comparable terminology, or by discussions of strategy, plans, objectives,
goals, future events or intentions. These forward-looking statements include all matters that are not historical facts. They appear in a number of places
throughout this Annual Report & Form 20-F and include, but are not limited to, statements regarding our intentions, beliefs or current expectations
concerning, among other things, our results of operations, financial positions, liquidity, prospects, growth, strategies and the natural gas and oil
industry. By their nature, forward-looking statements involve risk and uncertainty because they relate to future events and circumstances.
Forward-looking statements are not guarantees of future performance and the actual results of our operations, financial position and liquidity, and the
development of the markets and the industry in which we operate, may differ materially from those described in, or suggested by, the forward-looking
statements contained in this Annual Report & Form 20-F. In addition, even if the results of operations, financial position and liquidity, and the
development of the markets and the industry in which we operate are consistent with the forward-looking statements contained in this Annual Report &
Form 20-F, those results or developments may not be indicative of results or developments in subsequent periods. A number of factors could cause
results and developments to differ materially from those expressed or implied by the forward-looking statements including, without limitation, general
economic and business conditions, the behavior of other market participants, industry trends, competition, commodity prices, changes in regulation,
currency fluctuations, our ability to recover our reserves, our ability to successfully integrate acquisitions, our ability to obtain financing to meet liquidity
needs, changes in our business strategy, political and economic uncertainty.
Forward-looking statements may, and often do, differ materially from actual results. Any forward-looking statements in this Annual Report & Form 20-F
speak only as of the date of this Annual Report & Form 20-F, reflect our current view with respect to future events and are subject to risks relating to
future events and other risks, uncertainties and assumptions relating to our operations, results of operations, growth strategy and liquidity. Investors
should specifically consider the factors identified in this Annual Report & Form 20-F which could cause actual results to differ before making an
investment decision. Subject to the requirements of the Prospectus Rules, the Disclosure and Transparency Rules and the Listing Rules or applicable
law, we explicitly disclaim any obligation or undertaking publicly to release the result of any revisions to any forward-looking statements in this Annual
Report & Form 20-F that may occur due to any change in our expectations or to reflect events or circumstances after the date of this Annual Report &
Form 20-F
Production, Revenue & Hedging
Total revenue in the year ended December 31, 2024 of $795 million decreased 8% from $868 million reported for the year ended December 31, 2023,
primarily due to a 6% decrease in the average realized sales price, excluding the impact of derivatives settled in cash, and 3% lower production which
was primarily related to the sale of equity interest in DP Lion Equity Holdco in December 2023 along with normal declines. This decrease was partially
offset by increased production as a result of the Oaktree, Crescent Pass, and East Texas II acquisitions in 2024. Including commodity hedge settlement
gains of $151 million and $178 million in 2024 and 2023, respectively, total revenue, inclusive of settled hedges, decreased by 10% to $946 million in
2024 from $1,046 million in 2023.
23
The following table summarizes average commodity prices for the periods presented with Henry Hub on a per Mcf basis and Mont Belvieu and WTI on a
per Bbl basis:
Year Ended
December 31, 2024
December 31, 2023
$ Change
% Change
Henry Hub
$2.27
$2.74
$(0.47)
(17%)
Mont Belvieu
38.16
34.11
4.05
12%
WTI
75.72
77.62
(1.90)
(2%)
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)
Natural Gas
NGLs
Oil
Total
Commodity revenue for the year ended December 31, 2022
$1,544,658
$188,733
$139,620
$1,873,011
Volume increase (decrease)
4,717
22,935
(15,903)
11,749
Price increase (decrease)
(992,208)
(70,347)
(19,806)
(1,082,361)
Net increase (decrease)
(987,491)
(47,412)
(35,709)
(1,070,612)
Commodity revenue for the year ended December 31, 2023
$557,167
$141,321
$103,911
$802,399
Volume increase (decrease)
(26,214)
3,586
14,413
(8,215)
Price increase (decrease)
(66,353)
5,606
(1,178)
(61,925)
Net increase (decrease)
(92,567)
9,192
13,235
(70,140)
Commodity revenue for the year ended December 31, 2024
$464,600
$150,513
$117,146
$732,259
To manage our cash flows in a volatile commodity price environment and as required by our SPV-level asset-backed securities, we utilize derivative
hedging contracts that allow us to fix the per unit sales prices for our production. 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 hedge impact on commodity
revenue, excluding and including cash received for commodity hedge settlements:
(In thousands, except per
unit data)
Year Ended December 31, 2024
Natural Gas
NGLs
Oil
Total Commodity
Revenue
Realized $
Revenue
Realized $
Revenue
Realized $
Revenue
Realized $
per Mcf
per Bbl
per Bbl
per Mcfe
Excluding hedge impact
$464,600
$1.90
$150,513
$25.17
$117,146
$74.71
$732,259
$2.53
Commodity hedge impact
164,452
0.67
(5,055)
(0.85)
(8,108)
(5.17)
151,289
0.52
Including hedge impact
$629,052
$2.57
$145,458
$24.32
$109,038
$69.54
$883,548
$3.05
(In thousands, except per
unit data)
Year Ended December 31, 2023
Natural Gas
NGLs
Oil
Total Commodity
Revenue
Realized $
Revenue
Realized $
Revenue
Realized $
Revenue
Realized $
per Mcf
per Bbl
per Bbl
per Mcfe
Excluding hedge impact
$557,167
$2.17
$141,321
$24.23
$103,911
$75.46
$802,399
$2.68
Commodity hedge impact
177,139
0.69
10,594
1.82
(9,669)
(7.02)
178,064
0.59
Including hedge impact
$734,306
$2.86
$151,915
$26.05
$94,242
$68.44
$980,463
$3.27
Refer to Note 13 in the Notes to the Group Financial Statements for additional information regarding derivative financial instruments.
24
Expenses
(In thousands, except per unit data)
Year Ended
December
31, 2024
December
31, 2023
Total Change
Per Mcfe Change
Per Mcfe
Per Mcfe
$
%
$
%
LOE(a)
$231,651
$0.80
$213,078
$0.71
$18,573
9%
$0.09
13%
Production taxes(b)
36,043
0.12
61,474
0.21
(25,431)
(41%)
(0.09)
(43%)
Midstream operating expenses(c)
70,747
0.24
69,792
0.23
955
1%
0.01
4%
Transportation expenses(d)
90,461
0.31
96,218
0.32
(5,757)
(6%)
(0.01)
(3%)
Total operating expenses
$428,902
$1.47
$440,562
$1.47
$(11,660)
(3%)
$
—%
Employees, administrative costs and
professional services(e)
86,885
0.30
78,659
0.26
8,226
10%
0.04
15%
Costs associated with acquisitions(f)
11,573
0.04
16,775
0.06
(5,202)
(31%)
(0.02)
(33%)
Other adjusting costs(g)
22,375
0.08
17,794
0.06
4,581
26%
0.02
33%
Non-cash equity compensation(h)
8,286
0.03
6,494
0.02
1,792
28%
0.01
50%
Total operating and G&A expenses
$558,021
$1.92
$560,284
$1.87
$(2,263)
—%
$0.05
3%
Depreciation, depletion and amortization
256,484
0.89
224,546
0.75
31,938
14%
0.14
19%
Allowance for credit losses(i)
101
8,478
0.03
(8,377)
(99%)
(0.03)
(100%)
Total expenses
$814,606
$2.81
$793,308
$2.65
$21,298
3%
$0.16
6%
(a)LOE encompasses costs incurred to maintain producing properties. These costs include direct and contract labor, repairs and maintenance, emissions reduction
initiatives, water hauling, compression, automobile, insurance, and materials and supplies expenses.
(b)Production taxes consist of severance and property taxes. Severance taxes are typically paid on produced natural gas, NGLs and oil at fixed rates set by federal, state or
local taxing authorities. Property taxes are generally based on the valuation of the Group’s natural gas and oil properties and midstream assets by the taxing
jurisdictions.
(c)Midstream operating expenses are the daily costs of operating the Group’s owned midstream assets, including employee and benefit expenses.
(d)Transportation expenses are the daily costs incurred from third-party systems to gather, process, and transport the Group’s natural gas, NGLs and oil.
(e)Employees, administrative costs and professional services include payroll and benefits for our administrative and corporate staff, costs of maintaining administrative and
corporate offices, managing our production operations, franchise taxes, public company costs, fees for audit and other professional services, and legal compliance.
(f)Costs associated with acquisitions are related to the integration of acquisitions, which vary for each acquisition. For acquisitions classified as business combinations,
these costs include transaction costs directly associated with a successful acquisition. They also encompass costs related to transition service arrangements, where the
Group pays the seller of the acquired entity a fee to manage G&A functions until full integration of the assets. Additionally, these costs include costs to cover expenses
for integrating IT systems, consulting, and internal workforce efforts directly related to incorporating acquisitions into the Group’s systems.
(g)Other adjusting costs include items that affect the comparability of results or are not indicative of ongoing business trends. These costs consist of one-time projects,
contemplated transactions or financing arrangements, contract terminations, deal breakage and/or sourcing costs for acquisitions, and unused firm transportation.
(h)Non-cash equity compensation represents the expense recognition for share-based compensation provided to key members of the management team. Refer to Note 17
in the Notes to the Group Financial Statements for additional details on non-cash share-based compensation.
(i)Allowance for credit losses consists of the recognition and reversal of credit losses. Refer to Note 14 in the Notes to the Group Financial Statements for additional
information regarding credit losses.
Operating Expenses
Per unit operating expense remained flat year-over-year, resulting from:
Higher per unit LOE that increased 13%, or $0.09 per Mcfe, which is reflective of the Oaktree, Crescent Pass, and East Texas II acquisitions in 2024.
Lower per unit production taxes that declined 43%, or $0.09 per Mcfe were primarily attributable 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;
Higher per unit midstream operating expense that increased 4%, or $0.01 per Mcfe were primarily attributable to the growth in our midstream
operations due to Central region expansion; and
Lower per unit transportation expenses that declined 3%, or $0.01 per Mcfe, were primarily related to decreases in commodity price-linked
components of third-party midstream rates and costs.
General and Administrative Expense
G&A expense increased primarily due to:
Higher employees, administrative costs and professional services resulting in additional cost to support our ongoing growth through acquisitions. On
a per Mcfe basis, these costs increased 15%, or $0.04 per Mcfe;
Lower costs associated with acquisitions primarily related to a reduction in legal and consulting services incurred in 2024 as compared to 2023. On a
per Mcfe basis, these costs decreased 33% or $0.02 per Mcfe;
Higher other adjusting costs primarily related to increased costs associated with litigation expense. These costs were partially offset by decreases in
costs related to unused firm transportation and employee severance costs. On a per Mcfe basis, these costs increased 33%, or $0.02 per Mcfe; and
25
Higher non-cash equity compensation due to an increase in the number of participants in the long-term incentive plan in 2024. On a per Mcfe basis,
these costs increased 50%, or $0.01 per Mcfe.
Other Expenses
Depreciation, depletion and amortization (“DD&A”) increased due to:
Higher depletion expense as a result of 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 proved
reserves decrease was partially offset by the acquisition of the Oaktree, Crescent Pass, and East Texas II assets in 2024.
Allowance for credit losses decreased due to:
The impact on anticipated credit losses on joint interest owner receivables has a direct relationship with pricing and distributions to individual
owners. As the pricing environment declined in 2023, the underlying well economics did as well, and as a result, in 2023, we increased our reserve
by $8 million. In 2024, with pricing more stable, no such adjustment to the reserve was deemed necessary.
Refer to Notes 5, 10, 11 and 13 in the Notes to the Group Financial Statements for additional information regarding acquisitions, natural gas and oil
properties, property, plant and equipment and derivative financial instruments, respectively.
Derivative Financial Instruments
We recorded the following gain (loss) on derivative financial instruments in the Consolidated Statement of Comprehensive Income for the periods
presented:
(In thousands)
Year Ended
December 31, 2024
December 31, 2023
$ Change
% Change
Net gain (loss) on commodity derivatives
settlements(a)
$151,289
$178,064
$(26,775)
(15%)
Net gain (loss) on interest rate swap(a)
190
(2,722)
2,912
(107%)
Gain (loss) on foreign currency hedges(a)
(521)
521
(100%)
Total gain (loss) on settled derivative
instruments
$151,479
$174,821
$(23,342)
(13%)
Gain (loss) on fair value adjustments of unsettled
financial instruments(b)
(189,030)
905,695
(1,094,725)
(121%)
Total gain (loss) on derivative financial
instruments
$(37,551)
$1,080,516
$(1,118,067)
(103%)
(a)Represents the cash settlement of hedges that settled during the period.
(b)Represents the change in fair value of financial instruments net of removing the carrying value of hedges that settled during the period.
For the year ended December 31, 2024, we recognized a loss on derivative financial instruments of $38 million compared to a gain of $1,081 million in
2023. Adjusting our unsettled derivative contracts to their fair values drove a loss of $189 million in 2024, as compared to a gain of $906 million in 2023,
which is reflective of higher commodity prices on the forward curve.
For the year ended December 31, 2024, we recognized a gain on settled derivative instruments of $151 million as compared to a gain of $175 million in
2023. The gain on settled derivative instruments relates to lower commodity market prices than those we secured through our derivative contracts. With
consistent reliable cash flows central to our strategy, we routinely hedge at levels that, based on our operating and overhead costs, provide a significant
adjusted EBITDA margin even if it means forgoing potential price upside.
Refer to Note 13 in the Notes to the Group Financial Statements for additional information regarding derivative financial instruments.
Finance Costs
(In thousands)
Year Ended
December 31, 2024
December 31, 2023
$ Change
% Change
Interest expense, net of capitalized and income
amounts(a)
$120,773
$117,808
$2,965
3%
Amortization of discount and deferred finance costs
16,870
16,358
512
3%
Total finance costs
$137,643
$134,166
$3,477
3%
(a)Includes payments related to borrowings and leases.
For the year ended December 31, 2024, interest expense of $121 million increased by $3 million compared to $118 million in 2023, primarily related to
interest on the new ABS IX Notes, Oaktree Seller’s Note, and Term Loan II. These increases were partially offset by lower outstanding balances on our
existing ABS structures.
As of December 31, 2024 and 2023, total borrowings were $1,736 million and $1,325 million, respectively. For the period ended December 31, 2024,
the weighted average interest rate on borrowings was 7.37% as compared to 6.03% as of December 31, 2023. As of December 31, 2024, 83% of our
borrowings reside in fixed-rate, hedge-protected, amortizing structures compared to 87% as of December 31, 2023.
26
Refer to Notes 5, 20, and 21 in the Notes to the Group Financial Statements for additional information regarding acquisitions, leases and borrowings,
respectively.
Taxation
The effective tax rate is calculated on the face of the Statement of Comprehensive Income by dividing the amount of recorded income tax benefit
(expense) by the income (loss) before taxation as follows:
(In thousands)
Year Ended
December 31, 2024
December 31, 2023
$ Change
% Change
Income (loss) before taxation
$(223,952)
$1,000,344
$(1,224,296)
(122%)
Income tax benefit (expenses)
136,951
(240,643)
377,594
(157%)
Effective tax rate
61.2%
24.1%
The differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:
Year Ended
December 31, 2024
December 31, 2023
December 31, 2022
Expected tax at statutory U.S. federal income tax rate
21.0%
21.0%
21.0%
State income taxes, net of federal tax benefit
3.7%
3.1%
1.2%
Federal credits
41.3%
—%
—%
Other, net
(4.8%)
—%
0.2%
Effective tax rate
61.2%
24.1%
22.4%
For the year ended December 31, 2024, we reported a tax benefit of $137 million, a change of $378 million, compared to expense of $241 million in
2023 which was a result of the change in the loss before taxation and a change in the amount of tax credits generated relative to the pre-tax loss. The
resulting effective tax rates for the years ended December 31, 2024 and 2023 were 61.2% and 24.1%, respectively. The effective tax rate can be
materially impacted by the recognition of the marginal well tax credit available to qualified producers as noted 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 encourage companies to continue operating
lower-volume wells during periods of low prices to maintain production and the underlying jobs they create and the state and local tax revenues they
generate for communities to support schools, social programs, law enforcement and other similar public services.
Refer to Note 8 in the Notes to the Group Financial Statements for additional information regarding taxation.
Operating Profit, Net Income, Adjusted EBITDA & EPS
(In thousands, except per unit data)
Year Ended
December 31, 2024
December 31, 2023
$ Change
% Change
Operating profit (loss)
$(43,026)
$1,161,051
$(1,204,077)
(104%)
Net income (loss) attributable to Owners of Diversified
Energy Company PLC
(88,272)
758,018
(846,290)
(112%)
Adjusted EBITDA
472,309
546,788
(74,479)
(14%)
Earnings (loss) per share - basic
$(1.84)
$16.07
$(17.91)
(111%)
Earnings (loss) per share - diluted
$(1.84)
$15.95
$(17.79)
(112%)
For the year ended December 31, 2024, we reported a net loss of $88 million and basic and diluted loss per share of $1.84 compared to net income of
$758 million and basic EPS of $16.07 ($15.95 diluted EPS) in 2023, a decrease of 112%. We also reported an operating loss of $43 million compared
with an operating profit of $1,161 million for the years ended December 31, 2024 and 2023, respectively. This year-over-year decrease in net income
was primarily attributable to a $1,118 million decrease in gains on derivatives due to changes in commodity prices on the forward curve, a $24 million
decrease in gains on sale of assets, a decrease in gross profit of $94 million, a $3 million increase in finance costs, partially offset by a $378 million
swing in income tax expense to a benefit as compared to 2023, as a result of marginal well credits.
Excluding the mark-to-market loss on long-dated derivative valuations, as well as other customary adjustments, we reported adjusted EBITDA of $472
million for the year ended December 31, 2024 compared to $547 million for the year ended December 31, 2023, representing a decrease of 14% driven
by a decrease in commodity pricing and production from prior year, primarily as a result of our sale of equity interest in DP Lion Equity Holdco in
December 2023, in addition to normal declines. These decreases were partially offset by adjusted EBITDA growth through the Oaktree, Crescent Pass,
and East Texas II acquisitions in 2024.
Liquidity & Capital Resources
Overview
Our principal sources of liquidity are cash generated from operations and available borrowings under our Credit Facility. To minimize interest expense,
we use our excess cash flow to reduce borrowings on our Credit Facility. Consequently, we have historically maintained low cash balances on our
Consolidated Statement of Financial Position, as evidenced by the $6 million and $4 million in cash and cash equivalents as of December 31, 2024 and
2023, respectively.
27
When we acquire assets for growth, we complement our Credit Facility with long-term, fixed rate, fully-amortizing, asset-backed debt secured by certain
natural gas and oil assets. 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, value-adding acquisitions, and to maintain an appropriate leverage profile for the
assets we acquire, we also periodically raise funds through secondary equity offerings.
We closely monitor our working capital to ensure it remains sufficient for business operations, using any excess liquidity primarily to repay debt.
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 $52 million for the year ended December 31, 2024, compared to $74 million for the year ended December 31, 2023. This
decrease was primarily driven by the completion of wells in 2023 that were under development at the time of the March 2023 Tanos II acquisition.
Although we completed additional wells in 2024, the capital expenditures required for their development were less significant than those in 2023.
Additionally, we made improvements at our Black Bear facility in the Central Region in 2024, which contributed to the overall capital expenditure. 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 our growth rate, commodity prices and future acquisitions.
With respect to our 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.
Refer to Note 21 in the Notes to the Group Financial Statements for additional information regarding our current debt obligations.
Liquidity
The table below represents our liquidity position as of December 31, 2024 and 2023.
As of
(In thousands)
December 31, 2024
December 31, 2023
Cash and cash equivalents
$5,990
$3,753
Available borrowings under the Credit Facility(a)
86,690
134,817
Liquidity
$92,680
$138,570
(a)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
Our net borrowings consisted of the following as of the reporting date:
As of
(In thousands)
December 31, 2024
December 31, 2023
Total debt
$1,693,242
$1,276,627
LESS: Cash
5,990
3,753
LESS: Restricted cash(a)
46,269
36,252
Net debt
$1,640,983
$1,236,622
(a)The increase of restricted cash as of December 31, 2024, is due to the addition of $21 million and $3 million in restricted cash for the ABS VIII Notes and ABS IX Notes,
respectively, offset by $7 million and $9 million for the retirement of the ABS III Notes and ABS V Notes, respectively.
Our Capital Expenditure Program
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 capacity expansion, 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.
We actively manage our balance sheet and seek to maintain a long-term leverage ratio of approximately 2.5x. We believe this leverage range is
supported by our differentiated business model, characterized by long-life, low-decline production that ensures resilient cash flows. Our strategic
financial framework, strengthened by hedging and amortizing debt instruments, further supports this leverage target.
Looking ahead, we aim to maximize cash flow by maintaining our hedging strategy and capitalizing on market opportunities to enhance the floor price of
our risk management program. We will preserve our strategic advantages through purposeful growth, supported by a disciplined capital expenditure
program. This approach will ensure we secure low-cost financing for acquisitive growth while maintaining appropriate leverage and sufficient liquidity.
Asset Retirement Obligations
We remain proactive and innovative in our approach to asset retirement. Following our LSE IPO in 2017, we initiated meetings with state officials to
develop a long-term plan for retiring our expanding portfolio of long-life wells. By collaborating with state regulators, we have designed our retirement
activities to be equitable for all stakeholders, with a strong emphasis on environmental responsibility.
28
Asset retirements for the year ended December 31, 2024 were as follows:
DEC-owned Appalachian well retirements
202
3rd party-owned Appalachian well retirements(a)
85
Total Appalachian wells retired by Next LVL
287
DEC-owned Central Region well retirements
13
Total wells retired
300
(a)Includes 51 state and federal orphan wells and 34 wells for other operators.
We expanded asset retirement operations from 17 rigs at December 31, 2023 to 18 rigs by December 31, 2024. Our continued growth in capacity
enhances our ability to integrate asset retirement operations and achieve cost efficiencies across a broader footprint. Additionally, it enables us to
generate third-party revenues by offering a suite of services to other production companies and state orphan well programs, which can help fund our
own asset retirement program. Consequently, we aim to achieve a prudent mix of cost reduction and third-party revenues to maximize the benefits of
our internal asset retirement program.
Our asset retirement program demonstrates our strong commitment to a healthy environment and the surrounding communities. We anticipate
continued investment and innovation in this area. In 2025, we will focus on realizing the benefits of vertical integration by expanding our internal asset
retirement capacity. This will help us reduce reliance on third-party contractors, mitigate outsource risks, improve process quality and responsiveness,
and enhance control over environmental remediation and costs.
The composition of the provision for asset retirement obligations at the reporting date was as follows for the periods presented:
Year Ended
(In thousands)
December 31, 2024
December 31, 2023
Balance at beginning of period
$506,648
$457,083
Additions(a)
111,265
3,250
Accretion
30,868
26,926
Asset retirement costs
(6,724)
(5,961)
Disposals(b)
(17,300)
Revisions to estimate(c)
6,521
42,650
Balance at end of period
$648,578
$506,648
Less: Current asset retirement obligations
6,436
5,402
Non-current asset retirement obligations
$642,142
$501,246
(a)Refer to Note 5 in the Notes to the Group Financial Statements for additional information regarding acquisitions and divestitures.
(b)Associated with the divestiture of natural gas and oil properties. Refer to Note 5 in the Notes to the Group Financial Statements for additional information.
(c)As of December 31, 2024, we performed normal revisions to our asset retirement obligations, which resulted in a $7 million million increase in the liability. This increase
was comprised of increases of $95 million for cost revisions, which was partially offset by an $89 million decrease attributable to a higher discount rate as a result of an
increase in bond yield volatility during the year. As of December 31, 2023, we performed normal revisions to our asset retirement obligations, which resulted in a $43
million increase in the liability. This increase was comprised of a $28 million increase attributable to a lower discount rate as a result of slightly decreased bond yields as
compared to 2022 as inflation began to increase at a lower rate and $16 million in cost revisions. Partially offsetting these decreases was a $1 million change attributed
to timing.
The anticipated future cash outflows for our asset retirement obligations on an undiscounted and discounted basis are set forth in the tables below as of
December 31, 2024 and 2023. When discounting the obligation, we apply annual inflationary cost increases to our current cost expectations and then
discount the resulting cash flows using a credit adjusted risk free discount rate resulting in a net discount rate of 3.7% and 3.4% for the periods
indicated, respectively. While the rate is comparatively small to the commonly utilized PV-10 metric in our industry, the impact is significant due to the
long-life low-decline nature of our portfolio. Although productive life varies within our well portfolio, presently we expect all of our existing wells to have
reached the end of their productive lives and be retired by approximately 2098.
When evaluating our ability to meet our asset retirement obligations we review reserves models which utilize the income approach to determine the
expected discounted future net cash flows from estimated reserve quantities. These models determine future revenues associated with production using
forward pricing then consider the costs to produce and develop reserves, as well as the cost of asset retirement at the end of a well’s life. These future
net cash flows are discounted using a weighted average cost of capital of 10% to produce the PV-10 of our reserves. After considering the asset
retirement costs in these models, our PV-10 was approximately $1.6 billion, $2.1 billion and $8.8 billion as of December 31, 2024, 2023 and 2022,
respectively.
As of December 31, 2024:
(In thousands)
Not Later Than
One Year
Later Than One
Year and Not Later
Than Five Years
Later Than
Five Years
Total
Undiscounted
$6,436
$27,913
$2,432,934
$2,467,283
Discounted
6,436
24,450
617,692
648,578
29
As of December 31, 2023:
(In thousands)
Not Later Than
One Year
Later Than One
Year and Not Later
Than Five Years
Later Than
Five Years
Total
Undiscounted
$5,402
$20,365
$1,778,876
$1,804,643
Discounted
5,402
17,975
483,271
506,648
Cash Flows
Our principal sources of liquidity have historically been cash generated from operating activities. To minimize financing costs, we apply our excess cash
flow to reduce borrowings on our Credit Facility.
We monitor our working capital to ensure that the levels remain adequate to operate the business with excess cash primarily being utilized for the
repayment of debt or shareholder distributions. In addition to working capital management, we have a disciplined approach to managing operating costs
and allocating capital resources, ensuring that we are generating returns on our capital investments to support the strategic initiatives in our
business operations.
(In thousands)
Year Ended
December 31, 2024
December 31, 2023
$ Change
% Change
Net cash provided by operating activities
$345,663
$410,132
$(64,469)
(16%)
Net cash used in investing activities
(272,916)
(239,369)
(33,547)
14%
Net cash used in financing activities
(70,510)
(174,339)
103,829
(60%)
Net change in cash and cash equivalents
$2,237
$(3,576)
$5,813
(163%)
Net Cash Provided by Operating Activities
For the year ended December 31, 2024, net cash provided by operating activities of $346 million decreased by $64 million, or 16%, when compared to
$410 million in 2023. The change in net cash provided by operating activities was predominantly attributable to the following:
A decrease in net income of $847 million, driven by a decrease in the fair value adjustments of unsettled derivative financial instruments of $1,095
million, and a decrease of $378 million in income tax expense as a result of marginal well credits; and
Changes in working capital generated reduced cash outflows of $50 million compared to 2023.
Production, realized prices, operating expenses, and G&A are discussed above.
Net Cash Used in Investing Activities
For the year ended December 31, 2024, net cash used in investing activities of $273 million increased by $34 million, or 14%, from outflows of $239
million in 2023. The change in net cash used in investing activities was primarily attributable to the following:
A net increase in cash outflows of $58 million for acquisition, divestiture and disposal activity. Net cash outflows associated with acquisitions,
divestitures and disposals was $220 million during the year ended December 31, 2024 when compared to $162 million for the year ended
December 31, 2023. Refer to Note 5 and Note 11 in the Notes to the Group Financial Statements for additional information regarding acquisitions,
divestitures and disposals; and
A decrease in cash outflows of $22 million for capital expenditures. Capital expenditures were $52 million for the year ended December 31, 2024
compared to $74 million for the year ended December 31, 2023. This decrease was primarily driven by the completion of wells in 2023 that were
under development at the time of the March 2023 Tanos II acquisition. Although we completed additional wells in 2024, the capital expenditures
required for their development were less significant than those in 2023. Additionally, we made improvements at our Black Bear facility in the
Central Region in 2024, which contributed to the overall capital expenditure.
Net Cash Used in Financing Activities
For the year ended December 31, 2024, net cash used in financing activities of $71 million decreased by $103 million, or 59%, as compared to $174
million in 2023. This change in net cash used in financing activities was primarily attributable to the following:
An increase in cash inflows of $202 million related to debt activity. Debt activity resulted in proceeds, or a net cash inflow of $191 million (including
$805 million in repayments of amortizing debt, inclusive of the retirement of ABS III and V Notes and the ABS Warehouse Facility) in 2024 versus
payments, or a net cash outflow, of $11 million in 2023, with much of the change attributable to the issuance of the ABS VIII and IX Notes and the
Term Loan II during 2024, which was partially offset by the retirement of the ABS III and V Notes;
A decrease of $84 million due to a reduction in dividends paid in 2024 as compared to 2023;
A decrease of $6 million due to reduced hedge modifications associated with ABS notes in 2024 as compared to 2023;
An increase of $9 million due to proceeds received as a result of a lease modification for our fleet that was executed in 2024;
A decrease of $157 million in proceeds from the equity issuance in 2023 that did not occur in 2024;
An increase of $29 million due to increased finance costs and restricted cash requirements, primarily attributable to the ABS VIII and IX Notes, and
the Oaktree Seller’s Note issued in 2024, partially offset by the retirement of the ABS III and V Notes; and
An increase of $10 million due to an increase in share repurchases in 2024.
Refer to Notes 16, 18 and 21 in the Notes to the Group Financial Statements for additional information regarding share capital, dividends and
borrowings, respectively.
30
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, 2024
and December 31, 2023, our material off-balance sheet arrangements and transactions include operating service arrangements of $158 million and $14
million in letters of credit outstanding against our Credit Facility. Refer to Contractual Obligations & Contingent Liabilities & Commitments for additional
information regarding off-balance sheet operating service arrangements.
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.
Contractual Obligations & Contingent Liabilities & Commitments
We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual obligations as of
December 31, 2024 were as follows:
(In thousands)
Not Later Than
One Year
Later Than
One Year and
Not Later Than
Five Years
Later Than
Five Years
Total
Recorded contractual obligations
Trade and other payables
$35,013
$
$
$35,013
Borrowings
209,463
940,780
585,330
1,735,573
Leases
13,776
30,733
91
44,600
Asset retirement obligation(a)
6,436
27,913
2,432,934
2,467,283
Other liabilities(b)
161,467
5,384
166,851
Off-Balance Sheet contractual obligations
Firm Transportation(c)
51,795
106,324
158,119
Total
$477,950
$1,111,134
$3,018,355
$4,607,439
(a)Represents our asset retirement obligation on an undiscounted basis. On a discounted basis the liability is $649 million as of December 31, 2024 as presented in the
Consolidated Statement of Financial Position.
(b)Represents accrued expenses and net revenue clearing. Excludes asset retirement obligations and revenue to be distributed. Refer to Note 23 in the Notes to the Group
Financial Statements for information.
(c)Represents reserved capacity to transport gas from production locations through pipelines to the ultimate sales meters.
We believe that our operational cash flows and existing liquidity will be sufficient to meet our contractual obligations and commitments over the next
twelve months, even in a stressed scenario, as demonstrated by our Viability and Going Concern assessment. Cash flows from operations were $346
million for the year ended December 31, 2024, which includes partial-year contributions from the Oaktree, Crescent Pass and East Texas II acquisitions
in 2024. Cash flows from operations were $410 million for the year ended December 31, 2023, which similarly included partial-year contributions from
the Tanos II acquisition in 2023. As of December 31, 2024 and 2023, we had current assets of $304 million and $305 million, respectively, and available
borrowings on our Credit Facility of $101 million and $146 million, respectively, (excluding $14 million and $11 million in outstanding letters of credit,
respectively), which could also be used to service our contractual obligations and commitments over the next twelve months.
Litigation and Regulatory Proceedings
From time to time, we may be involved in legal proceedings in the ordinary course of business. Currently, we are not a party to any material litigation
proceedings that, if determined adversely, are reasonably expected to have a material and adverse effect on our business, financial position, or results
of operations. Additionally, we are not aware of any material legal or administrative proceedings that are contemplated to be brought against us.
We have no other contingent liabilities that would have a material impact on our financial position, results of operations, or cash flows.
Environmental Matters
Our operations are subject to environmental laws and regulations in all the jurisdictions where we operate. We cannot predict the impact of additional
environmental laws and regulations that may be adopted in the future, including whether they would adversely affect our operations. We can offer no
assurance regarding the significance or cost of compliance with any new environmental legislation or regulation once implemented.
Recently Issued Accounting Pronouncements
Refer to Note 3 in the Notes to the Group Financial Statements for information regarding recent accounting pronouncements applicable to our
Consolidated Financial Statements.
Significant Accounting Policies & Estimates
Refer to Note 3 and 4 in the Notes to the Group Financial Statements for information regarding our significant accounting policies, judgments and
estimates.
Quantitative & Qualitative Disclosure About Market Risk
Refer to Note 25 in the Notes to the Group Financial Statements for information regarding market risk.
Internal Control Over Financial Reporting
We are subject to Section 404 of the Sarbanes-Oxley Act of 2002 which requires that we include a report of management on our internal control over
financial reporting in our Annual Report & Form 20-F. In addition, our independent registered public accounting firm must attest to and report on the
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effectiveness of our internal control over financial reporting in our Annual Report & Form 20-F. No material weakness in financial reporting was identified
for the years ended December 31, 2024, 2023, or 2022.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable
possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis.
Refer to Risk Factors for additional information.
Trend Information
Other than as disclosed elsewhere in this Annual Report & Form 20-F, we are not aware of any trends, uncertainties, demands, commitments or events
since December 31, 2024 that are reasonably likely to have a material adverse effect on our revenues, income, profitability, liquidity or capital resources,
or that would cause the disclosed financial information to be not necessarily indicative of future operating results or financial conditions. For a discussion
of trend information, refer to Financial Review for additional information.
Risk Management Framework
Our Enterprise Risk Management (“ERM”) program underscores the significance of risk awareness and mitigation throughout the organization. We
proactively identify, assess, prioritize, monitor, and mitigate risks, enabling us to achieve the strategic objectives outlined in our business model. The
Board conducts thorough assessments of our principal and emerging risks regularly. Principal risks are actively managed due to their potential to
jeopardize our business model, future performance, or financial stability. Emerging risks are new, uncertain, or evolving threats that require ongoing
monitoring, as they may escalate to principal risks over time.
Our ERM program relies on systematic processes to continuously evaluate and enhance based on experience and industry best practices. As directed by
the Audit & Risk Committee, our Senior Leadership Team regularly engages in risk discussions across all operational areas. This proactive dialogue
fosters a culture that highly values risk mitigation, thereby preserving and creating value for our stakeholders. We consider risk management a collective
responsibility and empower all employees to enhance our processes and procedures to mitigate risks effectively. Our ERM program offers reasonable
assurance, not absolute certainty, that our risks are being effectively managed.
Risk Identification
In the risk identification phase of our ERM program, we capture potential and emerging risks arising from changes in circumstances or new
developments. To strengthen our risk identification, we undertake the following activities:
Continuous monitoring of the risk universe for new or emerging risks;
Re-evaluating the risk universe at least annually;
Enhancing our risk awareness culture and identifying risk ownership;
Interviewing risk owners about current mitigation activities; and
Designing and implementing a risk mitigation control framework.
Risk Assessment
We assess business risks using a scorecard approach that evaluates (i) likelihood, (ii) potential impact, and (iii) speed of impact. Our assessment
includes both financial and non-financial exposures. For each identified principal risk, we develop a list of mitigating activities and potential opportunities
to offset or minimize the risk.
Risk Response
Risk management begins with the Board, responsible for ensuring that risks are addressed and mitigated through our corporate strategy, business
model, and within the Board’s risk appetite. The Board actively monitors company performance on mitigation activities by engaging with executive and
senior management.
Principal Risks and Uncertainties
By leveraging our comprehensive risk management framework, we ensure a proactive approach to mitigating potential threats, which is crucial for
maintaining our stability and achieving our strategic goals. Below, we outline our principal risks and corresponding risk responses.
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Strategic Risks
1   Corporate Strategy & Acquisition Risk
Our future growth depends heavily on successfully completing acquisitions that align with our strategic goals. The process of executing and seamlessly
integrating acquisitions could place significant demands on our managerial, operational, and financial resources. If we fail to properly assess, execute,
and integrate acquisitions, it could negatively affect our business operations, financial performance, and overall prospects.
Link to Strategy:
.1. .2. .3. .4.
Link to KPIs:
.1. .2. .3. .4.
Response/Mitigation
Maintaining a disciplined commitment to our core strategy is essential. By focusing on acquiring low-cost, long-life, and relatively low-decline
producing assets, along with complementary and synergistic midstream assets, we can ensure sustainable growth and stability. This approach
helps us maximize value and efficiency while minimizing risks.
Our Commercial Development, Land, Reserves, Strategic Planning, and Financial Planning & Analysis teams collaborate closely to identify and
evaluate potential acquisition opportunities that align with our strategic objectives. This teamwork ensures that all potential acquisitions are
thoroughly vetted to meet our criteria.
Our organization leverages its extensive experience and knowledge to identify and recognize potential opportunities.
We conduct thorough risk assessments and a comprehensive due diligence process for all potential new acquisitions. This process ensures we
understand the full scope of risks and opportunities associated with each acquisitions, aligning with our commitment to sustainability and strategic
growth.
We incorporate feedback and evaluations from external experts during the due diligence process. This feedback ensures that we benefit from
specialized knowledge and objective insights, enhancing the thoroughness and accuracy of our assessments.
We strive to maintain a strong balance sheet with significant liquidity, enabling us to fund growth through acquisitions effectively. This financial
strength ensures we can seize opportunities as they arise, supporting our strategic objectives and long-term success.
2   Climate Risk
Climate-related matters remain central to numerous global corporate discussions and decisions. While opportunities related to climate continue to arise
in this swiftly changing landscape, we acknowledge that these issues may pose risks for DEC. Environmental regulations, climate change concerns, and
investor-driven changes may lead to (i) increased business costs, (ii) challenges in executing our strategy, and (iii) restricted access to specific markets
or investors.
Link to Strategy:
.1. .2. .3. .4.
Link to KPIs:
.2. .5. .6.
Response/Mitigation
Our Board oversees the development of our climate risk strategy which aims to position us at the heart of the energy transition based on
responsible stewardship of existing natural gas and oil assets. The Board’s decision-making is informed by regular climate subject matter updates
from each of our key Board committees.
Through our annual TCFD reporting process, we identify and assess climate-related risks for consideration of appropriate risk mitigation actions.
Our core business strategy aligns with numerous sustainability initiatives. We acquire reliable, long-life, producing wells that often have not reached
their full potential under their former owners. This stewardship model allows us to avoid the high cost and sometimes sizeable environmental
impact often associated with exploration and drilling, which is the intended target of many sustainability initiatives.
Alongside our zero-tolerance operating principle for fugitive emissions, we invest capital funds towards emission reduction technologies and
projects and regularly deploy SAM optimization techniques that allow us to eliminate or reduce our carbon footprint.
Our core KPI of methane intensity reduction is central to our corporate goals to reduce both methane and GHG emissions.
We again expanded our asset retirement capabilities, managed through our Next LVL subsidiary, that will permit us to exceed our long-term
Appalachian asset retirement agreements, reflective of our core KPI to meet or exceed state asset retirement goals.
Financial Risks
3   Commodity Price Volatility Risk
Changes in commodity prices may affect the value of our natural gas and oil reserves, operating cash flows and adjusted EBITDA, regardless of our
operating performance.
Link to Strategy:
.3.
Link to KPIs:
.1. .2. .4.
Response/Mitigation
Our Senior Leadership Team monitors commodity markets on a daily basis and internal models are routinely updated to evaluate market changes.
This monitoring process includes reviewing realized pricing, forward pricing curves, and basis differentials. This active monitoring is critical to risk
mitigation and the successful execution of our hedge strategy.
Our hedging policy continues to be guided by our goal to generate reliable free cash flow in any commodity pricing environment and secure our
debt and dividend payments. Our hedge strategy of proactively layering on appropriately structured hedge contracts at advantageous prices and
tenors allows us to capitalize on beneficial price movements in a constantly changing, forward natural gas price market.
External specialists are consulted on a regular basis to assist in the execution of our hedging strategy.
4   Financial Strength & Flexibility Risk
Liquidity and access to capital risks arise from our inability to generate cash flows from operations to fund our business requirements or our inability to
access external sources of funding. These risks can result in difficulty in meeting our financial obligations as they become due.
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Link to Strategy:
.1. .2. .3. .4.
Link to KPIs:
.1. .2. .3. .6.
Response/Mitigation
Our Senior Leadership Team actively monitors debt levels and available borrowing capacity on our Credit Facility.
Our Senior Leadership Team updates the Board at least quarterly on our debt and liquidity position.
Our business model of stable production contributes to predictable cash flows, which facilitates an efficient forecasting ability.
Strong access to bank capital as our borrowing base in the Fall 2024 redetermination was reaffirmed unanimously by our 12-bank group syndicate.
Maintain access to multiple avenues of funding beyond our Credit Facility: equity issuance, asset-backed securitizations, and bond issuance.
Proactive hedge program to protect against commodity price volatility and stabilize operating cash flows.
Continuous management review of funding and financing alternatives.
Legal, Regulatory and Reputational Risks
5   Regulatory & Political Risk
Our operations are governed by regulations in every jurisdictions where we operate. We cannot predict the impact of potential future laws or
regulations, including whether they could negatively affect our operations. We cannot guarantee that any new legislation, if enacted, will not require us
to incur substantial costs, make significant investments, or reduce production.
Link to Strategy:
.2. .4.
Link to KPIs:
.1. .2. .3. .4. .5. .6. .7.
Response/Mitigation
Operate to the highest industry standards with regulators and monitor compliance with our contracts, asset retirement program and taxation
requirements.
External specialists utilized on legal, regulatory, and tax issues as required.
Foster strong relationships with local, state, and federal authorities, as well as other government bodies and key stakeholders.
Continuous monitoring of the political and regulatory environments in which we operate.
Working responsibly and community/stakeholder engagement and outreach is an important factor in maintaining positive relationships in the
communities in which we operate.
We encourage our employees to become actively involved in their communities through industry associations in their respective operating areas. By
leading, participating in and championing a variety of these organizations, we believe that our support of the energy industry’s associations adds
value to our business through the sharing of operating best practices, technical knowledge and legislation updates, ultimately to the benefit of all
our stakeholders.
6   Health & Safety Risk
Potential impacts from a lack of adherence to health and safety policies may result in fines and penalties, serious injury or death, environmental
impacts, statutory liability for environmental redemption and other financial and reputational consequences that could be significant.
Link to Strategy:
.2. .4.
Link to KPIs:
.1. .2. .3. .4. .7.
Response/Mitigation
Effectively managing Health and Safety Risk exposure is the first priority for the Board and Senior Leadership Team. The Sustainability & Safety
Committee of the Board regularly reviews health and safety programs and mitigations.
Health and safety training is included as part of all staff and contractor inductions.
Detailed training on our field manual procedures has been provided to key stakeholders to ensure processes and procedures are embedded
throughout the organization and all operations.
Establishing processes for continually assessing our overall operating and EHS capabilities, including evaluations to determine the level of oversight
required.
Effective execution of the field operating manual in operations.
Crisis and emergency response procedures and equipment are maintained and regularly tested to ensure we are able to respond to an emergency
quickly, safely and effectively.
Leading and lagging indicators and targets developed in line with industry guidelines and benchmarks.
Findings from ‘lessons learned’ reviews are implemented on future operations.
All employees maintain work stoppage ability.
Operational Risk
7   Cybersecurity Risk
Cybersecurity risks for companies have increased significantly in recent years due to the mounting threat and sophistication of cybercrime. A
cybersecurity breach, incident, or failure of our IT systems could disrupt our businesses, put employees at risk, result in the disclosure of confidential
information, damage our reputation, and create significant financial and legal exposure for DEC.
Our network is designed using a Zero Trust Approach (“ZTA”) and is segmented to provide additional layers of security. We have established several
layers of security, including least privilege access, conditional access policies, and multi-factor authentication (“MFA”). Our ZTA extends beyond our
network to encompass identity, endpoints, infrastructure, data, and applications. This integrated ecosystem enables enhanced visibility, intelligence, and
automation for our security team. Due to our 100% cloud environment, we focus on continuous testing of our security posture from both trusted and
untrusted sources—both external and internal to our networks—rather than relying on a one-time penetration testing approach. Additionally, we
collaborate with third-party managed security service providers and utilize internal resources for round-the-clock incident monitoring.
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Link to Strategy:
.2. .3.
Link to KPIs:
.1. .2. .4.
Response/Mitigation
Employees are our first line of defense against cyberattacks, and we promote secure behaviors to help mitigate this growing risk. We focus on
practical rules through robust mandatory annual training and e-learning sessions delivered by our digital security team. One of these rules
addresses phishing and reminds staff to ‘think before they click’.
We engage with key technology partners and suppliers to ensure potentially vulnerable systems are identified and secured.
We test our cybersecurity crisis management and business continuity plans, recognizing the evolving nature and pace of the threat landscape.
We continuously implement and monitor our IT Security Policy, which includes measures to protect against cyberattacks.
Advanced network security detection with regular threat testing.
Control and protection of confidential information.
Our Information Security Management Team, which includes certain members of the Senior Leadership Team including the Chief Financial Officer,
Chief Information Officer, Chief Information Security Officer and General Counsel, meets at least once a quarter to discuss cybersecurity issues,
risks and strategies. The Information Security Management Team regularly briefs the Board of Directors 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 governance, risk management, and control of the cybersecurity program utilizing the National
Institute of Standards and Technology framework.
There were no cybersecurity incidents during the year ended December 31, 2024, that resulted in an interruption to our operations, known losses of any
critical data, or otherwise had a material impact on our strategy, financial condition, or results of operations. However, the scope and impact of any
future incident cannot be predicted.
Risk Factors
You should carefully consider the risks described below, together with all of the other information in this Annual Report & Form 20-F. 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 & Form 20-F 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 & Form 20-F.
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 decreases 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, their quality and production volumes may be lower than estimated or expected.
The present value of future net cash flows from our reserves, or 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 climate change.
We rely on third-party infrastructure such as TC Energy (formerly TransCanada), Enbridge, CNX, Dominion Energy Transmission, Enlink, Williams
and MarkWest (defined herein) that we do not control and/or, in each case, are subject to tariff charges that we do not control.
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, 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, including our recent acquisition of Maverick.
We may not have good title to all our assets and licenses.
We may issue additional ordinary shares in connection with acquisitions or other growth opportunities, any share incentive or share option plan or
otherwise that may dilute other shareholdings.
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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.
The dual listing of our ordinary shares may adversely affect the liquidity and value of our ordinary shares.
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 Kingdom and the United States.
Risks Related to Our Business, Operations and Industry
Volatility and future decreases 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 conflict in Ukraine. 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 conditions, natural disasters, climate change 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;
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. According to the U.S. Energy Information Administration, the
historical high and low Henry Hub natural gas spot prices per MMBtu for the following periods were as follows: in 2022, high of $9.85 and low of $3.46;
in 2023, high of $3.78 and low of $1.74, and in 2024, high of $13.20 and low of $1.20 — highlighting the volatile nature of commodity prices.
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 price 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 down 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
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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.
The effects of operating in a competitive industry may include:
Higher than anticipated prices for the acquisition of licenses or assets;
The hiring by competitors of key management or other personnel; and
Restrictions on the availability of equipment or services.
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.
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. In periods where NGL prices are high, we benefit greatly from the ability to process NGLs. 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, 2024, 2023 and 2022 contained in this Annual Report & Form 20-F has been audited by NSAI unless stated
otherwise. The standards utilized to prepare the reserves information that has been extracted in this document may be different from the standards of
reporting adopted in other jurisdictions. Investors, therefore, should not assume that the data found in the reserves information set forth in this Annual
37
Report & Form 20-F is directly comparable to similar information that has been prepared in accordance with the reserve reporting standards of other
jurisdictions, such as the United Kingdom.
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, including the following:
Production history compared with production from other comparable producing areas;
Quality and quantity of available data;
Interpretation of the available geological and geophysical data;
Effects of regulations adopted by governmental agencies;
Future percentages of sales;
Future natural gas, NGLs and oil prices;
Capital investments;
Effectiveness of the applied technologies and equipment;
Effectiveness of our field operations employees to extract the reserves;
Natural events or the negative impacts of natural disasters;
Future operating costs, tax on the extraction of commercial minerals, development costs and workover and remedial costs; and
The judgment of the persons preparing the estimate.
As all reserve estimates are subjective, each of the following items may differ materially from those assumed in estimating reserves:
The quantities and qualities that are ultimately recovered;
The timing of the recovery of natural gas and oil reserves;
The production and operating costs incurred;
The amount and timing of development expenditures, to the extent applicable;
Future hydrocarbon sales prices; and
Decommissioning costs and changes to regulatory requirements for decommissioning.
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. Furthermore, less historical well production
data is available for unconventional wells because they have only become technologically viable in the past twenty years and the long-term production
data is not always sufficient to determine terminal decline rates. In comparison, some conventional wells in our portfolio have been productive for a
much longer time. As a result, there is a risk that estimates of our shale reserves are not as reliable as estimates of the conventional well reserves that
have a longer historical profile to draw on. Interpretation, testing and production after the date of the estimates may require substantial upward or
downward 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, 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. Refer to APMs within this Annual Report & Form 20-F for additional information regarding our use of
PV-10.
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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 15
years. We will incur such decommissioning costs at the end of the operating life of some of our properties. 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 production sites. 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, data breaches, 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.
If we do not have access to capital on favorable terms, on the timeline we require, or at all, our financial condition and results of
operations could be materially adversely affected.
We require capital to complete acquisitions that we believe will enhance shareholder return. Significant volatility or disruption in the global financial
markets may result in us not being able to obtain additional financing on favorable terms, on the timeline we anticipate, or at all, and we may not be able
to refinance, if necessary, any outstanding debt when due, all of which could have a material adverse effect on our financial condition. Any inability to
obtain additional funding on favorable terms, on the timeline we anticipate, or at all, may prevent us from acquiring new assets, cause us to curtail our
operations significantly, reduce planned capital expenditures or obtain funds through arrangements that management does not currently anticipate,
including disposing of our assets, the occurrence of any of which may significantly impair our ability to deliver shareholder returns. If our operating results
falter, our cash flow or capital resources prove inadequate, or if interest rates increase significantly, we could face liquidity problems that could materially
and adversely affect our results of operations and financial condition.
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.
Economic conditions in a number of industries in which our customers operate have experienced substantial deterioration in the past, resulting in
reduced demand for natural gas and oil. Renewed or continued weakness in the economic conditions of any of the industries we serve or that are
served by our customers, or the increased focus by markets on carbon-neutrality, could adversely affect our business, financial condition, results of
operation and liquidity in a number of ways. For example:
Demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the
revenues, margins and profitability of our natural gas business;
A decrease in international demand for natural gas or NGLs produced in the United States could adversely affect the pricing for such products,
which could adversely affect our results of operations and liquidity;
The tightening of credit or lack of credit availability to our customers could adversely affect our liquidity, as our ability to receive payment for our
products sold and delivered depends on the continued creditworthiness of our customers;
Our ability to refinance our Credit Facility may be limited and the terms on which we are able to do so may be less favorable to us depending on
the strength of the capital markets or our credit ratings;
Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for
exploration and/or development of our natural gas reserves;
Increased capital markets scrutiny of oil and gas companies may lead to increased costs of capital or lack of credit availability; and
A decline in our creditworthiness may require us to post letters of credit, cash collateral, or surety bonds to secure certain obligations, all of which
would have an adverse effect on our liquidity.
Our operations are subject to a series of risks relating to climate change.
Continued public concern regarding climate change 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 climate change 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
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climate-related risks. For example, U.S. states have adopted or proposed climate-related disclosures rules that may require us to incur significant costs
to assess and disclose on a range of climate-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 fossil fuel 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, the
United States indicated in January 2025 its intent to withdraw from the Paris Agreement, and changes undertaken by the new U.S. Presidential
Administration have or may in the future reverse or rescind climate-related initiatives and regulations adopted by prior administrations and to 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 fossil fuel 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
climate change, and the continued political and societal attention afforded to mitigating the effects of climate change, 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 climate change, companies in the fossil fuel 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-fossil fuel 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 fossil fuel energy companies. A material reduction in
the capital available to the fossil fuel 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 Group may also be subject to activism from environmental non-governmental organizations (“NGOs”) campaigning against fossil fuel 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 climate change or alleging that the companies have been
aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
Finally, our operations are subject to disruption from the physical effects that may be caused or aggravated by climate change. These include risks from
extreme weather events, such as hurricanes, severe storms, floods, heat waves, and ambient temperature increases, as well as wildfires, each of which
may become more frequent or more severe as a result of climate change.
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 39% of the NGLs we sold during the year ending December 31, 2024 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.
40
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 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, 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 highly 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.
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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 Pipeline and Hazardous Materials Safety
Administration (“PHMSA”) has promulgated regulations requiring pipeline operators to develop and implement integrity 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.
The 2011 Pipeline Safety Act amends the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids
pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate regulations relating to expanded
integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to
confirm the material strength of certain pipelines, and operator verification of records confirming the maximum allowable pressure of certain intrastate
gas transmission pipelines. Additionally, pursuant to one of the requirements of the 2011 Pipeline Safety Act, in May 2016, PHMSA proposed rules that
would, if adopted, impose more stringent requirements for certain gas lines, extend certain of PHMSA’s current regulatory safety programs for gas
pipelines beyond HCAs to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as five dwellings within the
potential impact area and require gas pipelines installed before 1970 that were exempted from certain pressure testing obligations to be tested to
determine their maximum allowable operating pressures (“MAOP”). Other requirements proposed by PHMSA under the rulemaking include: reporting to
PHMSA in the event of certain MAOP exceedances; strengthening PHMSA integrity management requirements; considering seismicity in evaluating
threats to a pipeline; conducting hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and using more detailed
guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of
requirements on gathering lines. In January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand
the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s
proximity to an HCA. The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the
next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes
inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods,
earthquakes, or other similar events that are likely to damage infrastructure PHMSA regularly revises its pipeline safety regulations. For example, in June
2016, the President signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “2016 PIPES Act”) into law. The 2016
PIPES Act reauthorizes PHMSA through 2019, and facilitates greater pipeline safety by providing PHMSA with emergency order authority, including
authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazards,
without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and
hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-
sharing system related to integrity risk analyses. The 2016 PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates
outstanding from the 2011 Pipeline Safety Act PHMSA has recently published three parts of its so-called “Mega Rule,” including rules focused on: the
safety of gas transmission pipelines, the safety of hazardous liquid pipelines and enhanced emergency order procedures. PHMSA finalized the first part
of the rule, which primarily addressed maximum operating pressure and integrity management near HCAs for onshore gas transmission pipelines, in
October 2019. PHMSA finalized the second part of the rule, which extended 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, and 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.
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 2023, the maximum civil penalties PHMSA can impose are $257,664 per pipeline safety violation per day, with a maximum of
$2,576,627 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.
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We are currently operating in a period of economic uncertainty and capital markets disruption, which has been significantly impacted
by geopolitical instability due to the ongoing military conflict between Russia and Ukraine, and more recently, the Israel-Hamas war.
Our business may be adversely affected by any negative impact on the global economy and capital markets resulting from the conflict
in Ukraine or any other geopolitical tensions.
U.S. and global markets are experiencing volatility and disruption following the escalation of geopolitical tensions and the start of the military conflict
between Russia and Ukraine. In February 2022, a full-scale military invasion of Ukraine by Russian troops transpired. Although the length and impact of
the ongoing military conflict is highly unpredictable, the conflict in Ukraine has led, and could continue to lead, to market disruptions, including
significant volatility in commodity prices, credit and capital markets, as well as supply chain interruptions.
Additionally, on October 7, 2023, Hamas, a U.S. designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto
Israel. On October 8, 2023, Israel formally declared war on Hamas, and the armed conflict is ongoing as of the date of this filing. Hostilities between
Israel and Hamas could escalate and involve surrounding countries in the Middle East. We are actively monitoring the situation in Ukraine and Israel and
assessing their impact on our business. To date we have not experienced any material interruptions in our infrastructure, supplies, technology systems
or networks needed to support our operations given our operating areas are exclusively located within the Appalachian Region and Central Region of the
U.S. We have no way to predict the progress or outcome of the conflicts in Ukraine or Israel or their impacts in Ukraine, Russia, Belarus, Israel or the
Gaza Strip as the conflicts, and any resulting government reactions, are rapidly developing and beyond our control. The extent and duration of the
military actions, sanctions and resulting market disruptions could be significant and could potentially have substantial impact on the global economy and
our business for an unknown period of time. Any of the aforementioned factors could affect our business, financial condition and results of operations.
Any such disruptions may also magnify the impact of other risks described in this Annual Report & Form 20-F.
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, 2024, 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 Group Financial Statements) are fixed-rate
instruments (subject to adjustment pursuant to the sustainability-linked features described in Note 21 in the Notes to the Group Financial Statements)
and as of December 31, 2024 we had $284 million outstanding on our Credit Facility. 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 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, to further our growth, we have made acquisitions outside the Appalachian Region, a region in which we have developed our operational
experience into the Bossier and Haynesville shales, the Barnett Shale Play, and the Cotton Valley and Mid-Continent producing areas. Accordingly, 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.
Integrating operations, technology, systems, management, back office personnel and pre- or post-completion costs for future acquisitions may prove
more difficult or expensive than anticipated, thereby rendering the value of any company or assets acquired less than the amount paid. We may also
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take on unexpected liabilities which are uncapped, have to undertake unanticipated capital expenditures in connection with a new acquisition or provide
uncapped liabilities in connection with the purchase and sale of assets, which are customary in such agreements. The integration of acquired businesses
or assets requires significant time and effort on the part of our management. Following such integration efforts, prior acquisitions may still not achieve
the level of financial or operational performance that was anticipated when they were acquired. In addition, the integration of new acquisitions can be
difficult and disrupt our own business because our operational and business culture may differ from the cultures of the acquired businesses, unpopular
cost-cutting measures may be required, internal controls may be more difficult to maintain and control over cash flows and expenditures may be difficult
to establish. If we encounter any of the foregoing issues in relation to one of our acquisitions this could have a material adverse effect on our business,
results of operations, financial condition, cash flows or prospects.
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 also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
The Group’s success will be dependent upon its ability to fully integrate Maverick and deliver the value of the combined underlying
businesses; the full financial benefits expected from the Group may not be fully achieved.
The Group and Maverick have previously operated independently and there can be no assurance that their businesses can be fully integrated effectively.
The success of the combined business will depend, in part, on the effectiveness of the integration process and the ability to realize the anticipated
financial benefits from combining the respective businesses.
While the Group believes that the financial benefits of the Maverick acquisition and the costs associated with the Maverick 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 Maverick 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 Group's management
and employees from ongoing operations, pursuing other potential business opportunities and may cause a delay in other projects currently
contemplated by the Group. To the extent that the combined company is unable to efficiently integrate the operations of the Group and Maverick,
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 Group.
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.
The issuance of additional ordinary shares in the Group in connection with acquisitions or other growth opportunities, any share
incentive or share option plan or otherwise may dilute all other shareholdings.
We may seek to raise financing to fund future acquisitions and other growth opportunities. We may, for these and other purposes, issue additional
equity or convertible equity securities. As a result, existing holders of ordinary shares may suffer dilution in their percentage ownership or the market
price of the ordinary shares may be adversely affected. For example, consideration for the Maverick acquisition included the issuance of 21,194,213 new
ordinary shares directly to the unitholders of Maverick.
As of December 31, 2024, we have issued options under our equity incentive plans to employees and executive directors for a total of 153,631 new
ordinary shares of the Group, all of which are currently outstanding, and have also entered into restricted stock unit agreements and performance stock
unit agreements with certain employees, of which 976,222 restricted stock units and 965,303 performance stock units are outstanding, as of said date.
We may, in the future, issue further options and/or warrants to subscribe for new ordinary shares to certain advisers, employees, directors, senior
management and/or consultants of the Group. The exercise of any such options would result in a dilution of the shareholdings of other investors.
Subject to any applicable pre-emption rights, any future issues of ordinary shares by the Group may have a dilutive effect on the holdings of
shareholders and could have a material adverse effect on the market price of ordinary shares as a whole.
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;
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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 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. 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 the date of this report, our borrowing base is $900 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.
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 successfully 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, and ABS X Notes (which now covers Term Loan I, ABS I Notes, and ABS II Notes) (each as
defined herein), 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, and ABS X Notes (which now covers Term Loan I, ABS I Notes, and ABS II 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
December 31, 2024, we had $284 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 an operating loss of $43 million for the year ended
December 31, 2024, compared with an operating profit of $1,161 million for the year ended December 31, 2023 and an operating loss of $671 million
for the year ended December 31, 2022. 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 an operating profit to loss was attributable to a change of $1,095 million in the mark-to-market valuation adjustment on our
45
derivative financial instrument valuations to $189 million loss in 2024 from $906 million gain in 2023. 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 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;
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
46
environmental risks associated with the Group 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.
Increasing attention to sustainability matters may impact our business and financial results.
Increasing 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 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 increasing attention and demands for action related to
climate change 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 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, 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 climate change 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 climate change arising from GHG emissions has resulted in increasing political risks in the
United States, including climate change-related commitments and skepticism expressed by some 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 climate change-
related initiatives and requirements by the prior Administration. 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.
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. 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.
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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.
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 are designed to
penetrate our network security or the security of our internal systems, misappropriate proprietary information and/or cause interruptions to our services,
and we expect to continue to face similar threats in the future. We cannot guarantee that we will be able to successfully prevent all attacks in the future.
Such future attacks could include hackers obtaining access to our systems, the introduction of malicious computer code or denial of service attacks. If an
actual or perceived breach of our network security occurs, it could adversely affect our business or reputation, and may expose us to the loss of
information, 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
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 end up in 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. 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 Group, 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.
Any change in our tax status or in taxation legislation in the United Kingdom or the United States could affect our ability to provide returns to
shareholders. Statements in this document concerning the taxation of holders of our ordinary shares are based on current law and practice, which is
subject to change.
We are subject to income taxes in the United Kingdom and the United States, and there can be no certainty that the current taxation regime in the
United Kingdom, 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. 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. The
United Kingdom announced on May 26, 2022 a new “Energy Profits Levy” on oil and gas exploration and production companies operating in the United
48
Kingdom and the UK Continental Shelf at a rate of 25% (subsequently increased to 35% and then to 38% from November 1, 2024). As we do not
operate our exploration, production or extraction activities in the United Kingdom or in the UK Continental Shelf, we do not expect the Energy Profits
Levy to impact our headline corporation tax rate in the United Kingdom, however, the taxation of energy companies remains uncertain, particularly in
the context of current global events, and the future stability of such tax regimes cannot be guaranteed.
Our domestic and international 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, state or international 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 reliefs 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 reliefs available. In particular, the nature
and amount of tax payable may be dependent on the availability of relief under tax treaties and is subject to changes to the tax laws or practice in any
of the jurisdictions we currently are subject to or may be subject to in the future. Any limitation in the availability of relief under these treaties, any
change in the terms of any such treaty or any changes in tax law, interpretation or practice could increase the amount of tax payable by us.
Finally, because we are an entity incorporated in the United Kingdom that is treated as a U.S. corporation for all purposes of U.S. federal income tax
law, 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.
The taxation of an investment in our ordinary shares depends on the individual circumstances of the holders of our ordinary shares. Holders of our
ordinary shares are strongly advised to consult their professional tax advisers.
Tax legislation may be enacted in the future that could negatively impact our current or future tax structure and effective tax rates.
Long-standing international tax initiatives that determine each country’s jurisdiction to tax cross-border international trade and profits are evolving as a
result of, among other things, initiatives such as the Anti-Tax Avoidance Directives, as well as the Base Erosion and Profit Shifting (“BEPS”) reporting
requirements, mandated and/or recommended by the EU, G8, G20 and Organization for Economic Cooperation and Development (“OECD”), including
the imposition of a minimum global effective tax rate for multinational businesses regardless of the jurisdiction of operation and where profits are
generated (Pillar Two). Many countries around the world, including the United Kingdom, have introduced new, or amended existing, tax laws applicable
to multinational businesses to implement Pillar Two. As these and other tax laws and related regulations change (including changes in the interpretation,
approach and guidance of tax authorities), our financial results could be materially impacted. Given the unpredictability of these possible changes and
their potential interdependency, it is difficult to assess whether the overall effect of such potential tax changes would be cumulatively positive or
negative for our earnings and cash flow, but such changes could adversely affect our financial results.
Risks Relating to Our Ordinary Shares
The requirements of being a U.S. listed company, including compliance with the reporting requirements of the Securities Exchange
Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase
our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As we became a U.S. listed company in December 2023, we are required to comply with new laws, regulations and requirements, certain corporate
governance provisions of Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, with which we were not required to
comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and will
significantly increase our costs and expenses. We will need to: institute a more comprehensive compliance function to test and conclude on the
sufficiency of our internal control over financial reporting; comply with rules promulgated by the NYSE; prepare and distribute periodic public reports;
establish new internal policies, such as those relating to insider trading; and involve and retain to a greater degree outside professionals in the above
activities. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls
does not address all relevant financial statement risks. Compliance with Sarbanes-Oxley Act requirements may strain our resources, increase our costs
and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a new U.S. listed company, we are subject to significant regulatory oversight and reporting obligations under U.S. federal securities laws and the
continuous scrutiny of securities analysts and investors. In addition, most members of our management team have limited experience managing a U.S.
listed company, interacting with U.S. public company investors, and complying with the increasingly complex laws pertaining to U.S. listed companies.
Our management team may not successfully or efficiently manage us as a U.S. listed company. These new obligations and constituents require
significant attention from our management team and could divert our management team’s attention away from the day-to-day management of our
business, which could adversely affect our business, results of operations and financial condition.
Further, we expect that, as a new U.S. listed company, being subject to these rules and regulations may make it more difficult and more expensive for
us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher
costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board
of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may
incur or the timing of such costs.
We qualify as a foreign private issuer and, as a result, we will not be subject to U.S. proxy rules and will be subject to Exchange Act
reporting obligations that, to some extent, are more lenient and less frequent than those of a U.S. domestic public company.
We report under the Exchange Act as a non-U.S. company with foreign private issuer status. Because we qualify as a foreign private issuer under the
Exchange Act, we are exempt from certain provisions of the Exchange Act that are applicable to U.S. domestic public companies, including (i) the
sections of the Exchange Act regulating the solicitation of proxies, consents or authorizations in respect of a security registered under the Exchange Act;
(ii) the sections of the Exchange Act requiring insiders to file public reports of their stock ownership and trading activities and liability for insiders who
49
profit from trades made in a short period of time; and (iii) the rules under the Exchange Act requiring the filing with the SEC of quarterly reports on
Form 10-Q containing unaudited financial and other specified information, or current reports on Form 8-K, upon the occurrence of specified significant
events. In addition, foreign private issuers are not required to file their annual report on Form 20-F until 120 days after the end of each fiscal year, while
U.S. domestic issuers that are accelerated filers are required to file their annual report on Form 10-K within 75 days after the end of each fiscal year.
Foreign private issuers also are exempt from Regulation Fair Disclosure, aimed at preventing issuers from making selective disclosures of material
information. As a result of the above, you may not have the same protections afforded to shareholders of companies that are not foreign private issuers,
some investors may find the ordinary shares less attractive, and there may be a less active trading market for the ordinary shares.
To the extent we no longer qualify as a foreign private issuer as of June 30, 2025 (the end of our second fiscal quarter), we would be required to
comply with all of the periodic disclosure and current reporting requirements of the Exchange Act applicable to U.S. domestic issuers, which are more
detailed and extensive than the requirements for foreign private issuers, as of January 1, 2026, including the requirement to prepare our financial
statements in accordance with U.S. generally accepted accounting principles. We may also be required to make changes in our corporate governance
practices in accordance with various SEC and NYSE rules. The regulatory and compliance costs to us under U.S. securities laws if we are required to
comply with the reporting requirements applicable to a U.S. domestic issuer may be significantly higher than the cost we would incur as a foreign
private issuer. As a result, we expect that a loss of foreign private issuer status would increase our legal and financial compliance costs and would make
some activities highly time consuming and costly. If we lose foreign private issuer status and are unable to comply with the reporting requirements
applicable to a U.S. domestic issuer by the applicable deadlines, we would not be in compliance with applicable SEC rules or the rules of NYSE, which
could cause investors could lose confidence in our public reports and could have a material adverse effect on the trading price of our ordinary shares.
We also expect that if we were required to comply with the rules and regulations applicable to U.S. domestic issuers, it would make it more difficult and
expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs
to obtain coverage. These rules and regulations could also make it more difficult for us to attract and retain qualified members of our board of directors.
As a foreign private issuer, we are permitted to adopt certain home country practices in relation to corporate governance matters that
differ significantly from the corporate governance listing standards of the NYSE. These practices may afford less protection to
shareholders than they would enjoy if we complied fully with the corporate governance listing standards of the NYSE.
As a foreign private issuer listed on the NYSE, we are subject to corporate governance listing standards. However, NYSE rules permit a foreign private
issuer like us to follow the corporate governance practices of its home country in lieu of certain NYSE corporate governance listing standards, provided
that we disclose which requirements that we have not complied with in any year and confirm the UK corporate governance practices we have complied
with. Certain corporate governance practices in the United Kingdom, which is our home country, may differ significantly from the NYSE corporate
governance listing standards. Although we adhere to the higher corporate governance standards of the UK Corporate Governance Code, we could
include non-independent directors as members of our nomination and remuneration committee, and our independent directors would not necessarily
hold regularly scheduled meetings at which only independent directors are present. We may in the future elect to follow home country practices in the
United Kingdom with regard to other matters. Therefore, our shareholders may be afforded less protection than they otherwise would have under the
NYSE corporate governance listing standards applicable to U.S. domestic issuers.
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.
The process of designing and implementing effective internal control over financial reporting is a continuous effort that requires us to anticipate and
react to changes in our business and the economic and regulatory environments and to expend significant resources to maintain internal control over
financial reporting that is adequate to satisfy our reporting obligations as a U.S. listed company. If we are unable to maintain adequate internal control
over financial reporting, it could cause us to fail to meet our reporting obligations on a timely basis, result in material misstatements in our consolidated
financial statements and harm our results of operations. In addition, we are required, pursuant to the rules and regulations of the SEC, to furnish a
report by management on the effectiveness of our internal control over financial reporting. This assessment needs to include disclosure of any material
weaknesses identified by our management in our internal control over financial reporting. Assessing the effectiveness of our internal control over
financial reporting requires significant documentation, testing and possible remediation.
We may not be able to conclude on an annual basis that we have effective internal control over financial reporting or our independent registered public
accounting firm may not issue an unqualified opinion on the effectiveness of our internal control over financial reporting. If either we are unable to
conclude that we have effective internal control over financial reporting or our independent registered public accounting firm is unable to issue an
unqualified opinion on the effectiveness of internal control over financial reporting, investors could lose confidence in our reported financial information,
which could have a material adverse effect on the trading price of our ordinary shares.
We have incurred and will continue to incur increased costs as a result of operating as a public company in the United States, and our
management will be required to devote substantial time to new compliance initiatives and corporate governance practices.
As a U.S. listed company, we have incurred and will continue to incur significant legal, accounting and other expenses that we did not incur previously.
The Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the listing requirements of NYSE and other applicable
securities rules and regulations impose various requirements on non-U.S. reporting public companies, including the establishment and maintenance of
disclosure controls and procedures, internal control over financial reporting and corporate governance practices. Our management and other personnel
will need to devote a substantial amount of time to these compliance initiatives. Moreover, these rules and regulations will increase our legal and
financial compliance costs and will make some activities more time consuming and costly. For example, we expect that these rules and regulations may
increase the cost of our director and officer liability insurance.
However, these rules and regulations are often subject to varying interpretations, in many cases due to their lack of specificity, and, as a result, their
application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in continuing uncertainty
regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices.
There is no guarantee that we will continue to pay dividends on our ordinary shares in the future.
Our ability and the Board’s decision to pay dividends is dependent upon our performance and financial condition, cash requirements, future prospects,
commodity prices, the performance and dividend yield of our peers, compliance with the financial covenants and restricted payments covenant in our
Credit Facility, profits available for distribution and other factors deemed to be relevant at the time and on the continued health of the markets in which
we operate. Further, subsequent to our listing on the NYSE, while our Board’s evaluation of our ability or need to pay dividends will primarily remain a
question of the foregoing factors, it will also take into account the performance of our ordinary shares, including relative to our peer group. There can
be no guarantee that we will continue to pay dividends in the future on our ordinary shares.
50
The rights of our shareholders may differ from the rights typically offered to shareholders of a U.S. corporation.
We are incorporated under English law. The rights of holders of ordinary shares are governed by English law, including the provisions of the UK
Companies Act 2006 (the “Companies Act 2006”), and by our Articles of Association. These rights differ in certain respects from the rights of
shareholders in typical U.S. corporations. Refer to Memorandum and Articles of Association in this Annual Report & Form 20-F for a description of the
principal differences between the provisions of the Companies Act 2006 applicable to us and, for example, the Delaware General Corporation Law
relating to shareholders’ rights and protections.
Claims of U.S. civil liabilities may not be enforceable against us.
We are incorporated under the laws of the United Kingdom. In addition, certain of our directors and officers reside outside the United States. As a
result, it may not be possible for investors to effect service of process within the United States upon such persons or to enforce judgments obtained in
U.S. courts against them or us, including judgments predicated upon the civil liability provisions of the U.S. federal securities laws.
The United States and the United Kingdom do not currently have a treaty providing for recognition and enforcement of judgments (other than
arbitration awards) in civil and commercial matters. Consequently, a final judgment for payment given by a court in the United States, whether or not
predicated solely upon U.S. securities laws, would not automatically be recognized or enforceable in the United Kingdom. In addition, uncertainty exists
as to whether UK courts would entertain original actions brought in the UK against us or our directors or senior management predicated upon the
securities laws of the United States or any state in the United States. Provided that certain requirements are met, a final and conclusive monetary
judgment for a definite sum obtained against us in U.S. courts (that is not a sum payable in respect of taxes or similar charges or in respect of a fine or
a penalty), would be treated by the courts of the UK as a cause of action in itself and sued upon as a debt at common law without any retrial of the
issue. Whether the relevant requirements are met in respect of a judgment based upon the civil liability provisions of the U.S. securities laws, including
whether the award of monetary damages under such laws would constitute a penalty, is an issue for the court making such decision. If a UK court gives
judgment for the sum payable under a U.S. judgment, the UK judgment will be enforceable by methods generally available for this purpose. These
methods generally permit the UK court discretion to prescribe the manner of enforcement.
As a result, U.S. investors may not be able to enforce against us or our executive officers, board of directors or certain experts named herein who are
residents of the United Kingdom or countries other than the United States any judgments obtained in U.S. courts in civil and commercial matters,
including judgments under the U.S. federal securities laws.
Viability and Going Concern
In accordance with Provision 31 section 4 of the UK Corporate Governance Code, and taking into account our current financial position and principal
risks for a period longer than the 12 months required by the going concern statement, the Senior Leadership Team prepared a viability analysis which
was assessed by the Board for approval.
Assessment Process and Key Assumptions
Our financial outlook is assessed primarily through a detailed annual business planning process and a more general multi-year forecast. The Senior
Leadership Team provides the Board with a detailed overview as part of its annual budget approval while providing regular updates at each Board
meeting throughout the year. The Board uses this information, along with any other detail it requests, to assess our current performance and longer-
term outlook.
The outputs from the business planning process include a set of key performance objectives, an assessment of our primary risks, the anticipated
operational outlook and a set of financial forecasts that consider the sources of funding available to DEC (the “Base Plan”).
Key assumptions, which underpin the annual business planning process, include the forward price strip for each commodity (natural gas, NGLs and oil),
forecasted operating cost and capital expenditure levels, production profiles, and the availability of liquidity or additional financing. We regularly produce
cash flow projections, which we sensitize for different scenarios including, but not limited to, changes in commodity prices and production rates from our
wells. The Directors and Senior Leadership Team closely monitor these forecast assumptions and projections and seek to mitigate our operating and
liquidity risks.
Based on our financial scenario planning process, the Directors and Senior Leadership Team believe that stress testing forecast results over the Base
Plan for a two-year period through March 2027 forms a reasonable expectation of our viability. At least annually, we perform our two-year Base Plan
forecast for our medium-term strategic planning period. The Directors and Senior Leadership Team are confident that they appropriately monitor and
manage operational risks effectively within the two-year Base Plan, and our scenario planning is focused primarily on plausible changes in external
factors, providing a reasonable degree of confidence.
Viability
The principal risks and uncertainties that affect the Directors’ assessment of our viability in this period are:
The effect of volatile natural gas prices on the business;
Operational production performance of the producing assets; and
Operating cost levels and our ability to control costs.
The Base Plan incorporates key assumptions that reflect these principal risks as follows:
Projected operating cash flows are calculated using a production profile which is consistent with current operating results and decline rates;
Assumes commodity prices are in line with the current forward curve which considers basis differentials;
Operating cost levels stay consistent with historical trends which have been recently elevated due to the inflationary environment;
The financial impact of our current hedging contracts in place, being approximately 86% and 82%, of total production volumes hedged for the
years ending December 31, 2025 and 2026, respectively; and
The scenario also includes the scheduled principal and interest payments on our current debt arrangements.
To assess our viability, the Directors and Senior Leadership Team considered various scenarios around the Base Plan that primarily reflect a more
severe, but plausible, downside impact of the principal risks, both individually and in the aggregate, as well as the additional capital requirements that
downside scenarios could place on us. Conservatively, our viability statement considered the combined impact of all three listed scenarios in:
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Scenario 1: Cyclically low gas prices for a year (Henry Hub prices of $2.00 per MMbtu before returning to strip pricing), which have been historically
observed in the market.
Scenario 2: Considered the impact of climate change by assuming a two-week period of lost production in our East Texas/Louisiana region, which is
susceptible to hurricanes, due to a natural disaster (assumed to occur once in each year of the assessment period).
Scenario 3: Considered the impact of climate change by assuming a two-week period of lost production in our Appalachia region (assumption of lost
production in 25% of the total region), which is susceptible to flooding, due to a natural disaster (assumed to occur once in each year of the assessment
period).
The Directors and Senior Leadership Team considered the impact that these principal risks could, in certain circumstances, have on our prospects within
the assessment period, and accordingly appraised the opportunities to actively mitigate the risk of these severe, but plausible, downside scenarios.
Based on their evaluation, the Directors and Senior Leadership Team have a reasonable expectation that we will be able to continue in operation and
meet our liabilities as they fall due during the assessment period.
Going Concern
In assessing our going concern status, we have taken account of our financial position, anticipated future trading performance, borrowings and other
available credit facilities, forecasted compliance with covenants on those borrowings, and capital expenditure commitments and plans. Our cash
generation and liquidity remain adequate and we believe we will be able to operate within existing facilities.
The Directors are satisfied that our forecasts and projections, that take into account reasonably possible changes in trading performance, show that we
have adequate resources to continue in operational existence for at least 12 months from the date of this Annual Report & Form 20-F and that it is
appropriate to adopt the going concern basis in preparing our consolidated financial statements for the year ended December 31, 2024.
The Strategic Report was approved by the Board of Directors and signed on its behalf by:
/s/ David E. Johnson
David E. Johnson
Chairman of the Board
March 17, 2025
52
Corporate Governance
The Chairman’s Governance Statement
Dear Shareholder,
As a Board, we have been driving our governance standards towards meeting best practice, and it has been my privilege to work with this Board which
is committed to maintaining high standards of corporate governance. As Chairman of the Group, my role is to provide leadership, ensuring that the
Board performs its role effectively and has the capacity, ability, structure, corporate governance systems and support to enable it to continue to do so.
This Governance section of this Annual Report & Form 20-F provides an update on our Board and Corporate Governance Policy. It includes our UK
Corporate Governance Code compliance statements and the reports of the Board committees, namely the Audit & Risk, Nomination & Governance,
Remuneration, and Sustainability & Safety Committees.
In these reports, we set out our governance structures and explain how we have applied the UK Corporate Governance Code and applicable NYSE and
SEC rules.
/s/ David E. Johnson
David E. Johnson
Chairman of the Board
March 17, 2025
Governance Framework
The Group’s success is directly linked to sound and effective governance and we remain committed to achieving high standards in all we do. The
Directors recognize the importance of strong corporate governance and have developed a corporate governance framework and policies appropriate to
the size of the Group.
As the Group grows, the Directors and Senior Leadership Team continue to review and adjust our approach, make ongoing improvements to the Group’s
corporate governance framework and policies and procedures as part of building a successful and sustainable company.
Good governance creates the opportunity for appropriate decisions to be made by the right people at the right time to support the delivery of our
strategy and manage any risks associated with delivery of that strategy.
Board Agenda and Activities During the Year
The Board is responsible for the direction and overall performance of the Group with an emphasis on policy and strategy, financial results and major
operational issues.
During the year, the matters reserved for the Board’s decision have been reviewed and re-affirmed. Specific matters for the Board’s consideration
include:
Approval of the Group’s strategic plan;
Review of the performance of the Group’s strategy, objectives, business plans and budgets;
Review and assess the Group’s sustainability goals, including the Group’s GHG emission intensity reduction targets;
Review and assess the Group’s health and safety metrics and goals;
Approval of the Group’s operating and capital expenditure budgets and any material changes to them;
Review of material changes to the Group’s corporate structure and management and control structure;
Review of changes to governance and business policies;
Monitoring efforts related to community and stakeholder engagement;
Ensuring an effective system of internal control and risk management;
Ensure that appropriate succession planning procedures are in-place;
Approval of annual and interim reports and accounts, and preliminary announcements of year-end results; and
Review of the effectiveness of the Board and its committees.
The Board delegates matters not reserved for the Board to the Senior Leadership Team.
53
Board of Directors
Defines business strategy, assesses risks and monitors performance
Remuneration Committee
Sustainability & Safety
Committee
Nomination & Governance
Committee
Audit & Risk Committee
Responsible for the Group’s
remuneration policy, and for setting
pay levels and bonuses for senior
management in line with individual
performance. Ensures safety and
sustainability KPIs are included in
remuneration packages.
Monitors the Group’s social, ethical,
environmental and safety
performance, and oversees all
sustainable development issues on
behalf of the Board.
Ensures a balance of skills,
knowledge, independence and
experience on the Board and its
committees. Monitors the Group’s
governance structure.
Supports the Board in monitoring
the integrity of the Group’s financial
statements and reviews the
effectiveness of the Group’s system
of internal controls and risk
management systems.
CEO
Takes ultimate responsibility for delivering on strategy, financial and operating performance.
President & Chief
Financial Officer
Executive Vice
President of
Operations
Chief Legal &
Risk Officer
Executive Vice
President &
Investment
Officer
Executive Vice
President of
Energy Marketing
Chief Human
Resources Officer
Description of
Role
Manages the
finance and
accounting activities
of the Group and
ensures that its
financial reports are
accurate and
completed in a
timely manner.
Oversees the
Group’s information
technology function
to ensure safety
and soundness of
internal controls
and systems.
Coordinates
operating activities
and sustainability
initiatives to ensure
transparency and
long-term value for
DEC’s stakeholders.
Responsible for
legal and
compliance,
government, policy
engagement,
community
engagement and
land and mineral
owner engagement.
Responsible for
identifying and
valuing acquisition
targets.
Responsible for
developing and
implementing a
commodity
marketing strategy
to maximize
commodity
revenues.
Responsible for HR
function and
employee relations,
policies, practices
and operations.
Responsibility
Treasury,
Accounting &
Financial Reporting,
Investor Relations,
Information
Technology &
Sustainability
Reporting
Operations, EHS &
Regulatory
Legal &
Compliance, Land,
Policy Engagement
& Community
Relations
Acquisitions
Marketing
Human Resource
Risk
Management
Guidelines
Employee
Handbook, Code of
Business Conduct &
Ethics, Tax Policy &
Anti-Bribery &
Corruption Policy
Employee
Handbook, Code of
Business Conduct &
Ethics, EHS Policy,
Climate Policy,
Socio-Economic
Policy & Field
Operating
Guidelines
Employee
Handbook, Code of
Business Conduct &
Ethics, Anti-Bribery
& Corruption Policy,
Whistleblowing
Policy & Securities
Dealing Policy
Employee
Handbook, Code of
Business Conduct &
Ethics & Anti-
Bribery &
Corruption Policies
Employee
Handbook, Code of
Business Conduct &
Ethics & Anti-
Bribery &
Corruption Policies
Employee
Handbook and
Code of Business
Conduct & Ethics,
Employee Relations,
Human Rights, Anti-
Bribery &
Corruption Policies
& Whistleblowing
Policy
Stakeholder
Engagement
Responsibility
Employees, Rating
Agencies, Financial
Institutions & Debt
& Equity Investors
Communities,
Employees &
Business Partners
Employees,
Industry
Associations,
Communities, Land
& Mineral Owners &
Government &
Regulators
Customers
Customers
Employees &
Communities
Board Effectiveness, Composition and Independence
As of December 31, 2024, the Board was comprised of seven Directors being the Group’s CEO, the Non-Executive Chairman (who was independent
upon appointment) and five other Non-Executive Directors, all of whom were deemed Independent Non-Executive Directors under the UK Corporate
Governance Code, except one. As Mr. Thomas has served on the Board for ten years as of January 1, 2025, the Board no longer considers him
independent. In January 2025, Ms. Kerrigan retired from the Board due to other commitments.
54
As a foreign private issuer, under the listing requirements and rules of the NYSE, we are not required to have independent directors on our Board,
except that our audit committee is required to consist fully of independent directors, subject to certain phase-in schedules. Our Board has determined
that five of our six Directors do not have a relationship that would interfere with the exercise of independent judgment in carrying out the
responsibilities of a director and that each of these directors is “independent” as that term is defined under the rules of the NYSE.
The skills and experience of the Non-Executive Directors are wide and varied and contribute to productive and challenging discussions in the boardroom
ensuring the Board has appropriate independent oversight. For more details on the skills, knowledge and experience of our Board refer to the Directors’
biographies in Board of Directors within this Annual Report & Form 20-F.
With a Non-Executive Chairman, and, as of January 1, 2025, four other Independent Non-Executive Directors, over half of the Board is independent and
the Audit & Risk and Remuneration Committees were completely independent. Female representation at the Board level increased from 29% in
late-2019 to 43% as of December 31, 2024 (three out of seven Board members being female).
Recognizing the importance of workforce engagement, Sandra M. Stash serves as the Director responsible for workforce engagement as required under
the UK Corporate Governance Code. The Non-Executive Director Employee Representative directly engages with employees and provides a forum for
feedback to management. These discussions cover a variety of topics including the Group’s culture, policies and actions. Ms. Stash has served as the
Non-Executive Director Employee Representative since 2019. Further information on her role and the work undertaken can be found in the Directors’
Report within this Annual Report & Form 20-F.
The Board provides effective leadership and overall management of the Group’s affairs. It approves the Group’s strategy and investment plans and
regularly reviews operational and financial performance and risk management matters. A schedule of matters reserved for the Board is included in the
previous section.
The Board and its committees hold regularly scheduled meetings each year. Additional meetings are held when necessary to consider matters of
importance that cannot be held over until the next scheduled meeting.
All Directors have access to the advice and services of the Group’s solicitors and the Group’s Corporate Secretary, who is responsible for ensuring that all
Board procedures are followed. Any Director may take independent professional advice at the Group’s expense in the furtherance of their duties.
In accordance with the UK Corporate Governance Code, the Directors must stand for re-election annually. The Group’s Articles of Association also
require any new Director appointed by the Board during the year to retire at the next Annual General Meeting (“AGM”) and offer themselves for re-
election.
The Board delegates certain responsibilities to the Board committees, listed below, which have clearly defined terms of reference.
These terms of reference are reviewed annually to ensure they remain fit for purpose and can be viewed on the Group’s website.
Board Committees
The Directors have established four Board committees: an Audit & Risk Committee, Remuneration Committee, Nomination & Governance Committee,
and Sustainability & Safety Committee. The members of these committees were constituted in accordance with the requirements of the UK Corporate
Governance Code, as applicable. The terms of reference of the committees have been prepared in line with prevailing best practice, including the
provisions of the Code. A summary of the delegated duties and responsibilities, terms of reference of the committees and their activities for the year are
presented in their committee reports set out below.
Board Composition
The Board’s composition prioritizes a broad range of perspectives, emphasizing professional experience, industry knowledge, and cognitive diversity. In
recent years, the Board has strategically recruited members to enhance these attributes and is now focusing on a period of stability before considering
further additions. Although the Board does not currently have any ethnically diverse members, it acknowledges the UK Listing Rules’ diversity targets,
which the Group intends to continue to closely examine and evaluate in 2025.
In 2024, the Board complied with the UK Listing Rules’ targets of (i) more than 40% female representation on the Board, with 43% of the Board being
female and (ii) a female holding a senior Board position, with Ms. Kerrigan serving as the Senior Independent Director for the entirety through January
24, 2025 and Ms. Stash appointed to that role upon Ms. Kerrigan’s retirement from the Board.
Board and Executive Management Composition
As required to be presented in accordance with UK Listing Rule 6.6.6R(10) as of December 31, 2024:
Gender Identity or Sex(a)
Number of Board
Members
Percentage of the
Board
Number of Senior
Positions on the
Board (CEO, CFO,
SID & Chair)(a)
Number in
Executive
Management
Percentage of
Executive
Management
Male
4
57%
3
6
67%
Female
3
43%
1
3
33%
Other categories
—%
—%
Not specified/prefer not to say
—%
—%
55
Ethnic Background
Number of Board
Members
Percentage of the
Board
Number of Senior
Positions on the
Board (CEO, CFO,
SID & Chair)(a)
Number in
Executive
Management
Percentage of
Executive
Management
White British or other
White (including
minority-white groups)
7
100%
4
9
100%
Mixed/Multiple Ethnic Groups
—%
—%
Asian/Asian British
—%
—%
Black/African/Caribbean/Black
British
—%
—%
Other ethnic group, including
Arab
—%
—%
Not specific/prefer not to say
—%
—%
(a)The 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.
UK Corporate Governance Code Compliance Statement
The Directors support high standards of corporate governance, and it is the policy of the Group to comply with current best practice in UK corporate
governance.
The UK Corporate Governance Code published in July 2018 by the Financial Reporting Council (“FRC”), as amended from time to time, (the “Corporate
Governance Code”) recommends that: (i) the Chair of the Board of Directors should meet the independence criteria set out in the Corporate Governance
Code on appointment; and (ii) the Board should appoint one of the Independent Non-Executive Directors to be the Senior Independent Director. The
Chair of the Board is David E. Johnson, who was independent as of his appointment and whom the Group continues to consider independent, and the
Senior Independent Director for the year ended December 31, 2024 was Sylvia Kerrigan. The Board also considers Sandra M. Stash, David J. Turner, Jr.,
Sylvia Kerrigan and Kathryn Z. Klaber to meet the independence criteria set out in the Corporate Governance Code. Following the resignation of Sylvia
Kerrigan from the Board on January 24, 2025, Sandra Stash has been appointed as the Senior Independent Director. Since January 1, 2025, the
Company has been subject to the UK Corporate Governance Code 2024 (the ”2024 Code”) and will report on its compliance with the principles and
provisions of the 2024 Code in its 2025 Annual Report.
Currently, the Board is of the opinion that as of the date of this report it fully complies with the requirements of the Corporate Governance Code.
Additionally, the Directors acknowledge the requirement to implement a diversity policy that will be applicable to the Group’s administrative,
management and supervisory bodies and the Remuneration, Audit & Risk and Nomination & Governance committees. For more details, refer to Board
Composition and Workforce Composition within this Annual Report & Form 20-F.
Our Approach to Governance
As of the date of this Annual Report & Form 20-F, our Board is made up of six Directors: one Executive Director, chairman and four Non-Executive
Directors (all of whom are independent, except one).
Alongside the continued focus on our business strategy, we achieved significant milestones in 2024 in strengthening core areas of the business. One
such area of focus was corporate governance, where we engaged external consultants to advise on Board best practices, including independence,
composition and expertise.
Key Governance Improvements During 2024
The Board recognizes the benefits of good governance and is seeking to apply this in a meaningful way. DEC is a rapidly evolving company that is in an
expansion and transition phase. Accordingly, the Board is acutely aware of the need to rapidly and effectively integrate new businesses into the
reporting and governance framework of the Group, as determined by the Board. It is recognized that the Board has a key role in balancing the
fundamental elements of good governance, namely to deliver business growth and build trust while maintaining a dynamic management framework.
The Board appreciates the importance of good and effective communication and remains in close contact with its shareholders and other stakeholders.
The Board is actively engaged in the process of solidifying its governance framework for its rapidly expanding business. The Board concluded that
overall compliance with governance best practice has improved during the year under review, with the following having been achieved:
The Board re-affirmed several key governance policies including the following: Securities Dealing Policy, Whistleblowing Policy, Anti-Bribery &
Corruption Policy, Socio-Economic Policy, Modern Slavery Policy, EHS Policy, Climate Policy, Employee Relations Policy, Human Rights Policy,
Business Partners Policy, Biodiversity Policy, Code of Business Conduct & Ethics, and Tax Policy.
The Board achieved further progression of the Group’s overall corporate governance framework and practices, taking into account evolving market
best practices and the Group’s NYSE-listing, including, among other things, a continued review and update of the Group’s committee charters and
governance policies.
The Audit & Risk Committee is fully independent and continues to adopt best practice.
The Remuneration Committee is also independent with three Non-Executive Directors and the Non-Executive Chairman, and, together with a third-
party consultant, conducted a thorough review of the remuneration policy and practices and undertook a consultation exercise with the Group’s
largest shareholders.
56
Each committee completed a thorough charter evaluation to identify gaps in coverage, relevance and applicability as well as potential areas of
improvement.
Together with the executive management team, the Chairman and the Nomination & Governance Committee continued to formulate succession
planning procedures and plans around key-roles in management.
The Board encouraged employee outreach and training regarding the Group’s Whistleblowing Policy and was satisfied by measures taken, including
the placement of awareness posters with hotline details in all major offices.
Sylvia Kerrigan continued to serve as Senior Independent Director (for the entirety of 2024 and resigned as a director on January 24, 2025).
Corporate Governance Practices and Foreign Private Issuer Status
Companies listed on the NYSE must comply with the corporate governance standards provided under Section 303A of the NYSE Listed Company Manual.
As a “foreign private issuer,” as defined by the SEC, we are permitted to follow home country corporate governance practices, instead of certain
corporate governance practices required by the NYSE for U.S. domestic issuers, except that we are required to comply with Sections 303A.06, 303A.11
and 303A.12(b) and (c) of the Listed Company Manual. Under Section 303A.06, we must have an audit committee that meets the independence
requirements of Rule 10A-3 under the Exchange Act. Under Section 303A.06, we must disclose any significant ways in which our corporate governance
practices differ from those followed by domestic companies under NYSE listing standards. Finally, under Section 303A.12(b) and (c), we must promptly
notify the NYSE in writing after becoming aware of any non-compliance with any applicable provisions of this Section 303A and must annually make a
written affirmation to the NYSE. Further, an LSE listed company must disclose in its annual financial report a statement of how the listed company has
applied the principles set out in the UK Corporate Governance Code, in a manner that would enable shareholders to evaluate how the principles have
been applied, and a statement as to whether the listed company has (a) complied throughout the accounting period with all relevant provisions set out
in the UK Corporate Governance Code; or (b) not complied throughout the accounting period with all relevant provisions set out in the UK Corporate
Governance Code and if so, setting out: (i) those provisions, if any it has not complied with; (ii) in the case of provisions whose requirements are of a
continuing nature, the period within which, if any, it did not comply with some or all of those provisions; and (iii) the company’s reasons for
non-compliance.
For the purposes of NYSE rules, so long as the Group qualifies as a foreign private issuer, we are eligible to take advantage of certain exemptions from
NYSE corporate governance requirements provided in the NYSE rules. We are required to disclose the significant ways in which our corporate
governance practices differ from those that apply to U.S. companies under NYSE listing standards.
Section 312.03 of the NYSE Rules requires that a listed company obtain, in specified circumstances, (1) shareholder approval to adopt or materially
revise equity compensation plans, as well as (2) shareholder approval prior to an issuance (a) of more than 1% of its ordinary shares (including
derivative securities thereof) in either number or voting power to related parties, (b) of more than 20% of its outstanding ordinary shares (including
derivative securities thereof) in either number or voting power or (c) that would result in a change of control. The Group intends to follow home country
law in determining whether shareholder approval is required. Section 302 of the NYSE Rules also requires that a listed company hold an annual
shareholders’ meeting for holders of securities during each fiscal year. We will follow home country law in determining whether and when such
shareholders’ meetings are required.
The Group may in the future decide to use other foreign private issuer exemptions with respect to some or all of the other requirements under the NYSE
Rules. Following our home country governance practices may provide less protection than is accorded to investors under the NYSE listing requirements
applicable to domestic issuers. We intend to take all actions necessary for us to maintain compliance as a foreign private issuer under the applicable
corporate governance requirements of the Sarbanes-Oxley Act of 2002, the rules adopted by the SEC and NYSE listing standards. Because we are a
foreign private issuer, our directors and senior management are not subject to short swing profit and insider trading reporting obligations under Section
16 of the Exchange Act. They will, however, be subject to the obligations to report changes in share ownership under Section 13 of the Exchange Act
and related SEC rules.
57
Board of Directors
The Group has a commitment to strong governance, reporting and operating standards. During 2024, the Board comprised of seven Directors: including
a Non-Executive Chair (who was independent upon appointment and whom the Group continues to consider independent), a Non-Executive Vice-Chair,
an Executive Director, the Senior Independent Director, three additional independent Non-Executive Directors.
David E. Johnson
Rusty Hutson, Jr.
Martin K. Thomas
Non-Executive Chairman, independent
upon appointment
Co-Founder and Chief Executive Officer
Non-Executive Vice Chair, independent
through December 31, 2023
Age
64
55
60
Appointed
February 3, 2017 and as Chair of the
Board on April 30, 2019
July 31, 2014
January 1, 2015
Committee
Membership
Remuneration Committee, Sustainability &
Safety Committee
None
Nomination & Governance Committee
Experience
Mr. Johnson has served on our Board of
Directors since February 2017 and as the
Independent Chairman since April 2019.
He has worked at a number of leading
investment firms, as both an investment
analyst and a manager, and more recently
in equity sales and investment
management. Mr. Johnson currently serves
on the board of Chelverton Equity
Partners, an AIM-listed holding company,
where he serves as a member of the
Remuneration, Audit and Nomination
committees. Previously, Mr. Johnson was a
consultant at Chelverton Asset
Management from August 2016 to
February 2019. Prior to that, he worked as
a fund manager for the investment
department a large insurance company
and then as Head of Sales and Head of
Equities at a London investment bank. Mr.
Johnson earned a Bachelor of Arts in
Economics from the University of Reading.
Mr. Hutson is our co-founder and has
served as our Chief Executive Officer since
the founding of our predecessor entity in
2001. Mr. Hutson also serves on our Board
of Directors. Mr. Hutson is the fourth
generation in his family to immerse himself
in the natural gas and oil industry, with
family roots dating back to the early
1900s. Mr. Hutson spent many summers of
his youth working with his father and
grandfather in the oilfields of West
Virginia. He graduated from Fairmont State
College (WV) with a degree in accounting.
After college, Mr. Hutson spent 13 years
steadily progressing into multiple
leadership roles at well-known banking
institutions such as Bank One and
Compass Bank. His final years in the
banking industry were spent as CFO of
Compass Financial Services. Building upon
his experiences in the natural gas and oil
industry, as well as the financial sector,
Mr. Hutson established Diversified Energy
Company in 2001. After years of refining
his strategy, Mr. Hutson and his team took
Diversified public in 2017. He continues to
lead his team and expand the Group’s
footprint. With a rapidly growing portfolio,
Mr. Hutson remains focused on operational
excellence and creating shareholder value.
Mr. Thomas has served on our Board of
Directors since January 2015. Since
January 2022, Mr. Thomas has served as a
consultant at the law firm Wedlake Bell
LLP, from where he was previously a
Partner from January 2018 to December
2021. During his more than 30-year legal
career, Mr. Thomas has also served as
Partner of Watson Farley & Williams LLP
from February 2015 to April 2017 and as
consultant of the same firm from May 2017
to May 2018. Mr. Thomas earned a
Bachelor of Laws from the University of
Reading and completed his Law Society
Final Examinations at The College of Law
in the UK.
Key
Strengths
Investment sector knowledge; finance;
providing strong leadership to the Board in
connection with the Board’s role of
overseeing strategy and developing
stakeholder relations.
Deep understanding and leadership in the
natural gas and oil sector; strong track
record in developing and delivering results
in line with strategy; finance; risk
management.
Corporate law; advising on mergers and
acquisitions; public offerings.
Current
External
Roles
Chelverton Equity Partners (Director), an
AIM-listed holding company
Board of Governors of West Virginia
University
Wedlake Bell LLP (Consultant) and Jasper
Consultants Limited (Director)
58
Board of Directors (continued)
Sandra M. Stash
David J. Turner, Jr.
Kathryn Z. Klaber
Independent Non-Executive Director &
Non-Executive Director Employee
Representative
Independent Non-Executive Director
Independent Non-Executive Director
Age
65
61
58
Appointed
October 21, 2019
May 27, 2019
January 1, 2023
Committee
Membership
Sustainability & Safety Committee (Chair),
Remuneration Committee, Audit & Risk
Committee
Audit & Risk Committee (Chair),
Remuneration Committee (appointed Chair
on January 24, 2025), Nomination &
Governance Committee
Nomination & Governance Committee
(Chair), Audit & Risk Committee,
Sustainability & Safety Committee
Experience
Ms. Stash has served on our Board of
Directors since October 2019. Ms. Stash
joined Tullow Oil in October 2013 serving
as Executive Vice President of Safety,
Operations and Engineering, and External
Affairs where she served until March 2020.
Ms. Stash is a Certified Director of the US
National Association of Corporate Directors
and a Fellow of the Canadian Academy of
Engineering and currently serves on the
boards of Medallion Midstream LLC, Trans
Mountain Company, Warriors and Quiet
Waters as Chair, the Colorado School of
Mines Board of Governors, First Montana
Bank, and the African Gifted Foundation.
Ms. Stash earned a Bachelor of Science in
Petroleum Engineering from the Colorado
School of Mines and is a Registered
Professional Engineer
Mr. Turner has served on our Board of
Directors since May 2019. Mr. Turner has
served as Chief Financial Officer of Regions
Financial Corporation (NYSE: RF) since
2010 where he leads all finance
operations, including mergers and
acquisitions, financial systems, investor
relations, corporate treasury, corporate
tax, management planning and reporting
and accounting. Prior to his appointment
as Chief Financial Officer, Mr. Turner
oversaw the Internal Audit Division for
AmSouth Bank (which merged with
Regions Financial Corporation in 2006)
from April 2005 to March 2010. Before
beginning his banking career, Mr. Turner
was a certified public accountant and an
Audit Partner with Arthur Andersen and
KPMG specializing in financial services
clients. He earned a Bachelor of Science in
Accounting from the University of
Alabama.
Ms. Klaber has served on our Board of
Directors since January 2023. Since 2014,
Ms. Klaber has served as the Managing
Director of The Klaber Group, which
provides strategic consulting services to
businesses and organizations with a focus
on energy development in the United
States and abroad. Prior to founding The
Klaber Group, Ms. Klaber launched the
Marcellus Shale Coalition, serving as its
first CEO from 2009 to 2013. Previously in
her career, Ms. Klaber also served as the
Executive Vice President for
Competitiveness at the Allegheny
Conference on Community Development,
Executive Director of the Pennsylvania
Economy League, and consultant at
Environmental Resources Management,
where she gained significant experience in
EHS strategy and compliance. Ms. Klaber
received her B.A. in Environmental Science
from Bucknell University and her MBA from
Carnegie Mellon University.
Key
Strengths
Risk management & sustainability;
operations & engineering;
employee engagement.
Financial expert with recent and relevant
experience; capital markets; financial
operations; audit experience; risk
management.
Regulatory compliance, energy specific
sustainability programs; EHS processes
industry knowledge, risk management;
governance.
Current
External
Roles
Colorado School of Mines (Board of
Governors member), Trans Mountain
Company, Warriors and Quiet Waters, a
Canadian Crown Corporation (Chair and
Director), First Montana Bank (Director),
and Medallion Midstream, LLC (Director)
Regions Financial Corporation (CFO),
Junior Achievement of Alabama, Inc.
(Board and Executive Committee),
Leadership Alabama (Director), a nonprofit
organization, and Five Star Preserve
(Director), a nonprofit organization
RLG International (Director), Junior
Achievement of Western Pennsylvania
(Director and immediate past-Chair), and
Beaver County Chamber of Commerce
(Beaver County, Pennsylvania) (Chair)
59
Board of Directors (continued)
Senior Management
Sylvia Kerrigan
Bradley G. Gray
Ben Sullivan
Senior Independent Non-Executive
Director (ceased to be a director on
January 24, 2025)
President and Chief Financial Officer
Senior Executive Vice President, Chief
Legal & Risk Officer, and Corporate
Secretary
Age
59
56
46
Appointed
October 11, 2021
Committee
Membership
Remuneration Committee (Chair for
entirety of 2024 through January 24,
2025), Nomination & Governance
Committee
Experience
Ms. Kerrigan has served on our Board of
Directors since October 2021. Currently,
she is the Chief Legal Officer at Occidental
Petroleum Corporation (NYSE: OXY). Prior
to joining Occidental, Ms. Kerrigan served
as the Executive Director of the Kay Bailey
Hutchinson Center for Energy, Law and
Business at the University of Texas, where
she remains a member of the Executive
Council. In Ms. Kerrigan’s more than 20
years with Marathon Oil Corporation, she
served in a number of roles overseeing
public policy, legal and compliance,
corporate positioning and external
communications before retiring in 2017
after eight years as the Executive Vice
President, General Counsel and Corporate
Secretary. Ms. Kerrigan has also served as
a director for Hornbeck Offshore Services,
Inc. since August 2022 and Board of
Trustees for Southwestern University since
March 2014. Ms. Kerrigan holds a
Directorship Certification through the
National Association of Corporate
Directors. Ms. Kerrigan earned a Bachelor
of Arts from Southwestern University and a
Doctor of Jurisprudence from the
University of Texas at Austin School of
Law.
Mr. Gray has served as our President and
Chief Financial Officer since September
2023. Mr. Gray has also served as the
Group’s Executive Vice President, Chief
Operating Officer since October 2016 to
September 2023. Mr. Gray has also served
on the Board of Directors until September
2023. Prior to joining the Group, Mr. Gray
served as the Senior Vice President and
Chief Financial Officer for Royal Cup, Inc.
from August 2014 to October 2016. Prior
to that, from 2006 to 2014, Mr. Gray
served in various roles at The McPherson
Companies, Inc., most recently as
Executive Vice President and Chief
Financial Officer from September 2006 to
December 2013. Mr. Gray previously
worked in various financial and operational
roles at Saks Incorporated from 1997 to
2006. Mr. Gray has a B.S. degree in
Accounting from the University of Alabama
and was formerly a licensed CPA
(Alabama).
Mr. Sullivan has served as our Senior
Executive Vice President, Chief Legal &
Risk Officer, and Corporate Secretary since
September 2023, and prior to that served
as Executive Vice President, General
Counsel and Corporate Secretary since
2019. Prior to joining us, Mr. Sullivan
worked with Greylock Energy, LLC (an
ArcLight Capital Partners portfolio
company) and its predecessor, Energy
Corporation of America, from 2012 to
2017, most recently as Executive Vice
President, General Counsel and Corporate
Secretary from 2017 to 2019. Prior to that,
Mr. Sullivan served as counsel for EQT
Corporation from 2006 to 2012. He is a
member of the leadership and board of
directors of several commerce, legal and
industry groups, and has considerable
experience in corporate governance and
reporting, corporate responsibility and
sustainability matters, complex commercial
transactions, land/real estate, acquisitions
& divestitures, financing, government
investigations and corporate workouts and
restructurings. Mr. Sullivan received a B.A.
from the University of Kentucky and a J.D.
degree from the West Virginia University
College of Law. He holds licenses to
practice law in several states, including
Pennsylvania and West Virginia.
Key
Strengths
Corporate law; governance; merger and
acquisition; regulatory; risk management;
cybersecurity and information privacy
matters; corporate responsibility
and sustainability.
Corporate structure; operational processes
and management; finance; strategic
support to the CEO; mergers and
acquisitions; acquisition integration;
information technology; personnel
leadership.
Legal expert, mergers and acquisitions,
land/real estate, regulatory compliance
and governance, risk management and
strategic support to the CEO.
Current
External
Roles
Occidental Petroleum (Chief Legal Officer),
Kay Bailey Hutchinson Center for Energy,
Law and Business at the University of
Texas (Director), and Hornbeck Offshore
Services, Inc. (Director)
None
None
60
Directors’ Report
The Directors present their report on the Group, together with the audited Group Financial Statements, for the year ended December 31, 2024.
Board of Directors
The Directors of the Group who were in office during the year and up to the date of signing the financial statements were:
David E. Johnson - Non-Executive Chair (independent upon appointment)
Rusty Hutson, Jr. - Chief Executive Officer and Executive Director
Martin K. Thomas - Non-Executive Vice Chair
David J. Turner, Jr. - Independent Non-Executive Director
Sandra M. Stash - Independent Non-Executive Director
Sylvia Kerrigan - Senior Independent Non-Executive Director (for the entirety of 2024 through January 24, 2025)
Kathryn Z. Klaber - Independent Non-Executive Director
Incorporation and Listing
The Company was incorporated on July 31, 2014, and completed the transfer to the Official List of the Financial Conduct Authority (“FCA”) and
admission to the Main Market of the LSE from AIM in May 2020. The Company commenced trading on the New York Stock Exchange (“NYSE”) on
December 18, 2023. Following the changes to the UK Listing Rules on 29 July 2024, the Premium Listing Segment was replaced by the Equity Shares
(Commercial Companies) category and the Company continues to remain listed on the new equity shares (commercial companies) category of the
Official List of the Financial Conduct Authority.
Review of Business, Outlook & Dividends
The Group is a natural gas, NGLs and oil producer and midstream operator and is focused on acquiring and operating mature producing wells with long
lives and low-decline profiles. The Group’s assets have historically been located within the Appalachian Region, but the Group has acquired assets
expanding its footprint into the Central Region, consisting of the states of Louisiana, Texas and Oklahoma. The Group is headquartered in Birmingham,
Alabama, U.S., and has field offices located throughout the states in which it operates.
Details of the Group’s progress during the year and its future prospects are provided in the Strategic Report within this Annual Report & Form 20-F.
Results
The Group’s reported statutory loss for 2024 was $87 million, or $1.84 per share, and when adjusted for certain non-cash items, it reported adjusted
EBITDA of $472 million. The Group’s adjusted EBITDA for 2023 was $547 million. For more information on adjusted EBITDA refer to APMs within this
Annual Report & Form 20-F.
Dividend Approach
The Board’s target has been to return free cash flow to shareholders by way of dividend, on a quarterly basis, in line with the strength and consistency
of the Group’s cash flows.
For the three months ended March 31, 2024, the Group paid a dividend of $0.290 per share on September 27, 2024. For the three months ended
June 30, 2024, the Group paid a dividend of $0.290 per share on December 27, 2024. For the three months ended September 30, 2024, the Group
expects to pay a dividend of $0.290 per share on March 31, 2025. For the three months ended December 31, 2024, the Group expects to pay a dividend
of $0.29 per share.
The Directors may further revise the Group’s approach to dividends from time to time in line with the Group’s actual results and financial position. The
Board’s approach to its dividend reflects the Group’s current and expected future cash flow generation potential.
Disclosure of Information under UKLR 6.6.1R
The information that fulfills the reporting requirements under this rule can be found in the locations identified below.
Section
Topic
Location
(1)
Interest capitalized
Not applicable
(2)
Publication of unaudited financial information
Not applicable
(4)
Details of long-term incentive schemes
(5)
Waiver of emoluments by a Director
Not applicable
(6)
Waiver of future emoluments by a Director
Not applicable
(7)
Non pre-emptive issues of equity for cash
(8)
As item (7), in relation to major subsidiary undertakings
Not applicable
(9)
Parent participation in a placing by a listed subsidiary
Not applicable
(10)
Contracts of significance
(11)
Provision of services by a controlling shareholder
Not applicable
(12)
Shareholder waivers of dividends
Not applicable
(13)
Shareholder waivers of future dividends
Not applicable
(14)
Agreements with controlling shareholders
Not applicable
61
Directors’ Interest in Shares
The Directors’ beneficial interests in the Group’s share capital, including family interests, on December 31, 2024 are shown below. These interests are
based on the issued share capital at that time. As of February 28, 2025, there have been no changes to the Directors’ interests. The Non-Executive
Directors will purchase shares after the release of this Annual Report & Form 20-F pursuant to the Non-Executive Director Share Purchase Program
implemented in 2022.
Director
Appointed
Shares of £0.20
% of Issued Share Capital
Rusty Hutson, Jr.
July 31, 2014
1,234,134
2.41%
Martin K. Thomas
January 1, 2015
113,850
0.22%
David E. Johnson
February 3, 2017
23,750
0.05%
David J. Turner, Jr.
May 27, 2019
33,087
0.06%
Sandra M. Stash
October 21, 2019
4,092
0.01%
Kathryn Klaber
January 1, 2023
2,912
0.01%
Sylvia Kerrigan
October 11, 2021
3,181
0.01%
1,415,006
2.77%
Future Developments
The Directors continue to review and evaluate strategic acquisition opportunities recommended by the Senior Leadership Team, which align with the
strategy and requirements of the Group. Additional details are disclosed in Strategy within this Annual Report & Form 20-F.
Share Capital
As of December 31, 2024, the Group’s issued share capital consisted of 51,295,942 shares with a par value of £0.20 each, with ~45% of record holders
in the U.S. and ~55% of record holders in the UK. The Group has only one class of share and each share carries the right to one vote at the Group’s
AGM. No person has any special rights of control over the Group’s share capital and all issued shares are fully paid. There are no specific restrictions on
the size of a holding nor on the transfer of shares, which are both governed by the general provisions of the Group’s Articles of Association and
prevailing legislation. The Directors are not aware of any agreements between holders of the Group’s shares that may result in restrictions on the
transfer of securities or on voting rights.
The Group was authorized by shareholders at the 2024 AGM held on May 10, 2024 to purchase in the market up to 10% of its issued shares (excluding
any treasury shares), subject to certain conditions laid out in the authorizing resolution. The standard authority is renewable annually; the Directors will
seek to renew this authority at the upcoming AGM. Details of shares issued and repurchased by the Group during the period are set out in Note 16 in
the Notes to the Group Financial Statements.
In the second half of 2024, the Company issued 4,592,095 new ordinary shares at an average $12.13 per share (£9.41) for aggregate gross proceeds of
$56 million to fund a portion of the East Texas II and Crescent Pass transactions, discussed in Note 5. The new shares issued represented 9% of the
Company’s existing share capital as of December 31, 2024.
Employee Benefit Trust
An Employee Benefit Trust (“EBT”) was established in 2022 to purchase shares already in the market and is operated through a third-party trustee. The
objective of the EBT is to benefit the Group’s employees and in particular, to provide a mechanism to satisfy rights to shares arising on the exercise or
vesting of awards under the Group’s share-based incentive plans and reduce dilution for shareholders. As of February 28, 2025, the EBT holds 646,098
shares and has distributed 561,566 shares under the Group’s share-based incentive plans.
Financial Instruments
Details of the Group’s principal risks and uncertainties relating to financial instruments are detailed below and in Note 25 in the Notes to the Group
Financial Statements.
Risk Management
Risk management is integral to all of the Group’s activities. Each member of executive management is responsible for continuously monitoring and
managing risk within the relevant business areas. Every material decision is preceded by an evaluation of applicable business risks. Reports on the
Group’s risk exposure and reviews of its risk management are regularly undertaken and presented to the Board. Additional details regarding the Group’s
risk management can be found in Principal Risks and Uncertainties in the Strategic Report within this Annual Report & Form 20-F.
Securities Dealing Code
The Group adopted a Securities Dealing Code for share dealings reasonably designed for a company listed on the equity shares (commercial companies)
category of the Official List of the FCA and admitted to the Main Market of the LSE and NYSE-listed company to promote compliance with insider trading
laws, rules, regulations and applicable listing standards. The code applies to the Directors, members of the Senior Leadership Team and other relevant
employees of the Group and is monitored by the Group’s compliance-focused employees.
Other Corporate Governance Policies
The Board reviewed, updated, and reaffirmed several key governance policies in 2024, including the following:
Whistleblowing Policy - aims to provide guidance as to how individuals may raise their concerns and to ensure that they may do so confidently
and confidentially.
Anti-Bribery & Corruption Policy - acknowledges the Group’s commitment to right and ethical practices and addresses bribery and corruption
risk as a part of the Group’s overall risk management strategy.
62
Socio-Economic Policy - affirms the Group’s commitment to being recognized as a leader in the field of corporate responsibility and recognizes
the added value for our shareholders.
Modern Slavery Policy - recognizes that modern slavery is a significant global human rights issue and has many forms including human
trafficking, forced labor, child labor, domestic servitude, people trafficking and workplace abuse. The Group is committed to respecting
internationally recognized human rights, including ensuring that we are in no way involved or associated with the issue of forced or involuntary
labor and that modern slavery and human trafficking are not taking place in any part of our business.
EHS Policy - guides activities to protect employees, contractors, the public and the environment.
Climate Policy - recognizes that climate change is a complex global issue that may have an impact of the Group’s operations, processes,
equipment and capabilities.
Employee Relations Policy - acknowledges the value of the Group’s employees and highlights the Group’s commitments to promote employee
safety, health and well-being.
Human Rights Policy - recognizes the Group’s commitment and responsibility to ensure that human rights are upheld in every of its business
operations and to promote human rights where it can make a positive contribution.
Business Partners Policy - provides the standards the Group expects from its consultants, outsourced providers, subcontractors, vendors and
suppliers to adhere to in their business activities with the Group.
Biodiversity Policy - outlines the Group’s commitment to promote a net positive impact on the environment and its natural biodiversity.
Code of Business Conduct & Ethics - provides the standards the Group expects from its Directors, officers and employees, including honest and
ethical conduct, compliance with applicable laws and prompt internal reporting and accountability for adherence to the code.
Tax Policy - outlines the Group’s tax objections and the foundation of the Group’s tax approach.
These corporate governance policies can be viewed on the Group’s website at www.div.energy/about-us/corporate-governance.
Subsequent Events
Refer to Note 28 in the Notes to the Group Financial Statements.
Director Attendance at Board and Committee Meetings
Directors are expected to attend and participate in all Board meetings and meetings of committees on which they serve and are expected to be available
for consultation with management as requested from time to time. Regular Board and committee meetings are held at such times as the Board and
committees, respectively, may determine. Special meetings may be called upon appropriate notice at any time.
The following table shows the number of Board and committee meetings required to be held and actually held in 2024:
Type of Meeting
Number of Meetings
Required to be Held
Number of
Meetings Held
Board of Directors
10
Audit & Risk Committee
3
5
Nomination & Governance Committee
2
3
Remuneration Committee
2
3
Sustainability & Safety Committee
2
6
Members of the Board attended Board and committee meetings (to the extent they were members of such committee in 2024) as summarized in the
following table.
Director
Committee Seats
(during 2024)
Board
Audit & Risk
Committee
Nomination &
Governance
Committee
Sustainability &
Safety
Committee
Remuneration
Committee
Rusty Hutson, Jr.
None
10
David E. Johnson
R,S
10
6
3
Martin K. Thomas
N
10
3
Kathryn Z. Klaber
N,A,S
10
5
3
6
Sandra M. Stash
S,A,R
10
5
6
3
David J. Turner, Jr.
A,R
10
5
3
Sylvia Kerrigan
R,N
10
3
3
Directors’ Indemnities
As permitted by the Group’s Articles of Association, the Directors have the benefit of an indemnity, which is a qualifying third-party indemnity provision
as defined by Section 234 of the Companies Act 2006. The indemnity was in force during the financial year and remains in force at the date of this
report. The Group also purchased and maintained throughout the financial period Directors’ and officers’ liability insurance in respect of itself and its
Directors. This confirmation is given and should be interpreted in accordance with the provisions of Section 418 of the Companies Act 2006.
63
Conflict of Interest
There are no potential conflicts of interest between any duties owed by the Directors or members of the Senior Leadership Team to the Group and their
private interests and/or other duties. In addition, there are no arrangements or understandings with any of the shareholders of the Group, customers,
suppliers or others pursuant to which any Director or member of the Senior Leadership Team was selected to be a Director or Senior Manager. The
Group tests regularly to ensure awareness of any future potential conflicts of interest and related party transactions. Directors are required to declare
any additional or changed interests at the beginning of each Board meeting. In the event a conflict should arise, the pertinent Director would not take
part in decision making related to the conflict. Additionally, there are no family relationships among any of our Directors or Senior Managers
Substantial Shareholders
As of February 26, 2025, the following shareholders hold greater than 3% of the Group’s issued shares with voting rights:
Shareholders(a)
Number of Shares
% of Issued Share
Capital
BlackRock
4,909,399
8.21%
Columbia Management Investment Advisers
3,251,605
5.44%
Jupiter Asset Management
2,792,978