20-F: Annual and transition report of foreign private issuers pursuant to Section 13 or 15(d)
Published on March 19, 2024
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
(Mark One)
OR
For the fiscal year ended December 31 , 2023
OR
OR
Date of event requiring this shell company report
For the transition period from to
Commission file number: 001-41870

(Exact name of Registrant as specified in its charter) |
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Not Applicable |
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(Translation of Registrant’s name into English) |
(Jurisdiction of incorporation or organization) |
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Diversified Energy Company PLC
Tel: +1
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(Address of principal executive offices) |
(Name, Telephone, E-mail and/or Facsimile
number and Address of Company Contact
Person)
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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 |
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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 ¨ No þ
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
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¨ Accelerated filer
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þ |
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 which basis of accounting the registrant has used to prepare the financial statements included in this filing:
¨ U.S. GAAP
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þ |
¨ Other
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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 ¨ No þ
(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 ¨

2023
Annual Report
& FORM 20-F

Our Core Values
We CARE for each other, our communities, our industry
and our country!
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COMMITMENT
—Seek opportunities for continuous learning
and improvement.
—Serve and support our teams and communities with
passion and enthusiasm.
ACCOUNTABILITY
—Act with personal and business integrity.
RESPECT
—Value the dignity and worth of all individuals.
—Respect environmental stewardship as we make
business decisions.
EXCELLENCE
—Commit to excellence in our performance.
—Exhibit courage of convictions, challenge the status quo
and strive to create value.
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Report of Independent Registered Public Accounting
Firm
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Additional Information (Unaudited)
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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. Within the APMs section located in the Additional Information section
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.”

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 primarily natural gas.
Our proven business model creates sustainable value in today's natural gas market 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 then Retire our wells at the end of their life to optimally steward the resource already
developed by others within our industry, 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.
Key Achievements
Accretive Growth
Investment in the Tanos II
Central Region acquisition
totaled $262 million and
bolstered average daily
production by 8%.
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Asset Monetization
Unlocked value on non-core
assets through the sale of
undeveloped acreage and
non-operated well interests
for total consideration of
$66 million.
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U.S. Listing
Commenced trading on the
New York Stock Exchange
under the “DEC” ticker in
December 2023, expanding
access to U.S. investors and
improving trading liquidity.
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Prioritizing Sustainability
Realized 33% year-over-year
reduction in Scope 1
methane intensity, achieving
our 2030 goal of cumulative
50% reduction in Scope 1
methane intensity (from
2020 baseline) and driven
largely by our focused and
continual emissions
detection, measurement and
mitigation programs in both
our Appalachia and Central
regions.
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Financing
Executed the sale of certain
producing assets in
Appalachia to a special
purpose vehicle “SPV”,
generating proceeds of
approximately $192 million
through placement of an
asset-backed securitization at
the SPV, including the sale of
an 80% equity interest in the
SPV for $30 million.
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Delivering Shareholder Value
Share buybacks and
distributed dividends
represent $179 million in
return of capital to
shareholders.
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Cross Reference to Form 20-F
Pages |
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Part I |
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Item 1. |
Identity of Directors, Senior Management and Advisers |
N/A |
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Item 2. |
Offer Statistics and Expected Timetable |
N/A |
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Item 3. |
Key Information |
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A. |
[Reserved] |
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B. |
Capitalization and indebtedness |
N/A |
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C. |
Reasons for the offer and use of proceeds |
N/A |
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D. |
Risk factors |
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Item 4. |
Information on the Group |
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A. |
History and development of the Group |
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B. |
Business overview |
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C. |
Organizational structure |
181, Exhibit 8.1
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D. |
Property, plants and equipment |
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Item 4A. |
Unresolved Staff Comments |
N/A |
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Item 5. |
Operating and Financial Review and Prospects |
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A. |
Operating results |
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B. |
Liquidity and capital resources |
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C. |
Research and development, patents and licenses, etc. |
N/A |
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D. |
Trend information |
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E. |
Critical accounting estimates |
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Item 6. |
Directors, Senior Management and Employees |
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A. |
Directors and senior management |
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B. |
Compensation |
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C. |
Board practices |
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D. |
Employees |
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E. |
Share ownership |
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F. |
Disclosure of a registrant’s action to recover erroneously awarded
compensation
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N/A |
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Item 7. |
Major Shareholders and Related Party Transactions |
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A. |
Major shareholders |
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B. |
Related party transactions |
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C. |
Interests of experts and counsel |
N/A |
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Item 8. |
Financial Information |
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A. |
Consolidated Statements and Other Financial Information |
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B. |
Significant Changes |
N/A |
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Item 9. |
The Offer and Listing |
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A. |
Offer and listing details |
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B. |
Plan of distribution |
N/A |
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C. |
Markets |
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D. |
Selling shareholders |
N/A |
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E. |
Dilution |
N/A |
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F. |
Expenses of the issue |
N/A |
Pages |
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Item 10. |
Additional Information |
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A. |
Share capital |
N/A |
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B. |
Memorandum and articles of association |
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C. |
Material contracts |
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D. |
Exchange controls |
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E. |
Taxation |
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F. |
Dividends and paying agents |
N/A |
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G. |
Statement by experts |
N/A |
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H. |
Documents on display |
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I. |
Subsidiary information |
N/A |
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J. |
Annual report to security holders |
N/A |
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Item 11. |
Quantitative and Qualitative Disclosures About Market Risk |
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Item 12. |
Description of Securities Other than Equity Securities |
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A. |
Debt securities |
N/A |
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B. |
Warrants and rights |
N/A |
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C. |
Other securities |
N/A |
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D. |
American depositary shares |
N/A |
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Part II |
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Item 13. |
Defaults, Dividend Arrearages and Delinquencies |
N/A |
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Item 14. |
Material Modifications to the Rights of Security Holders and Use of Proceeds |
N/A |
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Item 15. |
Controls and Procedures |
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Item 16. |
[Reserved] |
N/A |
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Item 16A. |
Audit Committee Financial Expert |
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Item 16B. |
Code of Ethics |
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Item 16C. |
Principal Accountant Fees and Services |
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Item 16D. |
Exemptions from the Listing Standards for Audit Committees |
N/A |
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Item 16E. |
Purchases of Equity Securities by the Issuer and Affiliated Purchasers |
N/A |
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Item 16F. |
Change in Registrant’s Certifying Accountant |
N/A |
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Item 16G. |
Corporate Governance |
N/A |
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Item 16H. |
Mine Safety Disclosure |
N/A |
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Item 16I. |
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections |
N/A |
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Item 16J. |
Insider Trading Policies |
N/A |
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Item 16K. |
Cybersecurity |
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Part III |
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Item 17. |
Financial Statements |
N/A |
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Item 18. |
Financial Statements |
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Item 19. |
Exhibits |
DEC at a Glance
Our Assets
Our assets primarily consist of long-life, low-decline natural gas wells and gathering systems located within the Appalachian
Basin and Central Region of the U.S., providing opportunistic synergies in our operations. Our headquarters are located in
Birmingham, Alabama with operational and field offices located throughout the states in which we operate.

KEY
l Upstream assets
l Midstream assets
l States in which we operate
APPALACHIA ASSETS
CENTRAL ASSETS

Key Facts
PRODUCTION MIX
86%
natural gas
12%
NGLs
2%
oil
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PRODUCTION
256,378
natural gas (MMcf)
5,832
NGLs (MBbls)
1,377
oil (MBbls)
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PV-10 VALUE OF RESERVES
$2.1
billion(a)
3,849,946
MMcfe
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MIDSTREAM SYSTEM
~17,700
miles
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SCOPE 1 METHANE
EMISSIONS INTENSITY
0.8
MT CO2e/MMcfe
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NO LEAK RATE ON
SURVEYED WELLS
~98%
Group-wide
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AERIALLY SURVEYED
MIDSTREAM MILES
~10,000
miles
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REPORTABLE SPILL
INTENSITY
0.08
oil & water per MBbl
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NET
INCOME
$760
million
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TOTAL
REVENUE
$868
million
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ADJUSTED EBITDA
MARGIN(b)
52%
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ADJUSTED
EBITDA(b)
$543
million
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(a)Based on SEC pricing.
(b)Please refer to the APMs section in Additional Information within this Annual Report & Form 20-F for information on how these metrics
are calculated and reconciled to IFRS measures.
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Strategic
Report
Chairman’s Statement

On behalf of the Board of Directors, I am
pleased to share our financial and operational
results that reflect the hard work, dedication,
and focus of the entire Diversified team. Their
consistent execution of our strategy and
management initiatives has driven another year
of strong environmental, financial, and
operational performance.
Throughout 2023, we continued to focus on
cash flow generation, capital discipline, and
balance sheet management. This, together with
our resilient business model, means we have
been able to deliver strong results which have
benefited all stakeholders.
In addition, we are proud of the part we are
playing in responsibly providing the energy
needed for our communities and country, as
well as meeting growing demand beyond
the U.S.
Since 2017, Diversified’s demonstrated track
record has delivered more than $800 million in
returns to the Group’s stockholders including
approximately $700 million in cash dividends
paid and declared, along with approximately
$110 million in share repurchases.
The Board’s dedication to shareholder returns
remains an absolute priority. We continuously
refine the capital allocation framework in order
to balance debt reduction, sustainable fixed
dividends, strategic share repurchases and
accretive acquisitions. We are proposing a final
fourth quarter 2023 dividend of $0.29 which
allows us to focus our cash flows on what we
believe are the highest and best uses of capital.
We are confident that this new level will be
sustainable, and will also allow for continued
debt reduction, more flexibility for alternative
capital returns, and for funding future growth.
We believe that our share price has been
significantly undervalued for some while and
has been affected by the structural de-
equitization of the UK share market. We have,
therefore, also authorized a share buyback
program, which we believe will be an effective
use of our capital and will further increase total
shareholder returns.
Part of our business model and strategy
revolves around the continued addition of
growth opportunities. We identified a listing on
the New York Stock Exchange, in addition to
the London listing, as an opportunity that could
help to add significant value and were pleased
to deliver on that key milestone this year. We
view the NYSE listing as a great opportunity to
expand access to U.S. investors and improve
trading liquidity. We continue to evaluate
opportunities to grow and to increasingly
make Diversified the “Right Company at the
Right Time.”
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Another important part of our focused strategy
is to create value through sustainability and
stewardship. Over the past year, we have made
significant progress with our methane emissions
program, reducing emissions by over 33% from
2022 and achieving our 2030 goal meaningfully
ahead of schedule. We are proud that we
received recognition from the United Nations’
Oil & Gas Methane Partnership 2.0 (OGMP),
being awarded the Gold rating for the second
year. Our initiatives related to methane emission
reductions are of paramount importance, and it
gives us great confidence to see this recognized
by international bodies.
Operationally, we conducted over 246,000 leak
detection surveys using industry-leading and
proven detection equipment, and attaining a
zero emissions rate of approximately 98%,
proving the positive impact of our actions to
eliminate methane leaks. Next LVL Energy, our
asset retirement business, has continued to
grow and contribute significantly to safe and
efficient well retirements, retiring a total of 404
wells. This achievement included retiring a total
of 222 Diversified wells in 2023, significantly
exceeding state agreements. Additionally, our
partnership with states on their orphan well
programs resulted in 148 retired wells. We are
immensely proud of the material investments
we have made to lower our methane intensity,
and to safely retire wells, and we remain
focused on delivering continuous improvement.
The Board and its Committees continue to
operate effectively and are active in both
supporting and challenging strategic
discussions. There is an exceptional depth of
knowledge and diversity of thinking. We again
conducted a Board Performance Review during
2023 and will continue to ensure that we
comply with all governance guidelines.
As we look ahead to 2024 and beyond, I would
like to recognize the quality of the team we
have at Diversified, across the entire Group. I am
very grateful for their work and look forward to
future successes as a company in the years to
come. In particular, I would like to thank the
Executive Team, led by Rusty Hutson, Jr., who
navigated the team through a year that has
seen its share of broader challenges, notably an
unfavorable commodity price environment. I
also wish to express gratitude to our
shareholders, lenders, and other stakeholders
for their trust in our commitment to deliver
long-term sustainable value and their support
whilst we provide essential energy security and
continue to care for our communities.
![]()
David E. Johnson
Chairman of the Board
March 19, 2024
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“
Together with our
resilient business
model, we have been
able to deliver strong
results which have
benefited all
stakeholders.

Chief Executive’s Statement
The fundamental need for natural gas is well-
cemented in our domestic and global energy
outlooks. Natural gas is the essential fuel to
tackling global challenges – from enhancing energy
security of the United States and allies around the
world to addressing the universally shared need for
reliable, affordable, and sustainable power, natural
gas demand remains strong.
It’s against this backdrop of rising global energy
demand, consolidation in the U.S. energy markets,
and enhanced expectations for sustainably
produced energy that the case for Diversified’s
stewardship business model sharpens. Thanks to
our approach – focused on acquiring, improving,
and retiring existing, long-life U.S. energy assets
and honed through two decades of field
experience – Diversified is the “Right Company at
the Right Time” to responsibly manage existing
domestic natural gas and oil production in a
manner that’s consistent with environmental
stewardship and a lower-carbon energy future.
We continue to aggressively pursue this mission
each and every day, and 2023 was no different.
From closing the Tanos II acquisition – which
increased our footprint in the Central Region and
aligned with our stewardship and sustainability
commitments – to ending the year with dual-listing
on the New York Stock Exchange, 2023 was a year
focused on execution against our core business
objectives.
Through our focused commitment to responsible
asset management, we continue to drive methane
intensities downward, while returning wells to
production and gaining operational efficiencies.
Compared to a 2020 baseline, upstream methane
intensity has fallen over 50%, achieving our 2030
goal meaningfully ahead of schedule, and we are
continuing to take aggressive steps to optimize
environmental performance across our operating
areas. By viewing asset retirement as a business
opportunity, Diversified’s Next LVL Energy
subsidiary is the largest well retirement company in
Appalachia. Our focus on asset retirement stands
out, with our dedicated teams responsibly retiring
404 wells in 2023 alone, as no other company is
addressing state orphaned and end-of-life wells
head-on like we are.
This focus on sustainability principles has been
validated on the domestic and global stage, with
sustained Gold standard designations from the
United Nation’s Oil and Gas Methane Partnership
2.0 (second year), attainment of the second-
highest MSCI ESG “AA” rating, and multiple
sustainability awards, to name a few. Last year’s
sustainability report detailing our proactive
approach took home the ESG Report of the Year
by the international ESG Awards 2023 for speaking
to “both head and heart,” while also receiving the
top category nomination from IR Magazine. I am
proud to see the hard work of our employees
recognized as industry leaders time and again.
We also continue to expand Diversified’s
community-giving culture in the communities
where we live and work, and we’re privileged to
strengthen our corporate commitments to
employees. We fully recognize none of this
progress would be possible without our 1,600+
diligent team who work every day to ensure
families across the United States have safe, clean,
and reliable energy resources.
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In the year ahead, we are taking a renewed focus
on the values on which Diversified was founded:
investing in strategic, aligned acquisitions that
scale our model and deliver greater operational
efficiencies, taking proactive steps to ensure the
sustainability of assets, keeping costs low and de-
leveraging the balance sheet – all while returning
value to shareholders.
Diversified has set in motion its “Focus Five” in
order to demonstrate meaningful expansion of
free cash flow generation while growing the
company in a disciplined manner. That plan
consists of the following core objectives:
—Optimized cash flow generation
—Cost structure optimization
—Financial and operational flexibility
—Sustainability innovation
—Scale through accretive growth
I believe these principles will help differentiate the
Company among its peers in unlocking corporate
value throughout 2024 and into the future.
The Company has undertaken a reassessment of
its capital allocation strategy to weigh the
intrinsic value of the current share price level
against the historical practice of returning capital
through dividends. The Board and executive
management team have jointly evaluated a
number of potential scenarios to align the
dividend level with expected future capital
allocation needs, peer trends, current commodity
prices and current equity market dynamics.
The result of this assessment is the Board’s
realignment of capital allocation and is designed
to best position the Company to create long-term
shareholder value through the proper
combination of:
—Systematic debt reduction
—Fixed per-share dividend
—Strategic share repurchases
—Accretive strategic acquisitions
We are proud to be part of the solution to the
broader challenge of existing energy
infrastructure and to do our part in driving our
country’s energy, climate, and economic security
– and we couldn’t do it without our OneDEC team.
![]() Robert R. (“Rusty”) Hutson, Jr.
Chief Executive Officer
March 19, 2024
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Diversified is the Right
Company at the Right
Time to responsibly
manage existing
domestic natural gas
and oil production in a
manner that’s
consistent with
environmental
stewardship and a
lower-carbon energy
future.
“
A Differentiated Business Model
1 |
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ACQUIRE |
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We maintain a disciplined approach to evaluating
opportunities to ensure that we only pursue those
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.
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2 |
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OPTIMIZE |
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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 our emissions.
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3 |
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PRODUCE |
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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 both
environmental and financial best interests.
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4 |
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TRANSPORT |
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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.
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5 |
![]() |
RETIRE |
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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. During 2022, we made
investments that allowed us to meaningfully
expand our asset retirement capabilities through a
series of acquisitions that we believe have provided
us with the operational capacity to be a leader in
asset retirement.
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DAILY OPERATING PRIORITIES
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Safety |
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No compromises. Ensuring the care and well-being of
our employees, our families, our partners and
communities is our top priority.
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![]() |
Production |
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Every unit counts. Ensuring that every unit we
safely produce provides affordable and reliable
energy to our communities and generates value for
our shareholders.
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Efficiency |
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Every dollar counts. Ensuring every dollar we spend
protects our employees and communities and grows
the investment of our shareholders.
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Enjoyment |
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Have fun delivering great results. Ensuring our
company is an attractive place to work,
encouraging innovation and celebrating our
employees’ accomplishments.
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STRATEGY |
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Acquire long-life stable assets
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![]() |
Operate our assets in a safe, efficient and
responsible manner
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![]() |
Generate reliable free cash flow
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![]() |
Retire assets safely and responsibly
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Priorities |
Strategy |
Sustainability |
Risk |
see page 7 |
see page 11 |
see page 33 |
see page 79 |
Our business model and the corporate culture we cultivate is unique among the natural
gas and oil industry in that we do not engage in 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, reduce emissions and generate consistent free cash flow before safely and
permanently retiring those assets at the end of their useful lives.
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![]() |
Execute Commodity Hedges
to Secure Healthy Margins
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Protect our ability to provide
durable shareholder returns
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Generate Reliable
Free Cash Flow
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Maintain adjusted EBITDA
margins, low capital intensity
and low LOE per unit
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Provide Durable
Shareholder Returns
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Create value for our
shareholders via debt
reduction, fixed dividends,
strategic share repurchases
and accretive acquisitions
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Maintain A Healthy
Balance Sheet
|
Maintain low leverage, ample
liquidity and access to
additional capital for
opportunistic growth
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Geographic
Operating
Areas
U.S. NATURAL GAS PLAYS
Our Operating Areas
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 currently operate within Texas, Louisiana and Oklahoma in the following plays:
Haynesville, Bossier and Cotton Valley
While in a relatively similar geographic region of East Texas
and West Louisiana, the Bossier shale lies directly above the
Haynesville shale but beneath the Cotton Valley sandstones.
A key benefit to operations in this region is the ability to
access consistent natural gas pipeline transportation from
the wellhead to the Gulf Coast, an area of strong demand
and advantageous pricing. This access to strong pricing and
takeaway capacity has made it a desirable area for
developers and one of rapid growth, particularly in the
Haynesville, with Cotton Valley and Bossier viewed as more
mature. As the wells in this region continue to mature and
decline rates continue to shallow and become more
predictable, it will be a fertile ground for our
continued expansion.
Barnett
An original shale play in the U.S., the Barnett shale is located
in North Texas and is a geological formation rich in natural
gas. The Barnett is home to some of the first horizontal
drilling and hydraulic stimulation that occurred in the early
1990s, unlocking the U.S. shale revolution. For a time during
the early 2000s, the Barnett was the largest natural gas
producing shale play in the U.S. Though drilling in this area
has largely subsided, the maturity of the play with its now
vast portfolio of low decline rate wells makes this area
available for opportunities to complement our existing
mature portfolio through future acquisitions.
Mid Continent
The Mid Continent region stretches across Oklahoma, Kansas
and the Texas panhandle and is generally understood to
reference the Fayetteville, Woodford, Granite Wash,
Springer, Sycamore and Cana Woodford shale natural gas
plays along with numerous other conventional and
unconventional natural gas reservoirs in the Arkoma Basin,
Ardmore Basin and Anadarko Basin. This mature and
developed region has undergone a redevelopment
renaissance over the last several years through the use of
hydraulic stimulation and horizontal drilling. It is an asset rich
environment with an abundance of mature wells and
developed transportation infrastructure making it a valuable
complement to our current portfolio.


U.S. DRY SHALE GAS PRODUCTION
billion cubic feet per day
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Sources: Graph by the U.S. Energy Information Administration (“EIA”) based on state administrative
data collected by Enverus. Data are through December 2023. The EIA updated the factors it uses to
convert gross natural gas to dry natural gas based on the latest data. The update affected historical
production volumes from some formations. State abbreviations indicate primary state(s).
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Current play - oldest play |
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Current play - intermedia depth/age play |
|
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Current play - shallowest/youngest play |
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Prospective play |
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Basin |
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APPALACHIA
The Appalachian Basin spans
Pennsylvania, Virginia, West Virginia,
Kentucky, Tennessee and Ohio and
consists of two productive unconventional
shale formations, the Marcellus Shale and
the slightly deeper Utica Shale. Together
they accounted for 38% of all U.S. dry
natural gas production in 2023. Diversified
began operating here in 2001, more than
twenty years ago, firmly establishing the
Group as a consolidator of assets and
exceptional operator. Appalachia is home
to many mature, low-decline conventional
and unconventional wells matching our
target asset profile.
Strategy
Our rapid growth and ability
to generate consistent
shareholder return stems from
our unique business model
and successful execution of
straight-forward, low-risk,
disciplined and proven
operating techniques.
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ACQUIRE
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.
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OPERATE
Operate our assets in a safe, efficient
and responsible manner
Our operational strategy and success is
closely aligned with the culture we
created through our four guiding
operational priorities: Safety,
Production, Efficiency and Enjoyment.
These four daily priorities are brought
to life as part of our SAM program
which our team lives and breathes
every day as they work to safely deliver
clean, affordable and reliable energy.
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GENERATE
Generate reliable free cash flow
Our unique business model, coupled
with the successful execution of the
Acquire and Operate pillars of our
corporate strategy, naturally lends itself
to generating free cash flow. 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.
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RETIRE
Retire assets safely and responsibly
At the appropriate time, through our
safe and systematic asset retirement
program, we safely and permanently
retire wells and responsibly restore the
well sites as close as possible to their
original and natural condition. Our asset
retirement program reflects our solid
commitment to a healthy environment,
the surrounding community and its
citizens and state regulatory authorities.
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Acquire Long-Life
Stable Assets
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ONE DEC
Foster a culture of operational excellence
through the integration of People, Process
and Systems
|
2023 ACHIEVEMENTS
—Completed the Tanos II Central Region acquisition for
$262 million, contributing approximately 69 MMcfepd
to 2023 production.
—Realized first full year of operations for Next
LVL Energy.
— Utilized environmental and climate screening of
![]() target assets to inform acquisition considerations.
TARGETS FOR 2024
— We will persist in our disciplined approach to
![]() acquisitions, focusing on producing assets that align
with our stringent investment criteria.
—We will maintain liquidity discipline, ensuring we
remain well-positioned in the market to seize
opportunities as they arise.
—Our growth strategy will continue to emphasize
complementary and synergistic expansion in the
Appalachian and Central regions. We will foster
strong relationships with development-oriented
producers in our operating areas.
—We will actively screen and execute on new basin
opportunities, staying agile and responsive to
emerging prospects.
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ACQUIRE
Target low-decline, producing assets that complement our
returns-focused strategy
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INTEGRATE
Onboard employees, integrate processes and systems to
drive efficiencies and standardization
|
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OPTIMIZE
Empower retained personnel to apply our SAM techniques on
acquired assets
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CONSOLIDATE
Enhance operating, marketing relationships with
increasing scale
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PRINCIPAL RISKS
—Corporate Strategy and Acquisition Risk
—Financial Strength and Flexibility Risk
—Climate Risk
|
KEY PERFORMANCE INDICATORS
—Maintain net debt-to-adjusted EBITDA at or
below 2.5x
—Emissions intensity
—Adjusted operating cost per Mcfe
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Indicates sustainability achievements and targets.

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Operate our Assets in a Safe,
Efficient and Responsible Manner
|
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GOAL
Improve safety, optimize production, increase expense
efficiency and improve emissions profile
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2023 ACHIEVEMENTS
—Annual production of 299,632 MMcfe.
—Adjusted EBITDA margin of 52%.
— Achieved 2023 goal to conduct fugitive emission
![]() surveys on 100% of Central Region upstream assets.
— Collectively, conducted ~246,000 voluntary
![]() fugitive emission detection surveys within our
upstream portfolio, confirming an average ~98% no-
leak rate on surveyed sites and allowing us to take
meaningful steps towards reducing our
emissions profile.
— Completed aerial light detection and ranging
![]()
(“LiDAR”) surveys covering~10,000 miles of
midstream systems which also included ~9,000 sites
(wells, compressor stations and other facilities).
— Zero non-compliance issues cited after
![]()
participating in 16 state and federal regulatory agency
audits of our operational assets and compliance
programs which were completed as part of routine
monitoring programs.
— Our safety-no compromises culture contributed to
![]() our preventable motor vehicle accident rate (“MVA”)
declining 20% year-over-year to 0.55 (accidents to
million miles driven).
— Expanding continuous remote monitoring
![]() capabilities through our Gas Control and Integrated
Operations Centers promotes safety and efficiency
through enhanced visibility of operations.
TARGETS FOR 2024
—We will continue to execute our guiding priorities:
Safety, Production, Efficiency, and Enjoyment.
— Our commitment to responsible stewardship
![]() remains unwavering. We will intensely focus on
continuous improvement across all
sustainability aspects, aiming to exceed our
stakeholders’ expectations.
—We will maintain our focus on the SAM program to
uphold margins, offset natural declines, and capitalize
on expense efficiency opportunities.
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PROCESS
“Data + Human Interaction” coupled with production
technology systems, drive activities, process enhancements,
refine best practice techniques
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RESULT
Practical, profit-focused SOLUTIONS developed by our
experienced teams
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ONGOING INITIATIVES |
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PRINCIPAL RISKS
—Corporate Strategy and Acquisition Risk
—Climate Risk
—Cybersecurity Risk
—Health and Safety Risk
—Regulatory and Political Risk
—Financial Strength and Flexibility Risk
|
KEY PERFORMANCE INDICATORS
—Safety Performance
—Emissions intensity
—Consistent adjusted EBITDA margin
—Adjusted operating cost per Mcfe
—Net cash provided by operating activities
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Indicates sustainability achievements and targets.

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Generate Reliable
Free Cash Flow
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PRUDENT ALLOCATION OF
CASH FLOW
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2023 ACHIEVEMENTS
—Raised our weighted average hedge floor on natural
gas production to $3.87 per Mcf at December 31,
2023 from $3.63 per Mcf at December 31, 2022.
—Repaid $277 million in asset backed securitizations
illustrating the substantial cash flow generated by our
assets.
—Repurchased 646,762 shares through our Share
Buyback Program, representing $11 million in
shareholder value above and beyond the $168 million
in dividend distributions.
— Delivered on our sustainability investment
![]() commitment to convert additional natural gas
pneumatic devices to compressed air, converting 58
well pads exceeding our goal to convert 30 well pads.
We also had significant success with our upstream
emissions detection surveys, completed year two of
aerial surveillance activities for our midstream assets,
and contributed to tree planting and land
preservation initiatives primarily with West Virginia
State University.
TARGETS FOR 2024
—We will maintain our effective hedging strategy to
insulate cash flows. Additionally, we’ll make the most
of accretive market opportunities to raise our hedge
book floor.
— Our focus remains on securing low-cost
![]() sustainability-linked financing. This will support our
acquisitive growth while ensuring low leverage and
ample liquidity.
— We will continue to invest in sustainability
![]() initiatives, reinforcing our commitment to responsible
practices.
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Allocating Cash Flow |
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Debt Repayment
Reduce outstanding debt & create liquidity
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Reinvestment & Growth
Reinvest for organic growth & reduce
reliance on equity and debt markets
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Sustainability
Invest in broad spectrum of
sustainability initiatives
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Dividend Distributions
Pay sustainable dividends
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Share Buyback Program
Reduce outstanding shares & increase
shareholder value
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PRINCIPAL RISKS
—Corporate Strategy and Acquisition Risk
—Commodity Price Volatility Risk
—Financial Strength and Flexibility Risk
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KEY PERFORMANCE INDICATORS
—Maintain net debt-to-adjusted EBITDA at or
below 2.5x
—Consistent adjusted EBITDA margin
—Emissions intensity
—Adjusted operating cost per Mcfe
—Net cash provided by operating activities
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Indicates sustainability achievements and targets.

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Retire Assets Safely and
Responsibly and Restore the
Environment to its Natural State
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STEP 1
DEACTIVATION
Remove product from
production equipment.
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2023 ACHIEVEMENTS
— We expanded our asset retirement operations from 15 to
![]()
17 rigs.
— We successfully retired 222 DEC wells, including 21 Central
![]() Region wells. This achievement surpasses our goal of retiring
200 wells by 2023 and also exceeds our collective state
commitments in Appalachia to retire 80 wells in our primary
states of operation.
— We further retired 182 third-party wells, including 148
![]()
state and federal orphan wells and 34 for other third party
operators, bringing the total wells retired in Appalachia by
the Next LVL team to 383 wells.
— We permanently retired 18 wells on lands managed by the
![]() Pennsylvania Game Commission. We then restored well sites
to their natural condition by planting native trees to the
region. This dual effort not only reduced noise pollution but
also contributed to the restoration of bird habitats.
TARGETS FOR 2024
— Continue to safely retire wells and aim to exceed state
![]() asset retirement programme commitments by identifying
and retiring wells at the end of their productive lives.
— Continue to optimize the vertical integration benefits
![]() we can realize with our expanded internal asset
retirement capacity.
— Continue constructive and collaborative dialogue with
![]() states and industry associations to innovate and ensure best
practices in the well retirement arena.
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STEP 2
WELL DECOMMISSIONING
Permanently plug and
cap wellbore.
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STEP 3
SITE DECOMMISSIONING
Remove and salvage/dispose
of equipment.
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STEP 4
RECLAMATION
Redistribute soil and revegetate for
return to original state.
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PRINCIPAL RISKS
—Health and Safety Risk
—Regulatory and Political Risk
—Climate Risk
—Financial Strength and Flexibility Risk
|
KEY PERFORMANCE INDICATORS
—Net cash provided by operating activities
—Meet or exceed state asset retirement goals
—Emissions intensity
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Indicates sustainability achievements and targets.

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.
Please refer to the APMs section in Additional Information within this Annual Report & Form 20-F for information on how
these metrics are calculated and reconciled to IFRS measures.
MAINTAIN NET DEBT-TO-ADJUSTED EBITDA AT OR
BELOW 2.5x
During 2023 our leverage ratio remained consistent at 2.3x and within our
preferred goal of 2.0x to 2.5x.
LINK TO STRATEGY
—Acquire long-life stable assets
—Generate reliable free cash flow
(a)2023 is pro forma for the Tanos II acquisition completed in March 2023. 2022 is pro
forma for the East Texas Assets and ConocoPhillips acquisitions. 2021 is pro forma for
the Indigo, Blackbeard, Tanos and Tapstone acquisitions as well as Oaktree’s
subsequent participation in the Indigo transaction.
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NET DEBT-TO-PRO FORMA
ADJUSTED EBITDA(a)
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CONSISTENT ADJUSTED EBITDA MARGIN
Total revenue, inclusive of settled hedges for 2023 was $1,046 million, an
increase of 2% compared to 2022. Adjusted EBITDA for 2023 was $543 million,
an increase of 8% compared to 2022.
LINK TO STRATEGY
—Generate reliable free cash flow
—Operate our assets in a safe, efficient and responsible manner
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ADJUSTED EBITDA MARGIN
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ADJUSTED OPERATING COST PER MCFE
Adjusted operating cost per Mcfe for 2023 was $1.76, a decrease of 1%
compared with 2022.
LINK TO STRATEGY
—Operate our assets in a safe, efficient and responsible manner
—Generate reliable free cash flow
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ADJUSTED OPERATING COST
PER MCFE
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NET CASH PROVIDED BY OPERATING ACTIVITIES
Net cash provided by operating activities for 2023 was $410 million an increase
of 6% compared with 2022.
LINK TO STRATEGY
—Operate our assets in a safe, efficient and responsible manner
—Generate reliable free cash flow
—Retire assets safely and responsibly and restore the environment to its
natural state
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NET CASH PROVIDED BY
OPERATING ACTIVITIES
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EMISSIONS INTENSITY
Significant improvement in our Scope 1 methane emissions intensity is primarily
a result of our team’s steadfast focus on leak detection and mitigation across
our portfolio, including meeting current year objectives to survey 100% of
Central Region upstream assets while continuing like surveys in Appalachia to
maintain no leak rates. Conversion of natural gas-driven pneumatic devices to
compressed air also supported this tremendous achievement of a 33% year-
over-year reduction.
LINK TO STRATEGY
—Acquire long-life stable assets
—Operate our assets in a safe, efficient and responsible manner
—Generate reliable free cash flow
—Retire assets safely and responsibly and restore the environment to its
natural state
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METHANE EMISSIONS INTENSITY
(MT CO2e/MMcfe)
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MEET OR EXCEED STATE ASSET RETIREMENT GOALS
During 2023, we meaningfully expanded our asset retirement operations and
permanently retired 222 wells, inclusive of our Central Regions operations. This
achievement allowed us to more than double our Appalachian state
requirements of 80 wells and exceed our goal to retire 200 wells by the end of
2023. Additionally, with our Next LVL Energy assets, we plugged 182 wells for
third parties, including other operators and for the states of Ohio, Pennsylvania
and West Virginia.
LINK TO STRATEGY
—Retire assets safely and responsibly and restore the environment to its
natural state
(a)DEC wells inclusive of 14 and 21 Central Region wells retired during 2022 and
2023, respectively.
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ACTUAL WELLS RETIRED(a)
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SAFETY PERFORMANCE
Our 2023 MVA rate is 0.55 incidents per million miles driven, a 20%
improvement from 2022. Though five of nine operating areas incurred zero
incidents in 2023, including two states who have not recorded an incident in
more than four years, TRIR increased to 1.28, primarily driven by an increase in
reported incidents in the remaining areas, in part a function of short-service
employees with less than one year experience under the Group’s safety
expectations. A new Safety Strategy Committee has been created to identify
and advance specific areas for improvement and accountability.
LINK TO STRATEGY
—Operate our assets in a safe, efficient and responsible manner
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MOTOR VEHICLE ACCIDENTS &
TOTAL RECORDABLE
INCIDENT RATE
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Our Business
HISTORY AND DEVELOPMENT OF THE GROUP
The Group, formerly Diversified Gas & Oil PLC, is an
independent energy company engaged in the production,
transportation and marketing of natural gas as well as oil
from its complementary onshore upstream and midstream
assets, primarily located within the Appalachian and Central
Regions of the United States. Our Appalachia assets consist
primarily of producing wells in conventional reservoirs and
the Marcellus and Utica shales, within Pennsylvania, Ohio,
Virginia, West Virginia, Kentucky, and Tennessee, while our
Central Region, located in Oklahoma, Louisiana, and
portions of Texas, includes producing wells in multiple
producing formations, including the Bossier, Haynesville
Shale and Barnett Shale Plays, as well as the Cotton Valley
and the Mid-Continent producing areas. The Group was
incorporated in 2014 in the United Kingdom, and our
predecessor business was founded in 2001 by our Chief
Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., with
an initial focus on primarily natural gas and also oil
production in West Virginia. In recent years, we have grown
rapidly by capitalizing on opportunities to acquire and
enhance producing assets and leveraging the operating
efficiencies that result from economies of scale. Since 2017,
and through December 31, 2023, we have completed 24
acquisitions for a combined purchase price of
approximately $2.7 billion. We had average daily net
production of 821 MMcfepd and 811 MMcfepd for the years
ended December 31, 2023 and December 31,
2022, respectively.
We have consistently driven our operations towards
sustainability and efficiency throughout our history, but we
believe we are also at the forefront of U.S. natural gas and
oil producers in our commitment to sustainability goals.
While the global energy economy is reliant on natural gas
as an energy source, we believe it is imperative that natural
gas wells and pipelines be operated by responsible owners
with a strong commitment to the environment, and we
believe our operational track record demonstrates that
responsibility and stewardship. Given our operational focus
on efficient, environmentally sound natural gas production,
we believe we are ideally positioned to help serve current
energy demands and play a key role in the clean
energy transition.
Other Information
We were incorporated as a public limited company with the
legal name Diversified Gas & Oil PLC under the laws of the
United Kingdom on July 31, 2014 with the company number
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.” As of December 31, 2023,
the principal trading market for the Group’s ordinary shares
was the LSE.
Our principal executive offices are located at 1600
Corporate Drive, Birmingham, Alabama 35242, and our
telephone number at that location is +1 205 408 0909. Our
website address is www.div.energy. The information
contained on, or that can be accessed from, our website
does not form part of this Annual Report & Form 20-F. We
have included our website address solely as an inactive
textual reference.

Safety
No compromises
Ensuring the care and wellbeing of our employees, our families and our communities
is our top priority
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Production
Every unit counts
Ensuring every unit we safely produce provides affordable, reliable energy to our
communities and generates value for our shareholders
|
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Efficiency
Every dollar counts
Ensuring every dollar we spend protects our employees, our communities and the
investment of our shareholders
|
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Enjoyment
Have fun delivering great results
Ensuring our company is a great place to work, encouraging innovation and
celebrating our employees’ accomplishments
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BUSINESS OVERVIEW
Our strategy is primarily to acquire and manage natural gas
and oil properties while leveraging our associated
midstream assets to maximize cash flows. We seek to
improve the performance and operations of our acquired
assets through our deployment of rigorous field
management programs and/or refreshing infrastructure.
Through operational efficiencies, we demonstrate our
ability to maximize value by enhancing production while
lowering costs and improving well productivity. We adhere
to stringent operating standards, with a strong focus on
health, safety and the environment to ensure the safety of
our employees and the local communities in which we
operate. We believe that acting as a careful steward of our
assets will improve revenue and margins through captured
natural gas emissions while reducing operating costs, which
benefits our profitability. This focus on operational
excellence, including the aim of reducing natural gas
emissions, also benefits the environment and communities
in which we operate.
OUR BUSINESS STRATEGY
—Optimization of long-life, low-decline assets to enhance
margins and improve cash flow
—Generate consistent shareholder returns through vertical
integration, strategic hedging and cost optimization
—Disciplined growth through accretive acquisitions of
producing assets
—Maintain a strong balance sheet with ability to
opportunistically access capital markets
—Operate assets in a safe, efficient manner with what we
believe are industry-leading sustainability initiatives
OUR STRENGTHS
—Low-risk and low-cost portfolio of assets
—Long-life and low-decline production
—High margin assets benefiting from significant scale and
owned midstream and asset retirement infrastructure
and internal product marketing team
—Highly experienced management and operational team
—Track record of successful consolidation and integration
of acquired assets
OUTLOOK
Looking forward, we will continue to prudently manage our
long-life, low-decline asset portfolio and the consistent
cashflows they produce. We plan to maintain our hedging
strategy to protect cash flow. We will seek to retain our
strategic advantages in purposeful growth through a
disciplined acquisition strategy that continues to secure
low-cost financing that supports acquisitive growth while
maintaining low leverage and ample liquidity. In addition,
we intend to remain proactive in our sustainability
endeavors by seeking to secure future capital allocation for
sustainability initiatives.

RESERVE DATA
Summary of Reserves
The following table presents our estimated net proved reserves, Standardized Measure and PV-10 as of December 31, 2023,
using SEC pricing. Standardized Measure has been presented inclusive and exclusive of taxes and is based on the proved
reserve report as of such date by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineering firm.
A copy of the proved reserve report is included as an exhibit to the Annual Report & Form 20-F. Refer to the Preparation of
Reserve Estimates and Estimation of Proved Reserves sections within this Annual Report & Form 20-F for a definition of
proved reserves and the technologies and economic data used in their estimation.
December 31, 2023 |
|
SEC Pricing(a)
|
|
Proved developed reserves |
|
Natural gas (MMcf) |
3,184,499 |
NGLs (MBbls) |
94,391 |
Oil (MBbls) |
12,380 |
Total proved developed reserves (MMcfe) |
3,825,125 |
Proved undeveloped reserves |
|
Natural gas (MMcf) |
15,545 |
NGLs (MBbls) |
1,310 |
Oil (MBbls) |
236 |
Total proved undeveloped reserves (MMcfe) |
24,821 |
Total proved reserves |
|
Natural gas (MMcf) |
3,200,044 |
NGLs (MBbls) |
95,701 |
Oil (MBbls) |
12,616 |
Total proved reserves (MMcfe) |
3,849,946 |
Prices used |
|
Natural gas (Mmbtu) |
$2.64 |
Oil and NGLs (Bbls) |
$78.21 |
PV-10 (thousands) |
|
Pre-tax (Non-GAAP)(b)
|
$2,139,690 |
PV of Taxes |
(394,154) |
Standardized Measure |
$1,745,536 |
Percent of estimated total proved reserves that are: |
|
Natural gas |
83% |
Proved developed |
99% |
Proved undeveloped |
1% |
(a)Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with
SEC guidance. For natural gas volumes, the average Henry Hub spot price of $2.64 per MMBtu as of December 31, 2023 was adjusted for
gravity, quality, local conditions, gathering and transportation fees, and distance from market. For NGLs and oil volumes, the average WTI
price of $78.21 per Bbl as of December 31, 2023 was similarly adjusted for gravity, quality, local conditions, gathering and transportation fees,
and distance from market. All prices are held constant throughout the lives of the properties.
(b)The PV-10 of our proved reserves as of December 31, 2023 was prepared without giving effect 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.
Proved Reserves
As of December 31, 2023, our estimated proved reserves totaled 3,849,946 MMcfe, a decrease of 24% from the prior year-end
with a Standardized Measure of $1.7 billion. Natural gas constituted approximately 83% of our total estimated proved reserves
and 83% of our total estimated proved developed reserves. The following table provides a summary of the changes in our
proved reserves during the years ended December 31, 2023, 2022 and 2021.
Total (MMcfe) |
|
Total proved reserves as of December 31, 2020 |
3,250,588 |
Extensions and discoveries |
— |
Revisions to previous estimates |
541,509 |
Purchase of reserves in place |
1,260,514 |
Sales of reserves in place |
(164,039) |
Production |
(259,543) |
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
During 2023, 1,012 MMcfe were adjusted due to well assignments recorded in the accounting actuals.
During 2022, we elected to participate in select development activities on a non-operated basis generating 13,326 MMcfe
in reserves.
During 2021, no reserves were added from extension or discovery activities.
Revisions to Previous Estimates
During 2023, we recorded 659,379 MMcfe in revisions to previous estimates. The downward revisions were primarily
associated with changes in the trailing 12-month average realized Henry Hub first day spot price, which decreased
approximately 58% as compared to the December 31, 2022 along with a 17% decrease in the 12 month average WTI first day
spot price. These factors primarily drove a net downward revision that impacted well economics and well life.
During 2022, we recorded 379,812 MMcfe in revisions to previous estimates. These positive performance revisions were
primarily associated with changes in the trailing 12-month average realized Henry Hub spot price, which increased
approximately 77% as compared to the December 31, 2021 Henry Hub spot price due to the war between Russia and Ukraine,
as well as other geopolitical factors. These factors primarily drove a net upward revision of 386,064 MMcfe due to changes in
pricing that impacted well economics. These increases were offset by a 6,252 MMcfe downward revision for changes in timing.
During 2021, 541,509 MMcfe in revisions to previous estimates were primarily associated with changes in the 12-month average
realized Henry Hub spot price, which increased approximately 81% as compared to December 31, 2020.
Purchase of Reserves in Place
During 2023, 126,803 MMcfe of purchases of reserves in place were associated with the Tanos II acquisition. Refer to Note 5 in
the Notes to the Group Financial Statements for additional information about these acquisitions.
During 2022, 331,043 MMcfe of purchases of reserves in place were associated with the East Texas and ConocoPhillips
acquisitions. Refer to Note 5 in the Notes to the Group Financial Statements for additional information about
these acquisitions.
During 2021, 1,260,514 MMcfe of purchases of reserves in place were associated with the Indigo, Tanos, Blackbeard and
Tapstone acquisitions. Refer to Note 5 in the Notes to the Group Financial Statements for additional information about these
acquisitions.
Sales of Reserves in Place
During 2023, 369,035 MMcfe of sales of reserves in place were primarily associated with the divestitures of non-core assets.
During 2022, 6,912 MMcfe of sales of reserves in place were primarily associated with the divestitures of non-core assets.
During 2021, 164,039 MMcfe of sales of reserves in place were primarily associated with the divestment of assets to Oaktree for
their subsequent participation in the Indigo acquisition. Refer to Note 5 in the Notes to the Group Financial Statements for
additional information about divestitures.
Proved Undeveloped Reserves
We aim to obtain proved developed producing wells through acquisitions in accordance with our growth strategy rather than
through development activities. We accordingly contribute limited capital to development activities. From time to time, when
acquiring packages of wells, we will acquire certain locations that are in development by the acquiree at the time of the
acquisition or could be developed in the future. When economic, we will engage third parties to complete the existing
development activities, and such reserves are included below as proved undeveloped reserves. We do not have a
development program and, as a result, any additional undrilled locations that we hold cannot be classified as undeveloped
reserves in accordance with SEC rules unless a development plan is in place. As of December 31, 2023, we had no such
development plans and therefore have not classified these undrilled locations as proved undeveloped reserves.
The following table summarizes the changes in our estimated proved undeveloped reserves during the years ended
December 31, 2023, 2022 and 2021:
Total (MMcfe) |
|
Proved undeveloped reserves as of December 31, 2020 |
— |
Extensions and discoveries |
— |
Revisions to previous estimates |
— |
Purchase of reserves in place |
3,505 |
Sales of reserves in place |
— |
Converted to proved developed reserves |
— |
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
During 2023, no reserves were added from extension or discovery activities.
During 2022, we elected to participate in select development activities where third parties were engaged to complete the
development. Seven of these wells were in progress as of December 31, 2022, generating 8,832 MMcfe in proved
undeveloped reserves.
During 2021, no reserves were added from extension or discovery activities.
Purchase of Reserves in Place
During 2023, the 24,821 MMcfe of purchase of reserves in place were associated with the Tanos II acquisition and related to
four wells in progress that have been drilled and are awaiting hydraulic fracture stimulation.
During 2022, there were no purchases of proved undeveloped reserves in place.
During 2021, the 3,505 MMcfe of purchase of reserves in place were associated with the Tapstone Acquisition and related to
five wells that were under development as of December 31, 2021. We engaged third parties to complete this development
activity and during 2022 these were converted to proved developed reserves. Refer to Note 5 in the Notes to the Group
Financial Statements for additional information about acquisitions.
Sales of Reserves in Place
During 2023, the 8,832 in sales of reserves in place were divested as part of the sale of 80% of the equity interest in DP Lion
Equity Holdco LLC in December 2023. Refer to Note 5 in the Notes to the Group Financial Statements for additional
information.
During 2022, there were no sales of reserves in place.
During 2021, there were no sales of reserves in place.
Developed and Undeveloped Acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned
an interest as of December 31, 2023. Developed acres are acres spaced or assigned to productive wells and do not include
undrilled acreage held by production under the terms of the lease. Undeveloped acres are acres on which wells have not been
drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of
whether such acreage contains proved reserves. Approximately 99.9% of our acreage was held by production at
December 31, 2023.
Developed Acreage |
Undeveloped Acreage |
Total Acreage |
||||
Gross(a)
|
Net(b)
|
Gross(a)
|
Net(b)
|
Gross(a)
|
Net(b)
|
|
As of December 31, 2023
|
5,600,383 |
3,039,447 |
8,005,314 |
5,519,159 |
13,605,697 |
8,558,606 |
(a)A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working
interest is owned.
(b)A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres
is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
The undeveloped acreage numbers presented in the table above have been compiled using best efforts to review and
determine acreage that is not currently drilled but may be available for drilling at the current time under certain circumstances.
Whether or not undrilled acreage may be drilled and thereafter produce economic quantities of oil or gas is related to many
factors which may change over time, including natural gas and oil prices, service vendor availability, regulatory regimes,
midstream markets, end user demand, and macro and micro financial conditions; the undeveloped acreage described herein is
presented without an opinion as to economic viability, as a result of the aforesaid factors. Additionally, it is noted that certain
formations on a land tract may be already developed while other formations are undeveloped.
The following table sets forth the number of total gross and net undeveloped acres as of December 31, 2023 that will expire in
2024, 2025 and 2026 unless production is established within the spacing units covering the acreage prior to the expiration
dates or unless such acreage is extended or renewed.
Gross |
Net |
|
2024 |
5,404 |
663 |
2025 |
24,906 |
2,876 |
2026 |
2,869 |
87 |
Our primary focus is to operate our existing producing assets in a safe, efficient and responsible manner, however we also
assess areas subject to lease expiration for potential development opportunities when prudent. As of December 31, 2023, we
had no development plans other than the in-progress wells described above and therefore have not classified any other
potential undrilled locations on this acreage as proved undeveloped reserves.
Preparation of Reserve Estimates
Our reserve estimates as of December 31, 2023 included in
this Annual Report & Form 20-F were independently
evaluated by our independent engineers, NSAI, in
accordance with petroleum engineering and evaluation
standards published by The Petroleum Resources
Management System jointly published by the Society of
Petroleum Engineers, the World Petroleum Council, the
American Association of Petroleum Geologists and the
Society of Petroleum Evaluation Engineers, as amended and
definitions and guidelines established by the SEC.
NSAI is a worldwide leader of petroleum property analysis
for industry and financial organizations and government
agencies. NSAI was founded in 1961 and performs
consulting petroleum engineering services under Texas
Board of Professional Engineers Registration No. F-2699.
Within NSAI, the technical persons primarily responsible for
auditing the estimates set forth in the NSAI reserves report
incorporated herein are Mr. Robert C. Barg and Mr. William
J. Knights. Mr. Barg, a Licensed Professional Engineer in the
State of Texas (No. 71658), has been practicing consulting
petroleum engineering at NSAI since 1989 and has over six
years of prior industry experience. He graduated from
Purdue University in 1983 with a Bachelor of Science
Degree in Mechanical Engineering. Mr. Knights, a Licensed
Professional Geoscientist in the State of Texas, Geology
(No. 1532), has been practicing consulting petroleum
geoscience at NSAI since 1991 and has over 10 years of prior
industry experience. He graduated from Texas Christian
University in 1981 with a Bachelor of Science Degree in
Geology in 1984 with a Master of Science Degree in
Geology. Both technical principals meet or exceed the
education, training and experience requirements set forth in
the Standards Pertaining to the Estimating and Auditing of
Oil and Gas Reserves Information promulgated by the
Society of Petroleum Engineers; both are proficient in
judiciously applying industry standard practices to
engineering and geoscience evaluations, as well as applying
SEC and other industry reserves definitions and guidelines.
Our internal staff of petroleum engineers and geoscience
professionals work closely with our independent reserve
engineers to ensure the integrity, accuracy and timeliness
of data furnished to our independent reserve engineers for
their reserve evaluation process. Our technical team
regularly meets with the independent reserve engineers to
review properties and discuss methods and assumptions
used to prepare reserve estimates. The reserve estimates
and related reports are reviewed and approved by our Vice
President of Reservoir Engineering. The Vice President of
Reservoir Engineering has been with the Group since 2018
and has 24 years of experience in petroleum engineering,
with over 20 years of experience evaluating natural gas and
oil reserves, and holds a Bachelor of Science in Petroleum
Engineering. Prior to joining the Group in 2018, our Vice
President of Reservoir Engineering served in various
reservoir engineering roles for public companies engaged in
the exploration and production operations, and is also a
member of the Society of Petroleum Engineers.
Estimation of Proved Reserves
Proved reserves are reserves which, by analysis of
geoscience and engineering data, can be estimated with
reasonable certainty to be economic1ally producible from a
given date forward from known reservoirs under existing
economic conditions, operating methods and government
regulations prior to the time at which contracts providing
the right to operate expires, unless evidence indicates that
renewal is reasonably certain. The term “reasonable
certainty” implies a high degree of confidence that the
quantities of oil or natural gas actually recovered will equal
or exceed the estimate. To achieve reasonable certainty, we
and the independent reserve engineers employed
technologies that have been demonstrated to yield results
with consistency and repeatability. The technologies and
economic data used in the estimation of our proved
reserves include, but are not limited to, well logs, geologic
maps and available downhole and production data,
micro-seismic data and well-test data.
Reserve engineering is and must be recognized as a
subjective process of estimating volumes of economically
recoverable oil and natural gas that cannot be measured in
an exact manner. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering
and geological interpretation. As a result, the estimates of
different engineers often vary. In addition, the results of
drilling, testing and production may justify revisions of such
estimates. Accordingly, reserve estimates often differ from
the quantities of natural gas, NGLs and oil that are
ultimately recovered. Estimates of economically
recoverable natural gas, NGLs and oil and of future net cash
flows are based on a number of variables and assumptions,
all of which may vary from actual results, including geologic
interpretation, prices and future production rates and costs.
Productive Wells
Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities.
Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells
are the sum of our fractional working interest owned in gross wells. The following table summarizes our productive natural gas
and oil wells as of December 31, 2023.
As of December 31, 2023
|
|
Natural gas wells |
71,471 |
Oil wells |
3,044 |
Total gross productive wells |
74,515 |
Natural gas wells |
59,226 |
Oil wells |
1,413 |
Total net productive wells |
60,639 |
As of December 31, 2023(a)
|
|
Total gross in progress wells |
4.0 |
Total net in progress wells |
3.8 |
(a)Comprised of wells in the Central Region.
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 |
2023 |
4 |
4 |
— |
— |
4 |
4 |
2022 |
5 |
2 |
— |
— |
5 |
2 |
2021 |
— |
— |
— |
— |
— |
— |
We drilled no exploratory wells (productive or dry) during the years ended December 31, 2023, 2022 and 2021.
During 2021, we completed the Tapstone Acquisition, which included five wells in the Central Region that were under
development by Tapstone as of December 31, 2021. We engaged third parties to complete this development activity, however
they remained in progress as of December 31, 2021.
During 2022, we completed the development of the five wells referenced in the preceding paragraph 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. As of December 31, 2023, four Central Region development wells remain in progress. Refer to Note 5 in
the Notes to the Group Financial Statements for additional information regarding the sale of equity interest in DP Lion Equity
Holdco LLC.
Production Volumes, Average Sales Prices and Operating Costs
Year Ended |
|||
December 31, 2023 |
December 31, 2022 |
December 31, 2021 |
|
Production |
|||
Natural Gas (MMcf) |
256,378 |
255,597 |
234,643 |
NGLs (MBbls) |
5,832 |
5,200 |
3,558 |
Oil (MBbls) |
1,377 |
1,554 |
592 |
Total production (MMcfe) |
299,632 |
296,121 |
259,543 |
Average realized sales price |
|||
(excluding impact of derivatives settled in cash) |
|||
Natural gas (Mcf) |
$2.17 |
$6.04 |
$3.49 |
NGLs (Bbls) |
24.23 |
36.29 |
32.53 |
Oil (Bbls) |
75.46 |
89.85 |
65.26 |
Total (Mcfe) |
$2.68 |
$6.33 |
$3.75 |
Average realized sales price |
|||
(including impact of derivatives settled in cash) |
|||
Natural gas (Mcf) |
$2.86 |
$2.98 |
$2.36 |
NGLs (Bbls) |
26.05 |
19.84 |
15.52 |
Oil (Bbls) |
68.44 |
72.00 |
71.68 |
Total (Mcfe) |
$3.27 |
$3.30 |
$2.51 |
Operating costs per Mcfe |
|||
LOE(a)
|
$0.71 |
$0.62 |
$3.31 |
Production taxes(b)
|
0.21 |
0.25 |
0.53 |
Midstream operating expense(c)
|
0.23 |
0.24 |
1.42 |
Transportation expense(d)
|
0.32 |
0.40 |
1.28 |
Total operating expense per Mcfe |
$1.47 |
$1.51 |
$6.54 |
(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
The Group operates in four primary fields: (i) Appalachia, which is comprised of the stacked Marcellus and Utica shales and
other conventional formations (that form our Central Region) (ii) East Texas and Louisiana, which consists of the stacked
Cotton Valley, Haynesville, and Bossier shales, (iii) the Barnett Shale and (iv) the Midcontinent region, in North Texas and
Oklahoma, which also consists of various stacked plays. The following table presents production for the Group’s Appalachian
region, which is considered significant, or greater than 15% of the Group’s total proved reserves, for the periods presented.
Year Ended |
|||
APPALACHIA |
December 31, 2023 |
December 31, 2022 |
December 31, 2021 |
Production |
|||
Natural Gas (MMcf) |
167,930 |
180,194 |
201,635 |
NGLs (MBbls) |
3,018 |
2,810 |
2,690 |
Oil (MBbls) |
394 |
423 |
446 |
Total production (MMcfe) |
188,402 |
199,592 |
220,451 |
Customers
Our production is generally sold on month-to-month contracts at prevailing market prices.
During the year ended December 31, 2023, no customers individually comprised more than 10% of total revenues.
During the year ended December 31, 2022, no customers individually comprised more than 10% of total revenues.
During the year ended December 31, 2021, two customers individually comprised more than 10% of total revenues,
representing 22% of consolidated revenues.
Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers
would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate
potential exposure to credit risk, we may require from time to time for our customers to provide financial security.
Delivery Commitments
We have contractually agreed to deliver firm quantities of natural gas to various customers, which we expect to fulfill with
production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to
meet these commitments. The following table summarizes our total gross commitments, compiled using best estimates based
on our sales strategy, as of December 31, 2023.
Natural gas (MMcf) |
|
2024 |
70,769 |
2025 |
16,658 |
2026 |
— |
Thereafter |
360,114 |
Transportation and Marketing
Diversified Energy Marketing, LLC, our wholly owned
marketing subsidiary, specializes in commodity marketing,
asset optimization, producer services and the strategic
management of our transportation portfolio. Our mission
extends to enhancing operational efficiency and
profitability, leveraging market insights, operational
expertise, strategic asset management and the right sizing
of our contractual transport assets to ensure flow reliability
and access to various markets.
Our comprehensive suite of services encompasses the
marketing of natural gas, NGL’s and oil, risk management,
logistical support and the strategic management of
transportation agreements. This approach is designed to
maximize market presence, financial outcomes, ensure
consistent product flow and capitalize on strengthening
markets through our transportation infrastructure and
vertically integrated midstream systems. Our midstream
infrastructure and strategic arrangements enable us to
access high-demand markets, notably in the U.S. Gulf Coast
region, while leveraging low cost transportation in
Appalachia. The synergistic nature of our asset base allows
for access to advantageous pricing year-round and flow
assurance with minimal firm transportation agreements. As
of December 31, 2023, our transportation arrangements
provide access to 515 MMcfepd of takeaway capacity.
As a dedicated arm of the Group, our marketing team
ensures our operations and strategies are closely aligned
with our broader goals. With a team of experienced
professionals and a deep understanding of the energy
market’s nuances, we are committed to delivering value and
reliability to our stakeholders. We navigate through the
industry’s complexities to achieve operation excellence.
Competition
Our marketing activities compete with numerous other
companies offering the same services, many of which
possess larger financial and other resources than we have.
Some of these competitors are other producers and
affiliates of companies with extensive pipeline systems that
are used for transportation from producers to end users.
Other factors affecting competition are the cost and
availability of alternative fuels, the level of consumer
demand and the cost of and proximity to pipelines and
other transportation facilities. We believe that our ability to
compete effectively within the marketing segment in the
future depends upon establishing and maintaining strong
relationships with customers.
Seasonality
Demand for natural gas and oil generally decreases during
the spring and fall months and increases during the summer
and winter months. However, seasonal anomalies and
consumers’ procurement initiatives can also lessen seasonal
demand fluctuations. Seasonal anomalies can increase
competition for equipment, supplies and personnel and
can lead to shortages and increase costs or delay
our operations.
Title to Properties
We believe that we have satisfactory title to substantially all
of our active properties in accordance with standards
generally accepted in the oil and natural gas industry. Our
properties are subject to customary royalty and overriding
royalty interests, certain contracts relating to the
exploration, development, operation and marketing of
production from such properties, consents to assignment
and preferential purchase rights, liens for current taxes,
applicable laws and other burdens, encumbrances and
irregularities in title, which we believe do not materially
interfere with the use of or affect the value of such
properties. Prior to acquiring producing wells, we endeavor
to perform a title investigation on an appropriate portion of
the properties that is thorough and is consistent with
standard practice in the natural gas and oil industry.
Generally, we conduct a title examination and perform
curative work with respect to significant defects that we
identify on properties that we operate. We believe that we
have performed reasonable and protective title reviews
with respect to an appropriate cross-section of our
operated natural gas and oil wells.
GOVERNMENT REGULATION
General
Our operations in the United States are subject to various
federal, state and local (including county and municipal
level) laws and regulations. These laws and regulations
cover virtually every aspect of our operations including,
among other things: use of public roads; construction of
well pads, impoundments, tanks and roads; pooling and
unitizations; water withdrawal and procurement for well
stimulation purposes; wastewater discharge, well drilling,
casing and hydraulic fracturing; stormwater management;
well production; well plugging; venting or flaring of natural
gas; pipeline construction and the compression and
transportation of natural gas and liquids; reclamation and
restoration of properties after natural gas and oil operations
are completed; handling, storage, transportation and
disposal of materials used or generated by natural gas and
oil operations; the calculation, reporting and payment of
taxes on natural gas and oil production; and gathering of
natural gas production. Various governmental permits,
authorizations and approvals under these laws and
regulations are required for exploration and production as
well as midstream operations. These laws and regulations,
and the permits, authorizations and approvals issued
pursuant to such laws and regulations, are intended to
protect, among other things: air quality; ground water and
surface water resources, including drinking water supplies;
wetlands; waterways; protected plants and wildlife; natural
resources; and the health and safety of our employees and
the communities in which we operate.
We endeavor to conduct our operations in compliance with
all applicable U.S. federal, state and local laws and
regulations. However, because of extensive and
comprehensive regulatory requirements against a backdrop
of variable geologic and seasonal conditions,
non-compliance during operations can occur. Certain
non-compliance may be expected to result in fines or
penalties, but could also result in enforcement actions,
additional restrictions on our operations, or make it more
difficult for us to obtain necessary permits in the future. The
possibility exists that new legislation or regulations may be
adopted which could have a significant impact on our
operations or on our customers’ ability to use our natural
gas, natural gas liquids and oil, and may require us or our
customers to change their operations significantly or incur
substantial costs.
Environmental Laws
Many of the U.S. laws and regulations referred to above are
environmental laws and regulations, which vary according
to the jurisdiction in which we conduct our operations. In
addition to state or local laws and regulations, our
operations are also subject to numerous federal
environmental laws and regulations. Below is a discussion
of some of the more significant federal laws and regulations
applicable to us and our operations.
Clean Air Act
The federal Clean Air Act and associated Federal and state
regulations regulate air emissions through permitting and/
or emissions control requirements. These regulations affect
the entire value chain from oil and natural gas production,
to gathering, to processing, to transmission and storage,
and then to distribution operations. Various equipment and
activities in our assets are subject to regulation, including
compressors, engines, dehydrators, storage tanks,
pneumatic devices, fugitive components, and blowdowns.
We obtain permits, typically from state or local authorities,
or document exemptions necessary to authorize these
activities. Further, we are required to obtain pre-approval
for construction or modification of certain facilities, and/or
to use specific equipment, technologies or best
management practices to control emissions. Some states
also require a separate operating permit to be obtained for
on-going operations.
Federal and state governmental agencies continue to
review and revise the air quality regulations affecting oil
and natural gas activities, and further regulation could
increase our cost or otherwise affect our ability to produce.
For instance, on March 7, 2024, the U.S. Environmental
Protection Agency (“EPA”) finalized New Source
Performance Standard Subpart OOOOb (NSPS OOOOb) for
new, modified, and reconstructed sources after
December 6, 2022, and Emissions Guideline Subpart
OOOOc (EG OOOOc) for sources existing prior to
December 6, 2022. Most provisions of NSPS OOOOb take
effect immediately while certain requirements have phase-
in periods. EG OOOOc requires individual states to
incorporate similar provisions into their regulations (or rely
upon EPA’s model requirements) and will require
approximately five years to be implemented. The affected
source categories under OOOOb and OOOOc include well
completions, fugitive emissions, liquids unloading, process
controllers, process pumps, storage vessels, and
associated gas.
EPA has also recently proposed two interrelated
regulations. On August 1, 2023, EPA proposed revisions to
the greenhouse gas reporting rule for the oil and natural
gas industry to change the calculation methodology to be
primarily based on actual emission measurements rather
than emission factors. These changes facilitate the
implementation of a methane fee under the Waste Emission
Charge (WEC) rule which was proposed on
January 26, 2024. Both rules are expected to be finalized
by August 2024 as required by the Inflation Reduction Act
(IRA) of 2022. Under the WEC rule, reporters would be
subject to a fee beginning in 2025 at $900 per ton of
methane emissions that exceed thresholds prescribed
under the rule. These methane emissions would be based
on those reported under the greenhouse gas reporting rule.
Clean Water Act
The federal Clean Water Act (“CWA”) and corresponding
state laws affect our operations by regulating storm water
or other discharges of substances, including pollutants,
sediment, and spills and releases of oil, brine and other
substances, into surface waters, and in certain instances
imposing requirements to dispose of produced wastes and
other oil and gas wastes at approved disposal facilities. The
discharge of pollutants into jurisdictional waters is
prohibited, except in accordance with the terms of a permit
issued by the EPA, the U.S. Army Corps of Engineers, or a
delegated state agency. These permits require regular
monitoring and compliance with effluent limitations, and
include reporting requirements. Federal and state
regulatory agencies can impose administrative, civil and/or
criminal penalties for non-compliance with discharge
permits or other requirements of the CWA and analogous
state laws and regulations.
Endangered Species and Migratory Birds
The Endangered Species Act and related state laws
regulations protect plant and animal species that are
threatened or endangered. The Migratory Bird Treaty Act
and the Bald and Golden Eagle Protection Act provides
similar protections to migratory birds and bald and golden
eagles, respectively. Some of our operations are located in
areas that are or may be designated as protected habitats
for endangered or threatened species, or in areas where
migratory birds or bald and golden eagles are known to
exist. Laws and regulations intended to protect threatened
and endangered species, migratory birds, or bald and
golden eagles could have a seasonal impact on our
construction activities and operations. New or additional
species that may be identified as requiring protection or
consideration could also lead to delays in obtaining permits
and/or other restrictions, including operational restrictions.
Safety of Gas Transmission and
Gathering Pipelines
Natural gas pipelines serving our operations are subject to
regulation by the U.S. Department of Transportation’s
PHMSA pursuant to the NGPSA, as amended by the Pipeline
Safety Act of 1992, the Accountable Pipeline Safety and
Partnership Act of 1996, the PSIA, the Pipeline Inspection,
Protection, Enforcement and Safety Act of 2006, and the
2011 Pipeline Safety Act. The NGPSA regulates safety
requirements in the design, construction, operation and
maintenance of natural gas pipeline facilities, while the PSIA
establishes mandatory inspections for all U.S. oil and natural
gas transmission pipelines in high-consequence areas.
Additionally, certain states, such as West Virginia, also
maintain jurisdiction over intrastate natural gas lines. In
October 2019, PHMSA finalized the first of three rules that,
collectively, are referred to as the natural gas “Mega Rule.”
The first rule imposed additional safety requirements on
natural gas transmission pipelines, including maximum
operating pressure and integrity management near HCAs
for onshore gas transmission pipelines. PHMSA finalized the
second rule extending federal safety requirements to
onshore gas gathering pipelines with large diameters and
high operating pressures in November 2021. PHMSA
published the final of the three components of the Mega
Rule in August 2022, which took effect in May 2023. The
final rule applies to onshore gas transmission pipelines,
clarifies integrity management regulations, expands
corrosion control requirements, mandates inspection after
extreme weather events, and updates existing repair
criteria for both HCA and non-HCA pipelines. Finally,
PHMSA published a Notice of Proposed Rulemaking
regarding more stringent gas pipeline leak detection and
repair requirements to reduce natural gas emissions on May
18, 2023. The adoption of laws or regulations that apply
more comprehensive or stringent safety standards could
increase the expenses we incur for gathering service.
Resource Conservation and Recovery Act
The federal Resource Conservation and Recovery Act
(“RCRA”) and corresponding state laws and regulations
impose requirements for the management, treatment,
storage and disposal of hazardous and non-hazardous
wastes, including wastes generated by our operations.
Drilling fluids, produced waters and most of the other
wastes associated with the exploration, development and
production of natural gas and oil are currently regulated
under RCRA’s solid (non-hazardous) waste provisions.
However, legislation has been proposed from time to time,
and various environmental groups have filed lawsuits, that,
if successful, could result in the reclassification of certain
natural gas and oil exploration and production wastes as
“hazardous wastes,” which would make such wastes subject
to much more stringent handling, disposal and clean-up
requirements. A change in the RCRA exclusion for drilling
fluids, produced waters and related wastes could result in
an increase in our costs to manage and dispose of
generated wastes, which could have a material adverse
effect on the industry as well as on our results of operations
and financial position.
Comprehensive Environmental Response,
Compensation, and Liability Act
The Comprehensive Environmental Response,
Compensation, and Liability Act (“CERCLA” or
“Superfund”) imposes joint and several liability for costs of
investigation and remediation, and for natural resource
damages without regard to fault or the legality of the
original conduct, on certain classes of persons with respect
to the release into the environment of substances
designated under CERCLA as hazardous substances. These
classes of persons, so-called potentially responsible parties
(“PRP”), include the current and past owners or operators
of a site where the release occurred and anyone who
disposed, transported, or arranged for the disposal,
transportation, or treatment of a hazardous substance
found at the site. CERCLA also authorized the EPA and, in
some instances, third parties to take actions in response to
threats to public health or the environment, and to seek to
recover from the PRPs the costs of such action. Many
states, including states in which we operate, have adopted
comparable state statutes.
Although CERCLA generally exempts “petroleum” from
regulation, in the course of our operations we have
generated and will generate wastes that may fall within
CERCLA’s definition of hazardous substances, and may
have disposed of these wastes at disposal sites owned and
operated by others. We may also be the owner or operator
of sites on which hazardous substances have been released.
In the event contamination is discovered at a site on which
we are or have been an owner or operator, or to which we
have sent hazardous substances, we could be jointly and
severally liable for the costs of investigation and
remediation and natural resource damages. Further, it is not
uncommon for neighboring landowners and other third
parties to file claims for personal injury and property
damage allegedly caused by hazardous substances or other
pollutants released into the environment.
Oil Pollution Act
The primary federal law related to oil spill liability is the Oil
Pollution Act (“OPA”), which amends and augments oil spill
provisions of the Clean Water Act and imposes certain
duties and liabilities on certain “responsible parties” related
to the prevention of oil spills and damages resulting from
such spills in or threatening waters of the United States or
adjoining shorelines. A liable “responsible party” includes
the owner or operator of a facility, vessel or pipeline that is
a source of an oil discharge or that poses the substantial
threat of discharge. OPA assigns joint and several liability,
without regard to fault, to each liable party for oil removal
costs and a variety of public and private damages.
Although defenses exist to the liability imposed by OPA,
they are limited. In the event of an oil discharge or
substantial threat of discharge, we may be liable for costs
and damages.
Regulation of the Sale and Transportation of
Natural Gas, NGLs and Oil
The transportation and sale, or resale, of natural gas in
interstate commerce are regulated by the Federal Energy
Regulatory Commission (“FERC”) under the Natural Gas
Act of 1938, the Natural Gas Policy Act of 1978, and
regulations issued under those statutes. FERC regulates
interstate natural gas transportation rates and terms and
conditions of service, which affects the marketing of natural
gas that we produce, as well as the revenues we receive for
sales of our natural gas. FERC regulations require that rates
and terms and conditions of service for interstate service
pipelines that transport crude oil and refined products and
certain other liquids be just and reasonable and must not be
unduly discriminatory or confer any undue preference upon
any shipper. FERC regulations also require interstate
common carrier petroleum pipelines to file with FERC and
publicly post tariffs stating their interstate transportation
rates and terms and conditions of service.
Section 1(b) of the Natural Gas Act exempts natural gas
gathering facilities from regulation by FERC. However, the
distinction between federally unregulated gathering
facilities and FERC regulated transmission facilities is a
fact-based determination, and the classification of facilities
is the subject of ongoing litigation. We own certain natural
gas pipeline facilities that we believe meet the traditional
tests FERC has used to establish a pipeline’s primary
function as “gathering,” thus exempting it from the
jurisdiction of FERC under the Natural Gas Act.
Intrastate natural gas transportation is also subject to
regulation by state regulatory agencies. The basis for
intrastate regulation of natural gas transportation and the
degree of regulatory oversight and scrutiny given to
intrastate natural gas pipeline rates and services varies from
state to state. Like the regulation of interstate
transportation rates, the regulation of intrastate
transportation rates affects the marketing of natural gas
that we produce, as well as the revenues we receive for
sales of our natural gas.
FERC regulates the transportation of oil and NGLs on
interstate pipelines under the provisions of the Interstate
Commerce Act, the Energy Policy Act of 1992 and
regulations issued under those statutes. Intrastate
transportation of oil, NGLs and other products is dependent
on pipelines whose rates, terms and conditions of service
are subject to regulation by state regulatory bodies under
state statutes.
Natural gas, NGLs and crude oil prices are currently
unregulated, but Congress historically has been active in
the area of natural gas, NGLs and crude oil regulation. We
cannot predict whether new legislation to regulate sales
might be enacted in the future or what effect, if any, any
such legislation might have on our operations.
Health and Safety Laws
Our operations are subject to regulation under the federal
Occupational Safety and Health Act (“OSHA”) and
comparable state laws in some states, all of which regulate
health and safety of employees at our operations.
Additionally, OSHA’s hazardous communication standard,
the EPA community right-to-know regulations under Title III
of the federal Superfund Amendment and Reauthorization

Act and comparable state laws require that information be
maintained about hazardous materials used or produced by
our operations and that this information be provided to
employees, state and local governments and the public.
Climate Change Laws and Regulations
Climate change continues to be a legislative and regulatory
focus. There are a number of proposed and recently-
enacted laws and regulations at the international, federal,
state, regional and local level that seek to limit greenhouse
gas emissions, and such laws and regulations that restrict
emissions could increase our costs should the requirements
necessitate the installation of new equipment or the
purchase of emission allowances. For example, the Inflation
Reduction Act, which was signed into law in August 2022,
includes a “methane fee” that is expected to be imposed
beginning with emissions reported for calendar year 2024.
In addition, the current U.S. administration has proposed
more stringent methane pollution limits for new and
existing gas and oil operations. These laws and regulations
could also impact our customers, including the electric
generation industry, making alternative sources of energy
more competitive and thereby decreasing demand for the
natural gas and oil we produce. Additional regulation could
also lead to permitting delays and additional monitoring
and administrative requirements, in turn impacting
electricity generating operations.
At the international level, President Biden has recommitted
the United States to the UN-sponsored “Paris Agreement,”
for nations to limit their greenhouse gas emissions through
non-binding, individually-determined reduction goals every
five years after 2020. In April 2021, President Biden
announced a goal of reducing the United States’ emissions
by 50 – 52% below 2005 levels by 2030. In November 2021,
the international community gathered in Glasgow at the
26th Conference of the Parties to the UN Framework
Convention on Climate Change, during which multiple
announcements were made, including a call for parties to
eliminate certain fossil fuel subsidies and pursue further
action on non-carbon dioxide greenhouse gases. In a
related gesture, the United States and the European Union
jointly announced the launch of the “Global Methane
Pledge,” which aims to cut global methane pollution by at
least 30% by 2030 relative to 2020 levels, including “all
feasible reductions” in the energy sector. Such
commitments were re-affirmed at the 27th Conference of
the Parties in Sharm El Sheikh. Although it is not possible at
this time to predict how legislation or new regulations that
may be adopted pursuant to the Paris Agreement to
address greenhouse gas emissions would impact our
business, any such future laws and regulations imposing
reporting obligations on, or limiting emissions of
greenhouse gases from, our equipment and operations
could require us to incur costs to implement such measures
associated with our operations.
In addition, activists concerned about the potential effects
of climate change have directed their attention at sources
of funding for energy companies, which has resulted in
certain financial institutions, funds and other sources of
capital restricting or eliminating their investment in natural
gas and oil activities. Ultimately, this could make it more
difficult to secure funding for exploration and production
activities. Litigation risks are also increasing, as a number of
cities and other local governments have sought to bring
suits against the largest oil and natural gas exploration and
production companies in state or federal court, alleging,
among other things, that such companies created public
nuisances by producing fuels that contributed to global
climate change effects, such as rising sea levels, and
therefore are responsible for roadway and infrastructure
damages, or alleging that the companies have been aware
of the adverse effects of climate change for some time but
defrauded their investors by failing to adequately disclose
those impacts.
Additionally, the SEC published its long-awaited climate
rule in early March 2024, requiring the disclosure of a range
of climate-related risks and financial impacts. We are
currently assessing this rule, and at this time we cannot
predict the costs of implementation or any potential
adverse impacts for either the Group or our customers
resulting from the rule. Additionally, enhanced climate
disclosure requirements could accelerate the trend of
certain stakeholders and lenders restricting or seeking more
stringent conditions with respect to their investments in
certain carbon-intensive sectors.


A Letter from Our Senior
VP of Sustainability
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We remain focused on environmental
stewardship as well as meaningful and
effective employee and community
engagement, delivered with an intentional
adherence to a strong foundation of
good governance.”
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Sustainability Review
Thank you for your interest in Diversified’s sustainability
journey, which we believe aligns with not only our
stewardship business model but also value creation for our
stakeholders. I am pleased to share this annual review of
the successes and challenges on our 2023 journey,
inclusive of updates on key environmental, social and
governance objectives.
Of primary importance and consideration to our
sustainability efforts is our environmental impact, and
specifically our emissions footprint. During 2023, our well
tenders and midstream personnel remained focused on
progressing voluntary leak detection and repairs and other
emission reduction initiatives, while our environmental
teams were equally focused on identifying, researching and
field testing a multitude of emission abatement or reduction
technology alternatives for consideration in our near- and
long-term emissions reduction roadmap in order to achieve
our stated 2040 net zero goal.
These diligent efforts benefited the Group alongside both
our long-standing, proven Smarter Asset Management
optimization and efficiency improvement actions and the
increasingly demonstrable environmental and risk
mitigation wins from our multiple remote monitoring Gas
Control and Integrated Operating centers.
As we have said before, we are committed to reporting
transparently on our performance, even when it falls short
of our expectations. For example, our 2023 personal safety
performance did not meet our high standards as it relates
specifically to Total Recordable Incident Rate which
increased year-over-year as a result of an increase in
reported incidents. While our OneDEC corporate culture
and number one daily priority of ‘Safey-No Compromises’
remains steadfast, what is changing is our approach of how
improvement is best achieved.
Much like we did previously when liquids spill rates were
not meeting our expectations, we have already begun
dedicating focused time, attention and manpower to this
matter to ascertain how best to move forward with making
improvements. Having identified accountability as a key
contributor to this shortfall, we have already begun
addressing accountability with both field leadership and
staff. We look forward to sharing more about these actions
as we work towards delivering on the high expectations we
set for ourselves.
During 2023, we also updated our periodic materiality
assessment with both internal and external stakeholders,
the results of which reflected that employee safety remains
our top priority across the stakeholder groups. These
results reinforce our desire and drive to promptly and
appropriately address all matters related to employee
safety, beginning with our work thus far on TRIR.
We remain committed to setting appropriate objectives
related to our sustainability journey and reporting
transparently on the same. This priority is being recognized
in the marketplace as evidenced by our 2022 Sustainability
Report receiving the ESG Report of the Year award from
ESG Awards 2023 and that same report driving an
improved MSCI ESG rating score to Leadership status.
Furthermore, the Oil and Gas Methane Partnership 2.0 has
awarded our emissions reduction roadmap a Gold Standard
Pathway designation for the second consecutive year,
signaling the validity of our environmental stewardship
model and transparency thereof.
2023 was another successful year in many respects, but we
will not stop there as we have much more we want, and
need, to do to bolster our long-term sustainability. We will
remain focused on environmental stewardship (PLANET) as
well as meaningful and effective employee and community
engagement (PEOPLE), delivered with an intentional
adherence to a strong foundation of good governance
(PRINCIPLES).
The best is yet to come!

Teresa B. Odom
Senior Vice President - Sustainability
March 19, 2024
Additional information on our climate, environmental, safety and
social performance will be available in our separate sustainability
communications on our website at www.div.energy.
Our Strategy Supports Sustainability
Our sustainability strategy is centered around prudent risk management,
asset integrity, employee safety, environmental protection, and emissions
reduction. From the wellhead to the boardroom, we are committed to our
role as responsible stewards of the natural resources we manage, the
people we employ and the environment in which we operate. We strive to
adhere to quality operating standards with a strong focus on the
environment, the health and safety of employees and positive
engagement with our local communities.
We believe our efforts to connect the meaningful and differentiated
attributes associated with our natural gas will increasingly be recognized
by the market as value is progressively placed on highly responsible
operators of natural gas assets. We are committed to addressing key
climate and environmental issues for our PLANET and likewise relevant
social issues for the PEOPLE across our operations, and doing so with a
constant focus on the values and PRINCIPLES under which we were
founded and continue to operate.
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Commitment to Leadership and Transparency
Responsible stewardship and sustainability go hand-in-hand
and are at the core of our operations. Through sustainability
leadership and our unique business model, we
systematically strengthen our performance and execute on
our sustainability plans and commitments. We work
diligently to foster a culture of stewardship and
transparency, and a key aspect of our approach is to seek
stakeholder input while also keeping them apprised of
progress against our sustainability ambitions.
In 2023, we updated our periodic, formal multi-stakeholder
materiality assessment, utilizing our prior materiality
assessment, stakeholder outreach and peer benchmarking
to identify 29 relevant topics spread among eight key
clusters that include health and safety, climate change,
environmental management, resource management,
socio-economic value creation, our employees, suppliers
and partners, and risks and compliance.
We engaged both internal stakeholders such as Board
members and employees at all levels and locations as well
as external stakeholders across our value chain such as
equity and debt investors, financial service providers, trade
associations, customers, contractors and suppliers. The
assessment was conducted via a third-party, anonymous
online survey and the results were then compiled for
distribution and review by management and the
Sustainability & Safety Committee.
Among the relevant topics, the survey reflected that eight
topics of the top ten shared highest materiality among both
internal and external stakeholders, including the following:
—Employee safety
—Driver safety
—Cybersecurity
—Legal compliance
—Accident prevention
—Ethical behavior
—Access to funding
—Incident management
Survey over survey, the protection and safety of employees
continues to be a top priority while cybersecurity and
related data protection protocols was the single largest
upward mover and is now a top five priority for internal
stakeholders and likewise a top ten priority for external
stakeholders. Safe and efficient asset retirement fell out of
the top five relevance for both internal and external
stakeholders, though remains a top ten priority for external
stakeholders. For external stakeholders, emissions control
and reductions also fell in relevance, settling among their
top 20 material topics. Importantly, all of these issues
should not be viewed in isolation as they are increasingly
interconnected and can often impact each other.

Our Approach to Sustainability
Our approach to sustainability encompasses consideration
of our climate, environmental and social impacts as well as
our responsibility to conduct business in accordance with
the highest standards of governance. These topics remain
front of mind as we proudly accept the responsibility and
privilege to be part of the solution to the significant
challenges of our country’s energy, climate and economic
security. To that end,
—by providing a reliable supply of abundant domestic
energy from assets that have a significantly smaller
environmental footprint than newly drilled wells, we
support our nation’s energy security.
—by making investments and implementing measures to
reduce emissions at the facilities we acquire, producing
differentiated natural gas through our industry-
recognized emissions detection, measurement and
mitigation processes, and retiring orphan wells for
several states, we are part of the solution for
climate security.
—by providing an affordable and sustainable domestic
energy supply while also providing both direct and
indirect employment, paying mineral royalties, and
supporting tax revenues for the communities where we
operate, we are grateful to be contributing to our
country’s economic security.
LIFE-CYCLE STEWARDSHIP
With a unique business model that reflects growth through
acquisitions and an operating strategy that embodies
stewardship of our natural resources and the environment,
we understand the importance of a full, life-cycle focus on
the assets we manage. As such, we have established an
employee-driven, data-focused sustainability program
which integrates sustainability considerations and actions
throughout our assets’ life cycles, beginning with pre-
acquisition diligence screening and continuing until we
safely and permanently retire the acquired assets at the end
of their productive lives. These considerations are the very
heart of the operational priorities that collectively represent
our proven SAM program, which is designed to increase
efficiencies, reduce fugitive greenhouse gas (“GHG”)
emissions, and deliver improvements in production at
existing facilities.
SUPPORTING LONG-TERM SUSTAINABILITY
We view sustainability through the lens of creating
long-term sustainable value for our stakeholders while
ensuring our daily actions contribute to a sustainable
environment and planet for society at large. We
demonstrate this focus when we align our stewardship-
focused business model and OneDEC culture with our
commitment to continuously identify, improve and monitor
our sustainability actions, as evidenced through our setting
and tracking of relevant and measurable targets.
These targets include, in part, our previously disclosed
Scope 1 methane emissions intensity reductions of 30% and
50% by 2026 and 2030, respectively, as compared to our
2020 baseline. Ongoing human and financial capital
investments across our asset portfolio, aimed largely at
methane reduction through leak detection and repair
“(LDAR”) efforts and conversion of natural gas-driven
pneumatic devices to compressed air, contributed to a 33%
reduction in reported methane emissions intensity for
While this accomplishment achieves our 2030 reduction
target seven years earlier than anticipated, we continue to
seek opportunities to further reduce our methane footprint.
In light of forthcoming environmental regulations that may
add new source categories of reported emissions, we will
evaluate those regulations as we consider new interim
targets. Even so, our year-over-year focused efforts and
life-cycle stewardship actions will continue to play a vital
role in keeping us on track toward our stated goal of Scope
1 and 2 net zero absolute GHG emissions by 2040.
In addition to our own guiding values for sustainability
management, we also utilize the United Nations’
Sustainable Development Goals (“SDGs”), which call on
individuals, corporations and governments to work
together towards the ultimate, unified goal of creating a
better and more sustainable future for all citizens globally.
At Diversified, we challenge ourselves to consider these
topics and more when we effectuate our business model,
corporate strategy, sustainability commitments, daily
operations, and risk management practices. We believe our
OneDEC approach supports important contributions to the
SDGs illustrated below, and we’ve identified several other
SDGs to which our business model aligns yet also provides
added opportunities for us to make continuous
improvement and contribution.
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Task Force on Climate-Related
Financial Disclosures (“TCFD”)

The report is consistent with the recommendations of the
TCFD, with the exception of Scope 3 emissions, as noted
below, and in line with the Financial Conduct Authority’s
Listing Rule 9.8.6 requirement. The report also reflects the
guidance provided in Section C of the TCFD Annex, entitled
“Guidance for All Sectors” and Section E of the TCFD
Annex, entitled “Supplemental Guidance for Non-Financial
Groups”, related to the Energy sector. We are in the
process of developing a Scope 3 inventory in line with
existing protocols and evolving market expectations and
aim to report Scope 3 emissions for the 2024 year end.
While we remain focused on emissions reductions where we
have the most control, and thus are making good progress
in decarbonizing our own operations, we recognize that the
GHG emissions associated with our value chain are
proportionately greater than non-energy producing
companies as our Scope 3 emissions are associated mostly
with the end-use of our products. Therefore, we seek to
identify GHG reduction opportunities from our upstream
and downstream supply chains. We also evaluate initiatives,
including renewable natural gas and carbon capture and
storage projects which, in the longer-term, would allow us
to mitigate or offset some or all of our Scope 1 and
2 GHG emissions.
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GOVERNANCE
EMBEDDING SUSTAINABILITY ACROSS THE
ORGANIZATION
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Our Board of Directors (“Board” or “Directors”) continues
to take a hands-on approach to identifying, assessing and
managing climate-related risks and seeking new
commercial opportunities from an energy transition, such as
alternative uses for our wellbores. The processes by which
the Board does this are fully integrated into our Board
calendar and our governance procedures. Climate-related
topics were included in discussions at each of the six
regular Board meetings held throughout 2023.
The Directors receive regular briefings at Board meetings
on applicable climate matters from the Executive team as
well as the Chair of the Sustainability & Safety Committee.
From time to time the Board also receives training or
briefings from external third-party experts on specific
topics. In 2023, Deloitte LLP delivered a board education
session on biodiversity and the upcoming Taskforce on
Nature-related Financial Disclosures (“TNFD”).
Key climate-related topics discussed by the Board
throughout 2023, included:
—Assessing progress on emission detection and
mitigation, including handheld fugitive surveys and
repair, pneumatic conversions, aerial LiDAR, and
compressor conversions;
—Reviewing output from the marginal abatement cost
curve ("MACC") and approving the Emissions Program
budget for 2023; and
—Ensuring proposed acquisitions are consistent with
emissions reduction targets and plans.
Using an internally developed acquisition emissions
screening tool, target assets are assessed for their methane
intensity in accordance with the Methane Intensity Protocol
developed by the Natural Gas Sustainability Initiative
(“NGSI"). This information is then used by the Board as one
metric to inform its acquisition decision-making. The NGSI
voluntary reporting protocol complements existing
regulatory reporting by providing a consistent, transparent
and comparable methodology for measuring and reporting
methane emissions throughout the natural gas supply chain.
Our Board Committees provide oversight of our climate-
related risks and opportunities although these
considerations are a primary focus of our Sustainability &
Safety Committee. The roles of the four Board Committees
are reflected in the climate-related governance framework
depicted below.
CLIMATE-RELATED GOVERNANCE FRAMEWORK - BOARD

MANAGEMENT’S ROLE IN ASSESSING & MANAGING
CLIMATE-RELATED RISKS & OPPORTUNITIES
Management remains abreast of climate-related issues
through (i) its knowledge of our industry, business
environment and ongoing operating activities, (ii) frequent
interactions with both internal and external stakeholders,
including senior leaders in the Group, state and national
regulators and investors, and (iii) engagement with
vendors, industry associations and benchmarking groups
where current trends and best practice operating standards
and emissions reductions solutions are shared.
Climate-related responsibilities are assigned to
management-level positions according to each individual’s
area of responsibility and contribution to our overall
corporate strategy.
Collectively, our executive team, including in part the CEO,
CFO, COO (formerly) and Executive Vice President-
Operations (presently), provide frequent climate-related
operational and financial updates to the Board at each
Board meeting and throughout the year via interim
communications. However, the CEO assumes ultimate
responsibility for delivery of the Group’s climate and energy
transition strategy, including management of climate-
related risks and opportunities.
Climate-related actions by management during the year
include, but are not limited to: ensuring annual budgets
include operating and expenses for climate initiatives;
considering the impacts of new or emerging climate-related
policy and regulatory development on the Group; aiding in
the design or advancement of emission reduction initiatives;
ensuring Board directives on climate are integrated into
appropriate compensation plans and monitoring progress
of the same; and considering the impact of potential
acquisitions on standalone and consolidated Group
emissions and decarbonization strategies.
THE CULTURAL SHIFT UNDERPINS OUR TRANSITION TO
NET ZERO
Environmental management and the energy transition are
deeply embedded into our company’s culture and actions,
as climate impact is recognized as a key strategic
consideration across multiple business functions. For
example, we have trained and equipped 100% of our well
tenders to become leak detection and repair technicians.
Finding and repairing leaks has always been a priority for
Diversified and is truly just a daily routine for our employees
as we seek to positively impact our climate while delivering
a lower-carbon energy solution to market. Furthermore, at
an operational level, we have optimized well tender routes
to increase efficiency and reduce driving time, therefore
reducing emissions. We also use lightweight, fuel-efficient,
well-maintained vehicles to drive down fuel consumption.
In addition to the aforementioned responsibilities of various
teams with regard to climate oversight and action, the
figure below provides a broader view of certain individual
company departments whose actions incorporate
climate considerations.
CLIMATE CULTURE DRIVES DAILY ACTIONS

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STRATEGY
UNDERPINNED BY DE-METHANIZATION OF
OUR GAS PRODUCTION
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The reduction of methane emissions is at the heart of our
corporate strategy and underpins our pragmatic approach
to the ongoing decarbonization of our operations.
While our de-methanization activities are focused on the
decarbonization of our existing assets, we are also keen to
explore opportunities that will help us utilize our asset
portfolio, as well as our skills and competencies, beyond our
current business model.
OUR NET ZERO PATHWAY: OUTPERFORMING
OUR TARGETS
In line with our pragmatic approach, we set out our
emissions reduction targets aiming to reduce Scope 1
methane intensity by 30% by 2026 and 50% by 2030,
reaching net zero from Scope 1 and 2 absolute GHG
emissions by 2040. We also set out our net zero pathway
showing how we plan to achieve our targets, beginning
with a near-term focus on methane emissions, as
depicted below.
We have been resolute in our focus on reducing emissions
from our operations. We are delighted that our significant
efforts to date, largely through the deployment of state-of-
the-art technologies for methane detection and reduction
and the conversion of natural gas-driven pneumatic
devices, have yielded outstanding results, with our 2030
methane intensity reduction target being achieved in 2023,
seven years ahead of schedule and directly aiding our
overall goal toward net zero in 2040.
Even so, we will continue to progress our decarbonization
strategy, focusing primarily on additional methane emission
reductions in the near-term as we seek to unpack the
impact on our reported emissions from new EPA
regulations where future real emission reductions could be
offset by potential increases stemming from both recent
and forthcoming changes in regulatory reporting
requirements. We are committed to tackling those changes
and delivering tangible results with continued financial
investment and diligent execution to achieve our 2040 net
zero GHG goal.
We discuss our deployment of decarbonization
technologies in the Climate-related Risks and Opportunities
tables on the following pages.

CLIMATE-RELATED RISKS AND OPPORTUNITIES
In line with TCFD guidance, we consider climate-related
risks and opportunities that could have a material financial
impact on our business on a short-, medium- and long-term
basis. For this analysis, our considered timeframes are as
follows: short-term 2024 to 2026, medium-term 2027 to
2030, and long-term 2031 and beyond. The timeframes
align with our methane intensity reduction targets set for
2026 and 2030 while contributing to our net zero GHG
emissions goal in 2040.
The climate-related risks and opportunities presented
below were identified through workshops with executive
management, senior leaders, and third-party advisors as
well as through peer comparisons.
Climate-related risks have been grouped according to the
risk types suggested by the TCFD: Transition Risk
(including Market, Policy & Legal, Technology, and
Reputation) and Physical Risk (chronic and acute), while
climate-related opportunities are categorized as Resource
Efficiency, Energy Source, Products & Services,
and Markets.
The specific climate-related risks and opportunities
identified are set out in the following tables together with
the potential impacts they could have on our business, the
timeframes associated with each, and the progress being
made to mitigate or exploit them.
CLIMATE-RELATED RISKS
Risk |
Potential Impact |
Timeframe(a)
|
Risk Management Actions |
||
S |
M |
L |
|||
MARKET |
|||||
Changing global
market sentiment
as consumers
transition away
from fossil fuels
will result in reduced
natural gas & oil
demand and impact
the price outlook
|
—Negative impact on
revenues and
portfolio value
—Reduced
opportunities
for acquiring
commercially
viable assets
|
•
|
•
|
—We conduct scenario analysis of portfolio impacts
under a range of commodity price and demand
outlooks to assess portfolio resiliency.
—Our portfolio is heavily weighted towards gas, which is
expected to remain more resilient than oil through the
energy transition, particularly in North America.
—Our low-cost production provides considerable
resilience to lower commodity price environments.
—Our robust hedging strategy provides financial
assurance and protection against commodity price
volatility in the short-, medium- and long-term.
—Our compliance with OGMP Gold Standard Pathway
will ensure we remain differentiated as a responsible
gas producer, helping us sustain our competitive
advantage through the decarbonization of our Scope 1
and 2 emissions.
—We are pursuing other differentiated gas initiatives like
TrustWell and other quantification-based efforts to
market our lower gas intensity.
|
|
Increased cost
of and more
challenging or
conditional access
to capital
|
—Investors/lenders
look to decrease
their portfolio
exposure to
hydrocarbon assets
—Capital available to
Diversified
may become
more difficult
to access, more
costly, or come
with additional
climate-specific
obligations
|
•
|
•
|
•
|
—We have committed to achieving Net Zero by 2040
from our Scope 1 and 2 emissions, aligning with
mainstream lenders and investors in Western capital
markets.
—Our existing levels of fixed-rate debt and amortizing
payments provide significant protection in the
short/medium term.
—We continue to pursue ESG-aligned asset-backed
securitization (“ABS”) financing structures, where our
achievement or out-performance of commitments to
ambitious ESG KPIs attached to these ABS financings
can improve borrowing rates and financing capacity.
—Our hedging strategy provides short- to medium-term
certainty and protection for cash flows available
for reinvestment.
—Our strategy of incremental M&A enables adaptation to
changing market or financing conditions.
|
Risk |
Potential Impact |
Timeframe(a)
|
Risk Management Actions |
||
S |
M |
L |
|||
POLICY & LEGAL |
|||||
Cost of carbon |
—Implementation
of some form of
carbon cost or
regulation in states
where we operate
could increase
operating costs
and make our
natural gas less
competitive vs.
other forms
of energy
—Such policies could
also accelerate
pressure from
investors and
stakeholders to
reduce emissions
or improve
energy efficiency,
increasing our
decarbonization
costs
|
•
|
•
|
—Ongoing engagement in proactive, voluntary
measurement of our Scope 1 emissions to ensure we
fully understand potential portfolio liability.
—We continue to engage in efforts to reduce
emissions across our portfolio, such as leak detection
and repair, pneumatics replacements, and
compressor optimization.
—We engage in cost-efficient operations and deploy
SAM initiatives across our upstream and
midstream portfolio.
—We are engaging with third-party consultants to
more fully develop our internal price of carbon
metrics and strategy.
—We include the evaluation of acquisition targets’
carbon footprints in our M&A process and final
investment decisions.
—Our evolving internal MACC analysis aided by field
testing and/or small-scale pilot projects allows us to
optimize the prioritization of identified emissions
reduction projects.
|
|
Well retirement |
—Acceleration of
existing state
well retirement
commitments
could significantly
increase annual
capital and
operating costs
—Underestimation
of well retirement
costs could
significantly
increase asset
retirement
obligation and
future cash outlay
for well retirement
activities
|
•
|
•
|
—We actively engage with regulators regarding well
retirement policies and activities.
—We are committed to retiring wells ahead of state
requirements (2023: 80 wells), including 201
Diversified-operated wells retired in 2023.
—Our low-cost retirement capacity enables us to increase
our own well-retirement targets, participate in state
orphan well programs and carry out asset retirement
for third parties.
—Our extensive experience of well retirement,
particularly in Appalachia, and our expanded
retirement capabilities puts us in the best position to
accurately forecast the future capital requirements for
these activities.
—Revenue streams from third-party asset retirements
help to offset the cost of retiring our own wells. In
addition, Diversified is exploring potential opportunities
in alternative energy uses for wellbores (e.g.
hydrogen production, carbon storage, mechanical
battery storage).
|
|
Risk |
Potential Impact |
Timeframe(a)
|
Risk Management Actions |
||
S |
M |
L |
|||
Litigation |
—Potential litigation
tied specifically
to Diversified’s
climate-related
reporting (e.g. for
misrepresentation)
or actions could
bring additional
legal and
reputational costs
—Potential litigation
around leaks or
other sources of
emissions (now
or historical)
|
•
|
•
|
•
|
—We have focused, near-term efforts to achieve Scope 1
methane intensity reductions with a goal of net zero
Scope 1 and 2 GHG emissions by 2040.
—We expect continued development, funding, and
execution of formal plans and projects will enable the
achievement of emissions targets.
—We continue to transparently report and communicate
climate and emission reduction initiatives, keeping
stakeholders abreast of such actions.
—We actively engage with federal and U.S. state
regulators, and consistently demonstrate our
commitment to meet or exceed their requirements.
—We maintain strong community support in our
operating areas.
—We are transitioning to an emissions intelligence
software, Iconic Air, to track, report, and manage
emissions, which will enable us to increase
transparency, improve the integrity of our emissions
measurements and therefore minimize potential
litigation risk around leaks.
—We work with independent consultants to verify our
GHG accounting.
—We engage an independent, third-party consultant to
provide moderate Level II assurance for Scope 1 & 2
GHG emissions.
|
Current &
emerging climate-
related regulation
and policy
|
—Increasing costs of
doing business as a
fossil fuel-focused
company;
regulatory fines for
emission levels;
regulatory
constraints on
hydrocarbon
commerce
—Mandates on and
regulation of
existing products
and services
|
•
|
•
|
•
|
—We actively monitor U.S. and international climate-
related regulations and frameworks and engage as
applicable, including: IFRS S1 & S2, Transition Plan
Taskforce, SEC Climate Disclosures and TNFD.
—We have multiple emissions reduction activities in
place aimed at reducing methane emissions and
achieving our 2040 net zero goal.
—We actively engage with industry associations to
ensure we are using best practices in operating
procedures and emissions reductions.
—Our experience from the many voluntary efforts
made to date to reduce our methane emissions
positions us to manage any impact arising from the
U.S. EPA OOOOb and OOOOc regulations and U.S.
Inflation Reduction Act’s Methane Emissions
Reduction Program.
|
Risk |
Potential Impact |
Timeframe(a)
|
Risk Management Actions |
||
S |
M |
L |
|||
TECHNOLOGY |
|||||
Cost of GHG
emissions detection
and reduction
technology
|
—Increased costs
of required
technology;
possible cost
upside if more
mitigation than
expected is
required
|
•
|
•
|
—Our emissions detection and reduction plans are
already well-advanced with short- and medium-term
costs factored into budgets.
—We continue to benefit from the successful use of aerial
and handheld leak detection equipment and from
continuous investment in our low-cost SAM program to
repair and eliminate fugitive emissions.
—We continue to invest in leading-edge emissions
reduction technologies and to monitor new technology
developments, including aerial LiDAR, compressor
conversions, handheld emissions detection, and
pneumatic conversions.
—We piloted two emerging emission detection and
quantification technologies in 2023. Both technologies
are expected to substantially reduce the cost of
emissions detection while providing emissions
quantification and a digital twin.
—To date, we’ve experienced lower-than-expected
costs of compressed air applications for pneumatic
controllers. Our internally developed solutions for
pneumatics and level controllers are well below
market prices.
—We continue to demonstrate innovative actions to
reduce emissions, including retrofitting/elimination of
existing emitting equipment (e.g. pneumatic devices
and compressors).
—Throughout 2023, we have continued to build and
maintain our emissions intelligence using Iconic Air
carbon accounting software to track, report and
manage emissions. Using Iconic Air will allow us to
streamline emissions accounting and reporting and
manage our emissions sources at the asset-level.
|
|
Substitution of
natural gas and oil
with lower-carbon
forms of energy
|
—Faster acceleration
and adoption/
substitution of
alternative energy/
lower carbon
solutions (i.e.,
electric vehicles,
more efficient
appliances) drives
lower demand for
natural gas and oil
|
•
|
•
|
—The scenario analysis shows that gas plays an
important role throughout the Energy Transition even
in the Net Zero scenario (accounting for 22% of global
energy demand in 2040).
—Our scenario analysis shows that even under low-
carbon scenarios our portfolio is relatively resilient. Due
to our low cost of production, we are able to maintain
profitable operations across our portfolio even under
low commodity price environments (see Portfolio
Resilience section).
|
|
Risk |
Potential Impact |
Timeframe(a)
|
Risk Management Actions |
||
S |
M |
L |
|||
REPUTATIONAL |
|||||
Overall perception
of fossil fuels/
energy sector
|
—Increased
stakeholder
pressure to
accelerate
emissions reduction
projects could
increase short-term
costs and challenge
profit margins
—Changes in
stakeholder/society
expectations of
Diversified’s role in
the energy
transition could
impact company
valuation or brand
—Increasing
challenge to attract
and/or retain talent
|
•
|
•
|
•
|
—We are committed to transparency in emissions and
climate risk reporting, and to our plan of achieving our
climate-related targets.
—We engage regularly with shareholders, regulators and
other key stakeholders to ensure understanding of our
climate strategy.
—We include climate metrics in short- and long-term
remuneration policies to incentivize ongoing
improvement in climate actions.
—We are continuing to explore longer-term opportunities
in new revenue-generating low-carbon energy projects,
for example through waste heat recovery.
—Broad leadership engagement through multiple
communication channels keeps our current employees
abreast of business strategy and emissions reduction
actions and results.
—Our community engagement initiatives and talent
acquisition programs, including scholarship and
internship programs, facilitate broader awareness of
the Company and its climate-related actions among
potential employee candidates.
—Our community tree planting programs, such as
Diversified’s 10,000 tree replanting effort with West
Virginia State University in 2023, support communities,
provide carbon sequestration, and increase the
company’s visibility and engagement with our
future talent.
|
PHYSICAL |
|||||
Acute – Changing
weather patterns,
including increased
frequency and
severity of extreme
weather events
such as extreme
rainfall and
hurricanes
|
—Increased risk
of compromised
infrastructure
or forced
abandonment of
operations could
cause loss of
revenue and
decrease
portfolio value
|
•
|
•
|
•
|
—We have robust business continuity and crisis
management plans in place, which were tested during
the central Appalachia floods of 2022 and resulted in
minimal business disruption.
—We use 24-hour monitoring centers, enabling a more
rapid response to weather-related disruptions.
|
Chronic –
Persistent or
constantly
recurring weather
patterns, including
water stress and
heat stress
|
—Increasingly
challenging
and potentially
dangerous
environmental and
climate conditions
could increase
operating costs
and risks
|
•
|
•
|
—Our business model inherently requires minimal water
consumption in our operations.
—We maintain appropriate levels of insurance to
mitigate losses.
—The geographic spread of our asset portfolio mitigates
any large-scale disruption to production from individual
weather events e.g., flooding.
—Further details on our exposure to physical risks and
our qualitative assessment of our portfolio’s
vulnerability to identified hazards are described in a
separate section below.
|
|
(a)Timeframes are defined as S - short (2024 to 2026), M - medium (2027 to 2030), and L - long (2031 and beyond).
CLIMATE-RELATED OPPORTUNITIES
Timeframe(a)
|
|||||
Opportunity |
Potential Impact |
S |
M |
L |
Steps and Progress |
RESOURCE EFFICIENCY |
|||||
Emissions
monitoring and
replacement of
inefficient
equipment
|
—Early detection
of methane leaks
reduces the loss
of sales gas and
associated
revenues across
the portfolio
|
•
|
•
|
•
|
—To reduce our GHG footprint, we continue to invest in
remote leak detection, aerial surveillance, replacement
of pneumatic devices, and inefficient compressors.
—We actively track advances in emissions monitoring
technologies and plan to take advantage of any
suitable applications and technology cost reductions
that evolve.
—We continue to work on emissions intelligence
digitalization and automation plans, supporting the
connection of reported emissions data in the Iconic
Air software to our MACC tool, to enhance the
process of evaluating a broad scope of emissions
reduction projects.
|
Lowering vehicle-
derived carbon
emissions through
optimization and
more efficient
vehicles; waste
management
recycling
|
—Fuel and operating
cost savings by
using vehicles that
are more efficient
and have lower
carbon emissions
|
•
|
•
|
—We utilize lighter weight, more fuel-efficient vehicles in
our fleet replacement program, which could further
expand in the future to include the use of longer-range
electric vehicles.
—We are exploring new technologies to allow remote
operations at well sites thus reducing vehicle use and
associated emissions.
—We utilize optimized route mapping to create the
most efficient well tender routes thereby reducing
vehicle run time, maintenance, fuel consumption and
vehicle emissions.
—We work internally to identify opportunities to reduce
our carbon footprint within our office environment, for
example paper consumption and waste recycling.
|
|
ENERGY SOURCE |
|||||
Increase use of
renewable energy
sources
|
—Replace natural gas
with renewable
energy sources to
support operational
power needs
|
•
|
•
|
—Diversified uses solar equipment and small wind
turbines to provide auxiliary power at certain smaller or
remote well sites and has been increasing the use of
solar equipment in its pneumatic conversion projects.
—38% of our sources for Scope 2 electrical usage in 2023
were zero carbon (including nuclear and renewables).
An additional 33% results from lower-carbon energy
sources (including natural gas) versus coal or
petroleum products.
—We are exploring new technologies to expand the use
of renewable and alternative energy in operations,
including waste heat recovery and solid oxide fuel cells.
Additionally, we are exploring the use of wellbores for
mechanical battery energy storage to aid in the energy
transition by providing off-peak energy storage.
|
|
Timeframe(a)
|
|||||
Opportunity |
Potential Impact |
S |
M |
L |
Steps and Progress |
PRODUCTS & SERVICES |
|||||
Asset retirement
capabilities for third
parties
|
—Providing
third-party asset
retirement services
as an additional
revenue stream and
advancing states’
resolution of
orphan wells
—Support regional
well retirement
compliance
—Continue to build
internal asset
retirement
capabilities
|
•
|
•
|
•
|
—Our expanded well retirement capability supports
our regional leadership position in responsible
asset retirement.
—We see an opportunity to grow our retirement capacity
further via our subsidiary Next LVL Energy, positioning
Diversified to further support states’ efforts to eliminate
orphan wells.
—Potential for expanded services including the
generation of voluntary and regulated carbon credits
related to well retirement of orphan wells held by state
governments.
—Expanded plugging commitments increase return of
well pads to original, natural conditions thus supporting
natural reforestation and biodiversity initiatives in
those areas.
|
Fuel cells and
hydrogen
applications
|
—Explore potential
long-term revenue
opportunities in
blue hydrogen and/
or emissions
reductions using
fuel cells
|
•
|
•
|
—We continue to explore new opportunities in low-
carbon technologies.
—We are currently in the early stages of pursuing
partnerships to evaluate potential of using
existing midstream infrastructure for future
hydrogen applications.
|
|
Carbon capture
utilization and
storage (CCUS)
|
—Explore the
potential to provide
carbon storage
services to
neighboring
emitters
—Potential to offset
our Scope 1 & 2
emissions
|
•
|
•
|
—We are working with external partners to explore the
potential of using our gas storage capacity for CCUS.
|
|
Solar |
—Opportunities
to lease land
surface rights to
third parties
|
•
|
•
|
•
|
—We are evaluating opportunities to expand surface
rights leases to third parties for their development of
solar power farms.
|
MARKETS |
|||||
OGMP Gold
Standard
Recognition
|
—Recognition of our
commitment to
deliver responsibly
produced gas to
the market
—Enables further
differentiation of
our produced
natural gas versus
competitors
|
•
|
•
|
•
|
—Achieving Gold Standard Pathway in both 2022 and
2023 positions us to offer responsibly produced gas in
the marketplace to differentiate it from other natural
gas production.
—As a member of OGMP, Diversified is committed to
disclosing actual methane emissions data aligned with
the OGMP 2.0 framework, thus further increasing our
level of transparency for the market’s consideration
when seeking differentiated gas.
|
(a)Timeframes are defined as S - short (2024 to 2026), M - medium (2027 to 2030), and L - long (2031 and beyond).
EMBRACING ENERGY TRANSITION
TECHNOLOGIES MITIGATES RISKS AND
OPENS OPPORTUNITIES
MARGINAL ABATEMENT COST CURVE
(“MACC”) ANALYSIS
MACC is a tool that allows for the visualization of a portfolio
of projects that, when taken as a whole, provide
complementary choices for the most efficient reduction of
GHG emissions. Both the GHG emission reduction potential
and the associated abatement cost for each project are
identified within the MACC.
Anticipated emission reductions are estimated based on
source-specific emissions calculations or through direct
measurement. Total costs include direct costs for project
implementation and the value generated from the project,
including decreased product loss or reduced operating
costs. When estimated emission reduction costs and
benefits are combined in the MACC, emissions reduction
project ranking based on economic feasibility and potential
impact is realized.
We are utilizing our MACC analysis as a warehouse of
potential technologies identified through extensive research
and collaboration within the industry, where each
technology is at various stages of evaluation and
applicability. Of the first emphasis for us in the MACC was
natural gas-driven pneumatics, where we have now
identified multiple technologies and solutions that are
effective and promising for the elimination of methane
emissions from pneumatic controllers and pumps.
Before our use of the MACC, we began our pneumatic
controller emission reduction efforts two years ago,
targeting the highest emitting pads first. Now, with the
MACC’s capability to provide a conversion cost break point
of dollars per MT CO2e for a growing database of
alternative technologies, we can make more informed
decisions as to optimal locations and technologies for our
future conversion plans. Thus, going forward we currently
plan to employ customized solutions on a site-by-site basis
as informed by our MACC.
MACC CONSIDERATIONS IN EMISSIONS ABATEMENT (illustrative)

Diversified has achieved the OGMP 2.0 Gold Standard
Pathway for the second consecutive year. The OGMP 2.0 is
the only comprehensive measurement-based reporting
framework created to report methane emissions accurately
and transparently for the oil and gas industry. This award
recognizes our commitment to developing aggressive and
attainable multi-year plans to measure and reduce methane
emissions. Our team worked diligently to fulfil the
requirement throughout the year and continues to do so.
For our operated assets, Diversified has now achieved Level
4 on all but two of OGMP’s 10 categories, with only
methane slip and leak quantification data remaining to
address. As we look to close out these remaining two
categories for Level 4, we also continue to advance our
efforts to achieve Level 5 on all categories as per OGMP 2.0
Gold Standard expectations.
PHYSICAL RISK
We recognize that the physical risks of climate events can
impact our business. These risks have been incorporated
into our risk assessment through our Viability and Going
Concern assessment where we consider the impacts that
certain climate events may have on our production.
Physical climate risks are functions of hazard, exposure and
vulnerability and are therefore complex and frequently
multidimensional. They are related to tangible, physical
impacts of changes in climate and are considered either
acute or chronic. Acute physical risks are event-driven,
including weather events such as extreme rainfall, flooding,
droughts, or wildfires, whereas chronic risks refer to longer-
term shifts in climate patterns, such as rising temperatures
or rising sea levels.
HAZARD IDENTIFICATION
To identify key physical risks to our portfolio, we leveraged,
in part, data published by the American Communities
Project (“ACP”) which included physical risk projections
through 2040. The ACP climate risk analysis was
underpinned by data from Four Twenty Seven, an affiliate
of Moody’s specializing in physical climate risk. Pinkus, A.
(2021) “Mapping Climate Risks by County and Community”,
American Communities Project (accessed January 30,
2024). The 2040 data refers to IPCC’s RCP 8.5 scenario,
which assumes GHG emissions continue to grow
unmitigated, leading to a ‘hothouse world’ with an
estimated global average temperature rise of 4.3°C by
2100. This scenario implies no concerted effort is taken by
society to cut GHG emissions. In contrast, the International
Energy Administration’s (“IEA’s”) most conservative
scenario, STEPS, assumes the implementation of existing
policies, leading to a 2.5°C rise in temperatures by 2100.
Therefore, the scenario used in our assessment of the
impact of physical climate risks on our portfolio is more
extreme than any of the three scenarios used to test the
resilience of our portfolio against the climate-related
transition risks.
We focused on four key hazards that could impact Diversified’s portfolio: acute risks of extreme rainfall, hurricanes, chronic
risks of water stress, and heat stress. We carried out a qualitative assessment of our portfolio exposure to these hazards. The
impact of rising sea levels as addressed in the ACP report has not been analyzed, since we currently have no coastal or
offshore exposure.
IDENTIFIED HAZARDS IN THE STATES IN WHICH WE OPERATE*

*Includes high and extreme (red flag) risks only as per ACP data
Source: ACP, Diversified Energy
EXPOSURE ANALYSIS
Our upstream and midstream assets are considered
exposed if they are located in an area where a climate
hazard may occur. The degree of exposure is defined by the
intensity of that particular hazard, with the range of
exposure including no risk, low, medium, high, and extreme
risk (which corresponds to ACP’s ‘red flag’).
While our portfolio is located entirely U.S. onshore, our
exposure to suffering a significant financial loss from a
single extreme weather event is minimized due to the
dispersion of our production footprint over a large
geographical area covering nine states – Pennsylvania,
Ohio, West Virginia, Virginia, Kentucky, Tennessee,
Louisiana, Texas, and Oklahoma, with our headquarters
in Alabama.
We compared the locations of our current assets at the
county level to the same counties within the ACP analysis.
This enabled us to quickly assess the exposure of our
assets, and therefore production, to the projected 2040 risk
profile of those counties, as reflected below. We also
identified potential physical impacts associated with each
of the identified risks.
OUR PROJECTED GEOGRAPHICAL EXPOSURE TO KEY PHYSICAL RISKS OF CLIMATE CHANGE IN 2040
Acute |
Extreme Rainfall |
Hurricanes |

Potential impacts: |
Potential impacts: |
||
—Disruptions of operations
due to flooding
—Infrastructure damage
|
—Supply chain disruption
—Increased operating costs
—Impact on revenue
|
—Infrastructure damage due to
extreme winds
—Operational disruption from
hurricanes
|
—Inland flooding
—Increased operating
costs
—Impact on revenue
|
Chronic |
Water Stress |
Heat Stress |

Potential impacts: |
Potential impacts: |
||
—Reduced community
access to water
—Infrastructure cost of fresh
water supply
|
—Impact on supply chain
—Increased operating costs
—Impact on revenue
|
—Increased heat exposure is a health
and safety risk for people
—Decrease in work productivity
—Infrastructure failure due to excess
heat exceeding the design criteria
(gas leaks)
|
—Additional energy
needed for cooling
—Increased operating
costs
—Impact on revenue
|
Source: ACP, Diversified Energy
Using the ACP’s county-based hothouse world scenario,
and when considering each of these four risks, we believe
that our current portfolio is most exposed to extreme
rainfall. That is, we estimate that approximately 84% of our
projected production could be exposed to extreme rainfall
in 2040, as shown in the following table. It is important to
note that ACP’s analysis is at the county level, whereas our
assets may be located in a specific portion of the county
which may bear a different risk level than that of the overall
county. Thus, we believe our exposure will be mitigated by
the specific location of our wells within the counties that
are exposed to extreme rainfall risk, for example. Further,
we estimate that less than 3% of our existing production is
located in a designated flood plain.
OUR PRODUCTION EXPOSURE TO KEY PHYSICAL RISKS
Physical Risk |
% of Diversified’s
Projected 2040
Production in
High or Extreme
Risk Areas
|
|
Acute Risk |
Extreme Rainfall |
84% |
Hurricanes |
4% |
|
Chronic Risk |
Water Stress |
22% |
Heat Stress |
41% |
VULNERABILITY ASSESSMENT
Our qualitative assessment of vulnerability addresses the
sensitivity of our operations to the respective hazard,
including actions taken to reduce or adapt to the hazard.
Acute Physical Risks
Extreme rainfall and associated risk of flooding represent
the highest risk to our assets in the Appalachian Basin in
2040, especially in Kentucky, Ohio, and West Virginia,
where our exposure to this risk is characterized as extreme.
Indeed, in July 2022, several central Appalachia states
within our footprint, including primarily Kentucky but also
Virginia and West Virginia to a lesser extent, experienced
devastating floods resulting in loss of life and extensive
damage to housing and public infrastructure within the
states. While the flooding also temporarily impacted our
operations, including compressor facilities, communications,
and pipelines, we were able to efficiently restore the
affected facilities to operations within approximately 10
days. This flooding event did not require the full
implementation of our formal Crisis Management and
Business Continuity plans, yet our teams were able to
professionally respond as a result of our preparation for
such events.
Hurricanes represent a moderate risk to our portfolio, with
only limited increased exposure in Texas and Louisiana,
where this risk is characterized as medium-to-high and is
largely a function of the states’ location on the U.S. Gulf
Coast where Atlantic Basin hurricanes have historically, in
part, impacted the coastline. In the last three years, since
we acquired our first Central Region assets in 2021, the
Texas and Louisiana coastlines have directly experienced
two out of a total of 22 recorded hurricanes in the Atlantic
Basin with no impact on our inland operations.
From a mitigation perspective, we aim for prevention rather
than response when it comes to physical impacts to our
business from any emergency, including those which may
be climate-related. This prevention starts with training our
employees to respond to potential emergencies such as
natural disasters, where all emergency response-related
processes exceed the needs of situations that may arise.
We are also prepared to be effective and expeditious in our
response to any emergency as a function of our separate,
formal Crisis Management and Business Continuity plans
which are reviewed at least twice annually by senior
leadership and which help to ensure the resilience of our
critical business functions and the safety of our employees
and other stakeholders in the case of significant business
disruption. The resilience of our systems is supported in
large part by our intentional, 100% cloud-based information
systems strategy which eliminates the physical risk
exposure of this aspect of our business.
Our Central Region acquisitions in 2021 and 2022 also
brought three district Integrated Operations Centers
(“IOCs”) into our portfolio, two in our upstream operations
and one in our midstream operations. These IOCs
complement our existing gas control center in West
Virginia which monitors the majority of our midstream
Appalachia assets. These 24-hour monitoring centers
facilitate streamlining the collection, standardization and
dissemination of timely, decision-useful data for both
normal operations and atypical events such as those
created by physical climate risks. The central management
of data through these remote monitoring centers leverages
our supervisory control and data acquisition (SCADA)
system and therefore affords a more rapid response to
weather-related disruptions.
Further, we consistently maintain appropriate levels of
hazard risk insurance coverage that mitigate potential
material financial losses from extreme weather events, such
as extreme rainfall, tornadoes, hurricanes, etc.
Chronic Physical Risks
Water stress is the most significant chronic physical risk
associated with our portfolio in 2040, particularly for our
assets in Texas and Oklahoma, where this risk is
categorized as high. Nevertheless, our business model is
focused on operating existing assets, rather than the
extensive drilling of new wells which requires significant
amounts of water for completion of the wells. To date, we
have not experienced an instance of water use limitations
or restrictions when fresh water has been needed for our
typical field and well operations or asset retirement
activities. Therefore, we do not anticipate any significant
disruptions to our operations from this risk categorization.
We do recognize, however, that the increased risk of
drought-like conditions can impact local communities and
ecosystems, lead to increased cost of freshwater supply
where we do intake water, and potentially affect our supply
chain. We expect to adapt to these conditions, especially
since we already operate in these areas which are subject
to strict environmental regulations. Our approach to water
management is to minimize freshwater use where possible,
particularly in potential water-scarce areas within our
operating footprint, as described in our Climate Policy and
Environmental, Health & Safety Policy.
In our Sustainability Report, we assess our current exposure
to water stress, as defined by the World Resources
Institute’s Aqueduct Water Risk Atlas. Even though our
current exposure to water stress risk primarily qualifies as
Low Overall Water Risk, we continue to apply a responsible
approach to water use, aimed at limiting freshwater use,
managing our produced water, and recycling and reusing
produced water as and where applicable.
Heat stress is likely to have a moderate-to-high impact on
our portfolio, with the highest exposure in Oklahoma,
Kentucky, West Virginia and Virginia. We consider heat
stress from two perspectives: (1) personnel and (2)
infrastructure. While we recognize that heat stress is a
health and safety risk for personnel and could lead to a
decrease in work productivity, we have programs and
processes currently in place to address this concern daily,
given the number of field personnel working outdoors and
the nature and volume of work that must occur outside as a
result of our asset portfolio. We also hold adequate levels
of insurance coverage for heat stress-related incidents that
may require medical attention. As the risk of heat stress
increases, we are confident that our current health and
safety procedures can be successfully adapted, as
applicable, to mitigate the impact of this chronic risk on
our operations.
Our Smarter Asset Management operations program helps
mitigate the potential impacts of heat stress on our
infrastructure. The program consists of ongoing, consistent
asset inspection and maintenance and remote monitoring.
This information allows for a rapid response to any
infrastructure or equipment failures that may occur due to
excessive heat.
PORTFOLIO RESILIENCE
Following TCFD guidance and to ensure comprehensive
business planning, we evaluate the resilience of our
portfolio under multiple future climate scenarios. Each
scenario includes assumptions about how the energy
transition may evolve, with differing commodity price
and demand outcomes, providing a range of outlooks
against which our portfolio is tested to evaluate and
determine resilience.
SCENARIO ANALYSIS
The three scenarios we selected to test our portfolio
climate resilience are:
(a)IEA’s Stated Policies Scenario (“STEPS”)
(b)IEA’s Announced Pledges Scenario (“APS”)
(c)Wood Mackenzie’s Accelerated Energy Transition 1.5-
degree pathway (“AET-1.5”), a global net zero by
2050 scenario
It should be noted that there are some differences in the
categorization of specific fuels in the Wood Mackenzie
versus the IEA’s scenarios. For example, in the Wood
Mackenzie AET-1.5 scenario, liquid biofuels are included
within oil whereas they are included with bioenergy in the
IEA scenarios.
TOTAL PRIMARY ENERGY SUPPLY AND CO2 EMISSIONS FOR EACH SCENARIO
AET -1.5 |
IEA APS(a)(c)
|
IEA STEPS(b)(c)
|
|||||
Total Primary Energy
Supply (1018 J)
|
CO2 Emissions
(GT)
|
Total Primary Energy
Supply (1018 J)
|
CO2 Emissions
(GT)
|
Total Primary Energy
Supply (1018 J)
|
CO2 Emissions
(GT)
|
||
![]() |
![]() |
![]() |

(a)Based on IEA data from the Announced Pledges Scenario of the IEA (2023) World Energy Outlook, www.iea.org/weo
(b)Based on IEA data from the Stated Policies Scenario of the IEA (2023) World Energy Outlook, www.iea.org/
(c)Further detail on the IEA’s pricing methodology for the APS and STEPS scenarios can be found in the 2023 World Energy Outlook.
|
AET -1.5
This scenario represents the most aggressive energy
transition scenario we considered, consistent with limiting
global warming to 1.5°C, in line with the most ambitious
goals of the Paris Agreement. In AET-1.5, global energy
supply peaks in 2024 due to more aggressive policy action
and accelerated global decarbonization efforts, which result
in an increase in electrification and adoption of new-energy
technologies in place of hydrocarbons. Under this scenario,
oil demand peaks in 2024 and then declines, from ~100
million barrels of oil per day (“MMBO/d”) to ~30 MMBO/d in
2050. As a result, near-term oil prices fall rapidly, from
current levels to ~$52 per barrel (“/bbl”) in 2030 and then
continue to decline more gradually reaching ~$30/bbl by
2050. Under this scenario the global economy achieves net
zero carbon emissions by 2050, aligned with the IEA’s own
net zero scenario.
The forecasts for natural gas demand and prices under this
scenario are more nuanced due to the assumed role of
natural gas as a global transition fuel and the relatively
rapid decline of oil prices in the future. This position is
particularly apparent in the U.S. market where the resilience
of gas demand is supported through the development of
carbon capture and storage, which supports low carbon
power generation and heating for industrial process as well
as blue hydrogen and ammonia.
AET-1.5 sees global natural gas demand peaking in 2027
and then falling below 2023 levels by 2030, with a
continued decline forecast thereafter. U.S. natural gas
demand remains particularly robust out to 2040 with near-
term policy (i.e. Inflation Reduction Act) support for the
development of carbon capture and storage along with
sustained LNG exports. While overall global natural gas
demand declines from 2027, the rapid decline in global oil
prices has a dramatic impact on the availability of relatively
low-cost associated U.S. gas. Significant levels of
production from the liquids-rich plays in the U.S. (such as
the Permian) become sub-commercial thus cutting off
some of the country’s lowest-cost supplies. In order to
balance the market, higher cost non-associated gas is
required thus driving up the marginal cost of supply.
While U.S. natural gas demand does decline, this decline is
more than offset by the decline in supply from the liquids-
rich basins and thus the U.S. Henry Hub natural gas price is,
perhaps counter intuitively, forecast to increase
significantly in the period to 2032, from $2.61/million Btu
(“MMBtu”) in 2023 to $4.05/MMBtu by 2032. Thereafter,
prices continue to increase through the 2030s and 2040s,
albeit at a slower pace, reaching $4.80/MMBtu by 2050.
IEA APS
This scenario assumes that governments will meet, in full
and on time, the climate commitments they have made,
including their Nationally Determined Contributions and
longer-term net zero emissions targets. This scenario is not
designed to achieve a particular outcome and does not
result in a net-zero world by 2050.
Under APS, there is a pronounced decline in oil demand
driven by the implementation of policies aimed at reducing
oil consumption. Demand gradually declines from ~102
MMBO/d
in 2023 to ~93 MMBO/d in 2030, before an accelerated
decline to 55 MMBO/d by 2050. In conjunction, oil prices
see a similar decline, stabilizing at around $74/bbl in 2030
before declining to $60/bbl by 2050. Global natural gas
demand declines steadily, dropping about 40% from its
2021 peak by 2050. U.S. natural gas prices increase from
$2.61/MMBtu in 2023, reaching their plateau around $3.00/
MMBtu over the 2030s before declining to below $2.70/
MMBtu from 2040 onwards.
IEA STEPS
This scenario is the least ambitious energy transition
scenario used for our portfolio analysis and is designed to
provide a sense of the prevailing direction of energy system
progression, based on a detailed review of the current
policy landscape.
In this scenario, oil demand will grow in the near-term to
2030 to reach 102 MMBO/d. Demand then declines out to
2050, reaching 97 MMBO/d. Global natural gas supply
mirrors the growth pattern of oil, rising steadily to a gentle
peak level in 2030 that plateaus through 2050. U.S. natural
gas prices decline from $4.96/MMBtu in 2023 to $4.00/
MMBtu in 2030. From 2030, price begins to gradually
increase over the next two decade reaching $4.30/MMBtu
by 2050.
DEC’s BASE CASE PRICE SCENARIO
Diversified’s base case price forecasts, which are used for the calculations of net asset value and free cash flow, are based on
the NYMEX forward curves from 2024-2032 for Henry Hub (“HH”) and 2024-2029 for West Texas Intermediate (“WTI”) as of
December 31, 2023. The prices are kept flat in real terms thereafter.
Oil Comparison 2023 - WTI

U.S. Gas Price Comparison 2023

*Diversified Energy’s Henry Hub price is calculated based on 1030 BTU/standard cubic foot
PORTFOLIO IMPACT
We use the published price forecasts for oil and U.S. natural
gas from each scenario to assess the potential impact on
the value of our assets compared to our base case. It is
important to note, however, that this analysis considers
only our current assets. No account is taken of the impact
that future acquisitions or divestitures may have on our
future business value and cashflows.
The following table shows the impact of the three climate
scenarios relative to the base case for our current portfolio,
in terms of net asset value (“NAV”) change in percent
versus base case.
NAV CHANGE % vs. BASE CASE
Scenario |
Portfolio Value Impact (NPV10) |
STEPS |
18% ![]() |
APS |
-24% ![]() |
AET -1.5 |
7% ![]() |
Our NAV change is positive under the Wood Mackenzie
AET-1.5 and IEA STEPS scenarios, driven by two
main factors.
Firstly, both scenarios forecast robust U.S. gas prices out to
2050, at $4.30/MMBtu and $4.80/MMBtu for 2050 under
STEPS and AET-1.5, respectively. The results illustrate our
conservative approach to financial planning, with our Henry
Hub price forecast aligned with the AET 1.5 scenario out to
2030 and staying flat at around $3.50/MMBtu post-2030.
The higher positive NAV change under the STEPS scenario
can be attributed to much higher Henry Hub prices out to
2030 than in our Base Case, which when coupled with
Diversified's front-loaded production outlook, significantly
increases the value of assets. Production volumes between
2024 and 2035 account for over 60% of the total
production between from 2024 to 2048. During this
timeframe, natural gas prices are higher in the STEPS
scenario, averaging ~$4.30/MMBtu versus an average of
~$3.70/MMBtu under AET- 1.5.
Secondly, the strong price outlook is bolstered by our low
cost of production. As a result, we are able to maintain
profitable operations across our portfolio through to 2050.
Our analysis indicates that even in the most carbon
constrained scenario (Wood Mackenzie AET-1.5), our
production would remain resilient and profitable in the
short-, medium- and long-term. This conclusion is
supported by the analysis of related free cashflows,
depicted below, where even under the most aggressive
pricing outlook in AET-1.5, our free cashflow
remains positive.
Unless there are significant changes in the regulatory
environment in the near future, we do not expect to see a
significant financial impact of climate-related risks on our
near-term cash flows. Post-2030, our conservative
commodity price assumptions, used for Diversified’s
financial planning and acquisition and divestiture screening,
position us well to cope with the potential introduction of
carbon taxes in the U.S. or falling commodity prices.
CUMULATIVE UNLEVERED FREE CASH FLOWS UNDER
EACH SCENARIO vs BASE CASE

CARBON COSTS AND REDUCTIONS
In addition to the impacts of the three climate scenarios on
commodity prices, the scenarios also incorporate carbon
price outlooks required to achieve the highlighted primary
energy outcomes. While the IEA acknowledges that these
estimates should be interpreted with caution, the CO2
prices provide some context for the level of price that is
required to promote fuel switching and associated
investment decisions. To assess the impact that carbon
pricing may have on our business, we have utilized the
carbon price forecast for the U.S. for the IEA scenarios and
for developed economies in the Wood Mackenzie AET-1.5
scenario. We have evaluated the implications based of
these carbon prices on our net zero goal (Scope 1 and 2).
Under the APS scenario, carbon prices in the U.S. are
forecast to be $135/MT in 2030 and rise to $175/MT by
2040. STEPS does not incorporate a carbon cost in the U.S.
(at a country level) across the forecast period. The AET-1.5
scenario incorporates carbon prices of $96/MT as soon as
2026, thereafter increasing to $136/MT by 2030 and $173/
MT by 2040.
METHANE INTENSITY TARGETS
(MT CO2e/MMcfe)

Carbon Prices ($/MT) |
|||
Scenario |
2026 |
2030 |
2040 |
IEA STEPS |
N/A |
N/A |
N/A |
IEA APS |
N/A |
135 |
175 |
WM AET 1.5 |
96 |
136 |
173 |
In 2021 we announced our ambitions for near- and long-
term emissions reductions relative to our revised 2020
baseline, with short- and medium-term targets to reduce
Scope 1 methane emissions intensity by 30% by 2026 and
50% by 2030. Based on our revised IPCC 2020 baseline
methane intensity of 1.6 MT CO2e/MMcfe, our targets are
therefore 1.1 MT CO2e/MMcfe by 2026 and 0.8 MT CO2e/
MMcfe by 2030. In addition, we have a long-term goal to
achieve net zero Scope 1 and 2 GHG emissions by 2040.
Our revised IPCC 2020 baseline for CO2 emissions intensity
across both Scopes for 2020 was 2.1 MT CO2/MMcfe.
Using the carbon price assumptions used in each of the
climate scenarios, the potential financial impact associated
with our methane emissions intensity targets in 2030 would
be $0.11/Mcfe under APS and $0.11/Mcfe under AET-1.5. The
carbon cost per Mcfe is calculated using the carbon price
from each scenario and multiplying this by the methane
intensity target for each of the target years, i.e. 2026, 2030
and 2040. As we have already surpassed our 2030
methane reduction target in 2023, the potential financial
impact of our methane emissions will likely be lower than
the calculated value above as we continue to focus our
efforts on de-methanization of our operations. There would
be no cost to our business under STEPS as this scenario
does not incorporate a U.S. carbon price. These figures do
not account for any additional costs from emissions of CO₂.
Although we have not yet set specific targets for reducing
the intensity of our CO₂ emissions, if for the purposes of
this analysis we assume that we can reduce these at the
same rate as the intensity of our methane emissions, we
would expect our total Scope 1 and 2 emissions intensity in
2030 to be 1.05 MT CO2e/MMcfe, implying a total potential
carbon cost in 2030 (covering CO₂ and methane) of just
over $0.14/Mcfe in both APS and AET-1.5 scenarios.
Alternatively, if we take a less optimistic view and assume
that our CO₂ emissions remain at 2020 levels until 2030,
then the total intensity of our emissions would be 1.3 MT
CO2e/MMcfe, implying a total carbon cost in 2030 of close
to $0.18/Mcfe.
We aim to reduce our absolute Scope 1 and 2 GHG
emissions in line to achieve net zero in line with our 2040
goal. We would expect this to reduce the overall carbon
cost to our business from these emissions even in the face
of rising carbon prices. However, we recognize that our
2040 net zero goal assumes that there will still be residual
emissions from our operations which will need to be offset
elsewhere and that we may therefore still incur a carbon
cost associated with those residual emissions. We plan to
build these considerations into our financial models as the
pathway for our emissions after 2030 and for carbon
pricing becomes clearer in the coming years.
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RISK MANAGEMENT
IDENTIFYING, ASSESSING AND MANAGING
CLIMATE-RELATED RISKS AND
OPPORTUNITIES
|
We recognize that the transition to a lower-carbon future,
inclusive of both physical and transition risks, could have
significant implications for our corporate strategy and
could negatively impact our financial results due to lower
demand and lower prices for natural gas and oil. The size
and scope of market-related climate risks are assessed and
quantified through scenario analysis as detailed in the
Strategy section of this TCFD Report. Equally, we recognize
that physical risks, such as extreme rainfall, water stress,
and heat stress, related to climate variability, could impact
our operations. The Strategy section also shows details of
our qualitative analysis of the impact of specific acute and
chronic physical risks on our portfolio, including mitigation
and adaptation actions.
We also actively monitor our performance against our
peers and engage with industry organizations such as the
Natural Gas Sustainability Initiative (“NGSI”) and OGMP to
ensure that our approach to climate risk, particularly the
decarbonization of our operations, follows best practice, as
described elsewhere in this TCFD Report.
This section of the TCFD Report focuses on our risk
management processes, including how we identify, assess,
and manage climate-related risks.
Effective risk management and control is a key component
to the successful execution of our business strategy and
objectives. Under the oversight of the Board’s Audit & Risk
Committee, our Senior Leadership Team developed risk
management review processes which include the oversight
and monitoring of our risk control and mitigation efforts.
These risk management processes were developed to
minimize risks across our operations, support the
achievement of our strategic objectives, and create
sustainable value for our stakeholders.
As part of our ERM program, we seek to assess all potential
risks, including climate-related, affecting stakeholders and
the natural environment and to counteract and mitigate
such risks as effectively and expeditiously as possible. Our
company-wide risk management processes ensure risks are
appropriately identified, assessed, and managed.
RISK IDENTIFICATION
Within the program’s risk identification phase, we capture
potential and emerging risks that could arise as a result of a
change in circumstances or new developments impacting
our company. To identify climate-related risks, we rely on
discussions with business unit leaders across the
organization, the experience and expertise of our Board
members, third-party experts, and our knowledge of
current and emerging industry- or company-specific risks.
Through consistent, robust stakeholder engagement and
our periodic corporate Materiality Assessment with
stakeholders, we also have the opportunity to identify
issues with the greatest impact, whether through risks or
opportunities, on our business. In 2023, climate and climate
management was identified by our stakeholders as a top 25
issue for the Group.
Climate-related risks are classified in alignment with the
TCFD’s description of physical and transition risks, as
described in the Strategy section above.
RISK ASSESSMENT
We assess climate-related risks to our business by utilizing
a scorecard approach, alongside other risk categories
considering their (i) likelihood, (ii) potential impact, and (iii)
speed of impact. For each Principal Risk, we also develop a
list of mitigating activities and other opportunities that may
offset or minimize the risk. In our most recent risk
assessment, we identified Climate as a Principal Risk, and
further, as a Strategic Risk within Diversified’s risk universe
when considering the potential it has to also influence
several other Principal Risks including Corporate Strategy
and Acquisition Risk, Regulatory and Political Risk, and
Commodity Price Volatility Risk.
RISK MANAGEMENT
While we consider risk management the responsibility of all
employees and have empowered them to enhance our
processes and procedures as appropriate to mitigate risks,
a designated Risk Owner is primarily responsible for
implementing the identified mitigating controls and action
plans in order to remove or minimize the likelihood and
impact of the risk before it occurs. As more fully described
below, the Risk Owner also provides updates to Executive
and senior management and the Board, as applicable, on
mitigation efforts of the risk.
Integration of Risk Management Processes into the
Organization’s Overall Risk Management
As described in part in the Governance section of this TCFD
Report, the ownership structure for Climate Risk is shown
below and begins with the Board’s responsibility to ensure
that Climate Risk is ultimately addressed and mitigated
through the Group’s corporate strategy and business
model. Assuming oversight responsibility of Climate Risk on
behalf of the Board, the Sustainability & Safety Committee
monitors company performance on operational climate
mitigation activities and energy transition adaptation plans
by actively engaging with senior management on these
topics.
At the risk level, each Principal Risk is assigned to a Risk
Owner, a member of senior management who identifies and
develops mitigating controls and future opportunities for
mitigation as part of the risk scorecard process. Throughout
the year, under the oversight of an Executive Risk Owner,
the Risk Owner is responsible for actively monitoring and
managing the risk and likewise periodically updating the
risk scorecard.
As part of our ERM program, the role of Risk Owner for
Climate Risk is assigned to the Senior Vice President-
Sustainability. This Risk Owner, other senior management
team members, the Executive Risk Owner, and the CEO
regularly engage in risk discussions across all areas of our
operations, ensuring climate-related risks are integrated
into the Group’s overall and ongoing risk management
considerations, processes and actions. This healthy dialogue
regarding risk creates a culture that highly regards risk
mitigation as a way to preserve and create value for our
stakeholders. As a standing invited guest to the
Sustainability & Safety Committee meetings of the Board,
the Climate Risk Owner also regularly shares the Group’s
actions and mitigating activities regarding Climate Risk.
As a company, we also monitor emerging energy transition
trends and shifting conditions in the energy industry –
ranging from new climate-related regulatory requirements
to global climate impacts – so we are prepared to respond
accordingly. Such a response may include policy or
procedural changes or additional resources or training to
mitigate the emerging risks.
CLIMATE RISK OWNERSHIP STRUCTURE

Additional details of our ERM framework and program are
set out within this Annual Report .
Looking ahead, in 2024, the broader ERM program that
includes Climate Risk will be facilitated by our Senior Vice
President of Accounting who, under the ongoing oversight
of the Audit & Risk Committee, will:
—Engage Executive Management for a full review and
consensus of the Tier I and Tier II risks within our
risk universe;
—Assess the impact of the risks to corporate strategy and
develop relevant KPIs;
—Ensure Risk Owners develop, monitor, manage, and
report risk mitigation activities and opportunities to
Executive Management; and
—Present a full summary of the risks, KPIs, mitigating
actions, and opportunities to the Board.
![]() |
METRICS & TARGETS
Beating Our Emissions Targets on Our
Path Towards Net Zero
|
FOCUS ON SCOPE 1 & 2 EMISSIONS
We have been resolute in our focus on reducing GHG
emissions from our operations throughout 2023 with a
particular focus on reducing methane intensity,
underpinned by our clearly defined targets, relative to the
2020 baseline:
—30% reduction in Scope 1 methane intensity by 2026;
—50% reduction in Scope 1 methane intensity by 2030; and
—Net Zero from Scope 1 and 2 GHG emissions by 2040.
Methane emissions have a magnified impact on climate
change due to their high global warming potential
compared to carbon dioxide, hence our focus on reducing
the methane intensity of our operations. The significant
progress we are making in achieving our targets is reflected
in the reported emissions table below, reflective of our
achievement in 2023 of a methane intensity of 0.8 MT
CO2e/MMcfe, a 50% reduction from our 2020 baseline and
the accomplishment of our 2030 target seven years ahead
of schedule. This is also reflected in year-over-year change
in the portion of Scope 1 methane emission as to total
Scope 1 emissions, or 27% at year-end 2023 versus 38% at
year-end 2022.
Nonetheless, our primary focus remains on continuing near-
term efforts to further reduce the methane intensity of our
operations. This desire is driven by our longer-term goal to
achieve net zero emissions though we move forward
cautiously, within a regulatory environment that is
continuing to evolve and has the potential to increase our
reported emissions with the addition of new requirements
and new source categories not previously reported. As
such, we intend to evaluate those regulations as we
consider new interim targets.
As previously shared, we plan to increase in the medium-
term our efforts to reduce the combustion-derived CO2 in
our operations through efficiency improvements, potential
electrification, and the potential broader use of
renewable energy.
After focusing on true reductions and/or eliminations of
GHG emissions, whether methane or CO2, we will then seek
to address residual operating emissions through the use of
credible offsets and the generation of voluntary and
regulated carbon credits. We believe that this approach
sets us on course for the achievement of our longer-term
goal of net zero Scope 1 and 2 GHG emissions by 2040.
ACTIVITY LEVELS FOR THE KEY STEPS TOWARDS NET ZERO

REPORTING GHG EMISSIONS
To monitor our progress towards achieving our GHG emissions reduction targets and ultimate net zero goal, we collect and
evaluate a comprehensive set of metrics that are material to our performance. These metrics, which include our absolute
Scope 1 and 2 GHG emissions broken down by type and source, are also included in the GHG Emissions table below. Scope 1
and 2 GHG emissions data were assured by ISOS Group Inc. (“ISOS”). ISOS provided a moderate Level II assurance in
accordance with the AccountAbility 1000 Assurance Standard.
GHG Emissions(a)
|
Unit |
2023 |
2022 |
2021 |
Scope 1 Emissions: |
thousand MT CO2e
|
1,561 |
1,820 |
1,631 |
Carbon Dioxide |
thousand MT CO2
|
1,140 |
1,130 |
841 |
Methane(b)
|
thousand MT CO2e
|
420 |
686 |
790 |
Nitrous Oxide |
thousand MT CO2e
|
1 |
4 |
1 |
% Methane |
% |
27 |
38 |
48 |
Scope 1 Methane Intensity |
MT CO2e/MMcfe
|
0.8 |
1.2 |
1.5 |
Scope 1 Methane Intensity - NGSI(c)
|
% |
0.11 |
0.21 |
0.28 |
Scope 1 Emissions Attributable to:(b)(d)
|
||||
Flared Hydrocarbons |
thousand MT CO2e
|
— |
0 |
0 |
Other Combustion |
thousand MT CO2e
|
1,178 |
1,173 |
870 |
Process Emissions |
thousand MT CO2e
|
92 |
67 |
65 |
Other Vented Emissions |
thousand MT CO2e
|
63 |
182 |
295 |
Fugitive Emissions |
thousand MT CO2e
|
228 |
399 |
402 |
Scope 2 Emissions - Total Company(b)
|
thousand MT CO2e
|
61 |
59 |
3 |
Energy consumption |
million kWh |
134 |
128 |
7 |
Total Scope 1 and Scope 2(b)
|
thousand MT CO2e
|
1,622 |
1,879 |
1,634 |
Scope 1 and Scope 2 GHG Emissions
Intensity(b)
|
MT CO2e/MMcfe
|
3.1 |
3.4 |
3.1 |
Air Quality(a)(e)
|
Unit |
2023 |
2022 |
2021 |
Nitrogen Oxide (NOx, excluding N2O)
|
metric tons |
21,520 |
21,546 |
16,126 |
Carbon Monoxide (CO) |
metric tons |
18,448 |
18,530 |
13,842 |
Sulfur Oxide (SOx) |
metric tons |
61 |
108 |
81 |
Volatile Organic Compounds (VOC) |
metric tons |
3,108 |
4,421 |
6,632 |
Particulate Matter (PM Total) |
metric tons |
137 |
140 |
105 |
Totals may not sum due to rounding.
(a)Emissions are reported under a modified Intergovernmental Panel on Climate Change (“IPCC”) report format for EU investors.
(b)Based on a 100-year global warming potential of 28 for methane, in line with IPCC’s Fifth Assessment Report.
(c)Using the Natural Gas Sustainability Initiative protocol, and to support direct comparability among the industry’s producers, represents
methane intensity using methane emissions from production assets only (therefore, excluding gathering & boosting facilities) divided by
gross natural gas production.
(d)Reflects Sustainability Accounting Standards Board categories for reporting Scope 1 GHG emissions (EM-EP-110a.2) in line with the Oil & Gas
– Exploration & Production Sustainability Accounting Standard (October 2018).
(e)2022 and 2021 were recast from previous disclosures to mirror like computations in 2023, inclusive of updated calculation assumptions and
new approved reporting protocols, thus improving year-over-year comparability.
Disclaimer: GHG emissions were calculated per IPCC reporting guidance, which permits best engineering estimates for certain emissions
categories, and which may vary from the prescriptive measures applied under U.S. EPA reporting standards. The source data used in these
calculations were accurate and complete, to the best of our knowledge, at the time they were gathered and compiled. If new data or corrections
to existing data are discovered, the Group may update emissions calculations as permitted and in accordance with industry standards and
expectations. Such updates will be included in future reporting and posted to our website at www.div.energy where such posts may take place
without notice.
We have continued to focus our efforts on the reduction of
methane emissions from our operations with significant
success reflected in achieving our 2030 target seven years
ahead of schedule. As the bulk of our methane emissions
are largely a function of fugitive emissions and natural gas-
driven pneumatics, we have continued to address these
areas. Throughout 2023, we built upon previous
achievements and continued to pursue aggressive leak
detection and repair initiatives, as discussed in our Strategy
review, combined with replacing natural gas-driven
pneumatic devices with compressed air. These activities
have resulted in a 39% year-over-year reduction in absolute
Scope 1 methane emissions to 420 thousand MT CO2e from
686 thousand MT CO2e in 2022. Our Scope 1 methane
intensity improved more than 30% year-over-year to 0.8 MT
CO2e/ MMcfe and contributes to a three-year cumulative
reduction in methane intensity of ~50%.
METHANE INTENSITY LEVELS (2020-2023) vs.
DEFINED TARGETS

Carbon dioxide emissions now account for 73% of our year-
end 2023 total Scope 1 emissions portfolio, an increase from
the prior year’s 62% of Scope 1 emissions though not
surprising given our near-term focus and success on
reducing methane emissions. Year-over-year absolute
Scope 1 CO2 emissions increased by approximately 10
thousand MT CO2 to 1,140 thousand MT CO2. A majority of
Diversified's CO2 emissions are generally attributable to
compressors and vehicle fuel. For 2023, this slight increase
in CO2 emissions was largely attributable to an increase in
liquid fuel emissions as a function of increased produced
water hauling associated with a Central Region acquisition
during the year and refined calculation methodologies.
Nitrous oxide remains an immaterial component of our
overall GHG emissions, totaling just one thousand MT CO2e
in 2023. Further, our location-based Scope 2 GHG emissions
remained largely unchanged year-over-year at ~61 thousand
MT CO2e. As such, the primary drivers of the net reduction
in total absolute Scope 1 and Scope 2 GHG emissions were
the aforementioned significant methane emission
reductions in fugitives and pneumatics, as reflected in the
14% decline from 1,879 thousand MT CO2e in 2022 to 1,622
thousand MT CO2e in 2023. With this reduction, our overall
Scope 1 and Scope 2 GHG emissions intensity declined 9%
from 3.4 MT CO2e/MMcfe in 2022 to 3.1 MT CO2e/MMcfe at
year-end 2023.
YEAR-OVER-YEAR CHANGE IN SCOPE 1 AND 2 EMISSIONS

WATER USAGE
Due to the geographic locations of our assets and the
nature of our business model aimed at acquiring and
operating existing wells rather than drilling new wells, we
do not consider water availability to be a material climate-
related risk for our company. Further, according to the
World Resources Institute’s Aqueduct Water Risk Atlas,
99% of Diversified’s operations are located in states
classified as Low Overall Water Risk areas, using the oil and
gas industry-specific weighting scheme which is most
relevant for our business. At present we have therefore not
set ourselves specific targets regarding water usage.
INCENTIVIZING EMISSIONS
REDUCTION PERFORMANCE
Our commitment to reducing our GHG emissions is
reflected in our executive compensation plans which
include sustainability and climate-related targets.
An ESG-related performance component was first assigned
to a portion of the Executive Directors’ short-term incentive
plan (“STIP”) in 2020. Since then, our Remuneration
Committee and the Board have increased the ESG-related
percentage from 10% to 30%. ESG-related metrics were
also added to Executive Directors’ long-term incentive plan
(“LTIP”) first in 2022 and continue presently through 2024.
For both the STIP and LTIP, a portion of those ESG-related
metrics are specifically climate-related targets tied to
tactical methods to achieve further methane emission
reductions in our journey toward net zero in 2040, and thus
these short- and long-term incentive compensation metrics
are also applicable to members of senior leadership who
play an active role in executing these tactical methods.
2020 |
2021 |
2022 |
2023 |
2024 |
|
STIP |
10% |
25% |
30% |
30% |
30% |
LTIP |
N/A |
N/A |
20% |
20% |
20% |
CONCLUSION
We recognize that the energy transition is a challenging
and complex global issue. However, Diversified continues to
prioritize its ambitious goals of reducing the carbon
intensity of its operations. With sustainability deeply
embedded in every aspect of our organization, we remain
steadfast in integrating climate considerations into our
company culture and decision-making processes.
We have assessed the impact of transition and physical
climate risks on our portfolio. The size and scope of market-
related climate risks were assessed and quantified through
scenario analysis, showing the resilience of our portfolio
even in the Net Zero scenario. Our qualitative assessment
of physical risks, such as extreme rainfall, hurricanes, water
stress, and heat stress, showed we are well-positioned to
mitigate and adapt to these risks, even in a more extreme
‘hothouse world’ scenario, associated with a temperature
increase of 4.3°C by 2100.
Our pragmatic approach to emission reductions, with a
near- and mid-term focus on de-methanization of our
operations, has yielded outstanding results with our 2030
methane intensity reduction target being achieved seven
years ahead of schedule - though we will not slow in our
efforts to capture further emission reductions as we move
forward. Our mission to achieve our long-term target of net
zero in 2040 continues, emboldened by the achievements
we have already made in reducing the methane intensity of
our operations. As we work toward our net zero targets, we
are committed to keeping environmental stewardship at the
forefront of our strategic decision-making.
Managing Our Footprint
Diversified’s commitment to environmental stewardship
is focused on our responsible management of the natural
resources located within the communities we serve, the
safe and permanent retirement of end-of-life assets, our
efficient use of water, and the protection of biodiversity.
Our efforts to manage our environmental footprint start
with Diversified employees, who leverage their expertise
alongside innovative and proven solutions to help
reduce any potential negative impacts resulting from
our operations.
In addition to the previous GHG emissions and air quality
data and accompanying discussion within our
aforementioned TCFD disclosures, below are a number of
environmentally-focused areas within our footprint that are
relevant to our 2023 actions.
WELL RETIREMENT
Through our wholly-owned subsidiary, Next LVL Energy,
Diversified is a leader in well retirement in Appalachia. Next
LVL retires not only end-of-life wells owned by Diversified,
but also wells owned by other oil and gas operators in
Appalachia and abandoned wells with no current owner
that are the responsibility of the state. Further, Next LVL
serves as manager of the federal orphan well retirement
programs in southern Ohio.
ACTUAL WELLS RETIRED

![]() |
DEC wells(a)
|
![]() |
Total wells, including
3rd party(a)
|
(a)Inclusive of 14 and 21 Central Region wells retired during 2022
and 2023, respectively
We retired 201 Diversified wells in Appalachia in 2023,
exceeding our stated objective for the year and significantly
exceeding annual requirements as per our existing state
agreements. We also retired 21 Diversified owned wells in
our Central Region states, bringing total retired company
wells to 222 in 2023.
During the year, the Next LVL team directly retired or
managed the retirement of 182 third-party wells, including
148 state and federal orphan wells and 34 wells for other
third-party operators. When considering both Diversified
and third-party retirements, we plugged a total of 404
wells during the year.
In its first full year of operation under Diversified’s
ownership, Next LVL’s expanded retirement capabilities
now include 14 teams and 17 rigs, well positioning the Group
to remain one of Appalachia’s largest and most active asset
retirement companies. Responsibly retiring end-of-life
assets is an integral part of our environmental stewardship
strategy. Included in this strategy are a rig utilization
optimization program, or a streamlined workflow that
affords more efficient movement of vehicles and equipment
- thus reducing the plausibility of safety incidents while
simultaneously reducing vehicles emissions - and bespoke
well pad restoration and biodiversity protections while
retiring the wells and restoring the site.
WATER MANAGEMENT
Water is a finite and essential resource and thus,
responsible water withdrawal, use, and disposal is
important for our environmental performance. Our
operations are primarily located within areas that qualify as
Low Overall Water Risk, with only 1% located in areas that
have Low to Medium Overall Water Risk and none in areas
beyond Medium Risk, as assigned by the World Resources
Institute’s Aqueduct Water Risk Atlas. Even so, we apply
the same principles of operational efficiency and best
practice to our water use that we apply across our business,
with the goal to: (i) limit freshwater use, (ii) manage our
produced water, and (iii) expand recycling and reuse of
produced water.
Our differentiated business model significantly decreases
our reliance on water and therefore on freshwater
withdrawal, thus alleviating an environmental concern
material to many of our peers engaged in new
development. Given the location of our operations in low
water risk areas, no freshwater was withdrawn in high or
extremely high water stressed areas in 2023.
In 2023, we decreased our annual total water use to less
than one million barrels, or nearly 70% less than the prior
year, primarily as a result of decreased water consumption
for contracted drilling and hydraulic stimulation activities
for third parties during the year. Our own water
consumption is largely related to domestic use and various
well operations, including certain well treatments and asset
retirement activities. This decline in water consumption as
compared to our total gross production resulted in a
significant improvement in our year-over-year water
consumption intensity, as reflected below.
WATER CONSUMPTION INTENSITY(b)
(Bbl of Water per Boe Gross Production)

(b)To improve year-over-year comparability, 2021 and 2022
metrics were revised to reflect updated reporting assumptions
for domestic water use
The main waste associated with our operations is produced
water, a naturally occurring by-product from the
production of natural gas and oil. Therefore, most of our
efforts in water management focus on the handling and
disposal of produced water given the potential
environmental implications of the same. During 2023, our
produced water increased 34% year-over-year to 83
thousand barrels per day, due primarily to our increasing
presence in the Central Region through acquisition.
Our framework for managing produced water effluents
aims to first limit any environmental impacts and to
increase the safety of employees, contractors and
surrounding communities. Then, we focus on operational
efficiencies to reduce waste water, which may include
recycling and reuse efforts as well as seeking innovative
approaches or technologies which can evaporate water
from the production stream to reduce total produced
water or extract heavy elements from the produced water
to allow the now distilled water to be released into
water streams.
SPILL PREVENTION & MANAGEMENT
As an integral aspect of our environmental management
program, Diversified is committed to effectively preventing
spills across our operations. Our strategic approach to spill
prevention includes (i) maximizing the use of well-
maintained pipelines to transport produced liquids, (ii)
utilizing continuous monitoring and automated data
collection where applicable to inform our liquids decision-
making, and (iii) removing out of service or degraded
equipment which could inadvertently contribute to spills.
Our spill intensity rate improved 64% year-over-year largely
as a result of the creation and empowerment of a Spill
Prevention Focus Group in 2023 who developed and
effectuated a plan to better mitigate and manage spill
incidents, starting with a root cause analysis and action
process that included informed data collection and
increased training. Additional contributory actions included
prevention and mitigation awareness from our integrated
operations centers, the increased frequency of equipment
inspections and the use of sacrificial anodes to lower the
rate of naturally occurring corrosion in tanks.
SPILL INTENSITY
(Bbl of Spills per MBbl Gross Liquids Production)

BIODIVERSITY
At Diversified, we are committed to safeguarding nature
and conserving biodiversity and ecosystems. We prioritize
responsible stewardship of our leaseholds and assets, and
focus on (i) minimizing environmental disruption though
our “Avoid, Mitigate, Restore and Offset” approach, (ii)
protecting sensitive species, habitats, and waterways, and
(iii) enhancing biodiversity and ecosystems within our
operational footprint. We achieve this through strong
oversight, risk management and standardized procedures,
recognizing that biodiversity protection is central to our
sustainable operations.
As part of our zero net deforestation goal and biodiversity
commitment, our 2023 efforts included a wide spectrum of
ecosystem enhancement activities, starting with bespoke
well pad restoration following well retirements for both
Diversified and third parties. For our largest project in 2023,
we partnered with West Virginia State University and its
Extension Service, along with over 500 individual
volunteers, to enable the planting during the year of nearly
11,000 bare-root seedlings and containerized trees in
municipal parks, underserved neighborhoods, degraded
forests, university campuses, and more.
Separately, we maximized the use of existing rights of way to
avoid potential stream and wetlands impacts during pipeline
extension work and effectuated projects independently
identified and developed by our summer intern which
included building and installing woodpecker houses in
various locations within our West Virginia footprint.
Safety in Focus
‘Safety-No Compromises’ has been and will continue to be
our utmost daily operational priority. While safety is
inherently the primary functional responsibility of the EHS
team, we recognize that safety is every employee’s
responsibility and priority - no matter the employee’s
location, position or job function. We recognize that
comprehensive and effective management practices
underpin the safety of our employees.
We take a data-driven approach to safety that includes an
electronic dashboard which contains key EHS metrics and is
readily accessible by all employees at any time. Thus, our
approach to safety training for our employees is both
preventative and responsive, utilizing the current and
historical results and trends from this dashboard -
partnered with amnesty-based Good Catch/Near Miss
reporting, computer-based and fit-for-purpose training, and
root cause analysis - to drive our safety training practices
and protocol as we work diligently to uphold a zero-harm
working environment.
PERSONAL SAFETY
While we take this approach to keep safety top of mind for
employees while on the job and despite an 84% increase in
Good Catch/Near Miss reporting, 2023 was a challenging year
for personal safety performance. We recorded a Total
Recordable Incident Rate (“TRIR”) of 1.28, up 75% from the
0.73 recorded in 2022 and higher than our 2023 target of 1.03.
This year’s incident rate was driven primarily by an increase
in the total number of incidents, which were attributable in
part to short service employees with less than one year of
service under Diversified’s safety culture, which we are
seeking to address through our safety programs.
As with any incident and no matter the severity, our desire
for a zero harm working environment and our data-driven
approach to change management encourage us to (i) take
appropriate time to review the circumstances, causes and
corrective actions of these incidents and (ii) use these
results as a catalyst for improving forward
safety performance.
Our lessons learned to date in the review of our 2023
incidents reinforce what we already know - the task of
promoting safety is never finished - and highlight where our
safety program needs improvement, specifically in our
accountability and corrective action following an incident.
We have created a more robust work-flow for
accountability for safety incidents and formed a task force
to evaluate causal factors. So far, we have identified
opportunities for increased instruction for front line and
mid-level managers. and we will utilize the efforts of our
task force to drive additional, appropriate
program improvements.
Moving forward in 2024, while we will continue to promote
our Good Catch/Near Miss amnesty reporting program, we
are also updating our personal safety metrics to include
both TRIR and a severity rate, as measured by Lost Time
Incident rate, to provide enhanced clarity to our
safety performance.
TRIR
Per 200,000 work hours

DRIVER SAFETY
Our field operations span across nine states, and this
geographic dispersion means employees may spend
significant time traveling on the roads, as evidenced by the
more than 24 million miles driven during the year. For this
reason, improving driver safety means reducing both miles
driven, which we accomplish in part through our remote
monitoring programs and efficient well tender routing, and
the accidents that occur during those miles. We seek zero
preventable motor vehicle accidents (“MVA”) during the
calendar year, and aim to incentivize accident-free driving
by offering our field teams annual safe driving awards and
leveraging our MVA metric in a portion of executive and
senior leadership short-term compensation.
Our 2023 MVA is 0.55 incidents per million miles driven, a
20% improvement from the 0.69 recorded in 2022.
VEHICLE SAFETY
Vehicle Incidents (“MVA”)

![]() |
![]() |
MVA |
— |
Miles Driven |
PIPELINE AND PROCESS SAFETY
We operate a full complement of natural gas production,
gathering, transmission, and storage assets, including
thousands of miles of pipeline. To keep employees, our
communities, and the environment safe and protected, we
deploy rigorous monitoring and safety measures, engage in
regular maintenance, focus on operator training, maintain
well-documented operational and safety records, and utilize
state of the art technologies to aerially survey our systems.
Reflective of our commitment to asset integrity
management, during 2023 we were audited by 16 various
state and federal regulatory agencies and received zero
non-compliance citations with civil penalties for our
operational assets and compliance programs.
Our Employees
We are committed to building a workplace that seeks to
attract and retain a talented and diverse staff by providing
attractive jobs with competitive salaries and meaningful
benefits, fostering a unified company culture, offering
equitable growth and development opportunities, and
creating a collaborative and enjoyable work environment
where all employees feel valued and supported in the work
they do.
Though our various operations encompass distinct
activities, we view our corporate and individual employee
actions through the lens of a single, unified OneDEC
approach that drives a culture of operational excellence
fostered through the integration of people and the
standardization of processes and systems. This OneDEC
approach supports and encourages company-wide
initiatives by ensuring alignment of our corporate and
sustainability goals with individual or collaborative action
supported by financial investment and well understood
principles and policies.
Regarding these principles and polices, during the year we
refreshed our Employee Relations Policy which defines
Diversified’s role in prioritizing employee well-being while
promoting an equal opportunity work environment. We also
updated our Employee Handbook to include new policies
and programs that offer additional opportunities and
benefits for employees. Finally, we developed a new
employee-specific Code of Business Conduct & Ethics
which serves as a framework for ethical decision-making,
helps ensure that all employees understand the
expectations and consequences of their actions, and
creates a safe, respectful and professional work
environment for all employees.
EMPLOYEE ENGAGEMENT
During the year, we capitalized on various opportunities to
promote employee engagement with members of
management and the Board. For example, executive
management held town hall meetings and in-the-field
interactions with employee groups, providing a platform for
the employees to receive direct updates on corporate
initiatives and developments and to ask questions directly
of executive and senior management. The Board’s Non-
Executive Director Employee Representative, Ms. Sandra
(Sandy) Stash, accompanied our Board Chairman in the fall
of 2023 on an asset and employee field visit in Texas,
meeting with employees to ensure the views of the
workforce are considered by the Directors. The Employee
Representative role was established in compliance with the
UK Corporate Governance Code, and 2023 was the third
full year of Ms. Stash’s tenure in this regard.
The valuable feedback from these meetings, along with that
resulting from our corporate-wide Employee Experience
Survey, is used to strengthen future employee engagement
and initiatives. We also regularly conduct new hire surveys
regarding the onboarding process as well as exit
interviews, both important tools to further improve
employee experiences.
In line with industry standards in the country of employment,
our employees maintain a range of relationships with union
groups. We have not previously experienced labor-related
work stoppages or strikes and believe that our relations with
our employees are satisfactory.
WORKFORCE DIVERSITY
The vast majority of our employee base at December 31,
2023 consists of production employees which includes
our upstream, midstream, and asset retirement field
personnel. All other employee positions, including back
office, administrative and executive positions, comprise
production support roles. Since inception of the Group, and
in alignment with our U.S.-based assets, all employees are
located in the U.S.
At Diversified, 11% of our total workforce at year-end was
made up of females (as self-reported), slightly higher than
the prior year-end and, in part, a function of our hiring
practices in 2023 where we hired female candidates at a
higher rate than female applications received (17% versus
14%, respectively, as self-reported). Ethnically diverse hiring
continues to be a focus. Our applicant data reflects that we
often have the least minority applicants per available job
opening in areas where we have some of the most available
openings. Likewise, we see a large number of minority
applications in a few areas where we have the least number
of annual openings. As always, we seek to enhance the
diversity of our employee base, ensuring our local
workforce mirrors the local population diversity, while also
striving to hire the best candidate for the position,
regardless of diversity characteristic.
At December 31, 2023, Senior Management, including the
executive committee and direct reports and excluding the
Executive Director, consisted of 103 employees, including
35 females (34%) and 68 males (66%).
At Diversified, we are dedicated to actively fostering an
environment of welcoming and belonging throughout all
facets of our business while demonstrating our company
principle to “value the dignity and worth of all individuals.”
Therefore, we utilize our talent acquisition team to seek and
develop programs and opportunities that allow us to
increase our diversity when hiring.

2023 PRODUCTION EMPLOYEES
|
2023 PRODUCTION SUPPORT EMPLOYEES
|
![]() |
![]() |
2022 PRODUCTION EMPLOYEES
|
2022 PRODUCTION SUPPORT EMPLOYEES
|
![]() |
![]() |
TRAINING & DEVELOPMENT
We are committed to building a workplace that fosters
equitable growth opportunities and encourages human
capital and career development for all employees. We offer
several development programs and trainings to promote
the professional growth of employees, including our
existing Educational Assistance Program that offers tuition
reimbursement for advanced training in an employee’s field
of focus or a field that facilitates promotion opportunities.
In 2023, the Group also piloted a new Leadership Impact
Training (“LIT”) program for 40 managers across the
organization. The LIT is a Franklin Covey facilitated program
which includes a 360° feedback assessment that will drive a
personalized leadership development program for each
participant to better prepare participants for expanded
future leadership roles at Diversified. Based on overwhelming
positive feedback on the program, the Group intends to
continue this leadership program in 2024 and to introduce a
new LinkedIn Learning development program for
approximately 500 employees which also includes
personalized professional development curriculums.
TALENT ACQUISITION & RETENTION
Attracting and retaining talented and diverse staff is key to
our success as a business, and we remain focused on
providing attractive jobs with competitive salaries.
including hiring locally to build our long-term pipeline of
talent. In 2023, most of our new hires were from the local
communities in which we operate. Our commitment to local
hiring is indicative of our larger dedication to supporting
economic development in the areas in which we work.
Further, our commitment to hiring a diverse workforce was
bolstered this year with three unconscious bias training
programs undertaken by 350+ managers and leaders to
help them recognize potential bias present during the
interview, recruiting and promotion processes.
In addition to providing development programs and
trainings to promote career development for existing
employees, our hiring efforts also include utilizing our
summer internship and scholarship programs as a potential
employment pipeline for diverse candidates. We were
pleased to expand our internship program this year to
include 18 interns, surpassing our 2023 goal of hiring 15
interns. These interns included 15 traditional summer interns
who worked in various departments within the Group while
the other three interns were part of a local community
college’s workforce development initiative that allows
students to take technical courses toward a degree while
gaining paid work experience in their field of study.
Our total corporate turnover rate in 2023 was 17.1%, a slight
decrease over the prior year’s turnover of 17.6%.
Our Communities
SOCIO-ECONOMIC IMPACT
Diversified assumes a vital role in supporting communities
across our 10-state operational footprint. By providing our
communities with employment opportunities underpinned
by competitive salaries and excellent benefits, state and
local tax revenues, royalty payments, and other direct and
indirect investments, we contribute significantly to the
economies of these states and, in doing so, positively
impact the communities where we operate.
Since 2021, we have commissioned an independent third-
party to conduct an analysis on the collective direct and
indirect economic impact we have across our 10-state
footprint. The analysis leverages financial and other data
from across our operations to assess the net impact we
have at the local, state and national level, and allows us to
illustrate the value of our contributions to stakeholders and
other interested parties. In the last year alone, for example,
we have contributed more than one billion dollars to the
U.S. GDP when considering both the direct and ancillary
impacts of our operations.
For example, in calendar year 2023, we provided more than
$500 million in ancillary labor income and generated more
than 6,300 ancillary jobs. These ancillary jobs, when
coupled with the ~1,600 employees we had at year-end
2023, highlight Diversified’s total employment impact of
nearly 8,000 jobs during the year. Year-over-year
operational expenditures across our footprint also
increased, but more substantially in states like Texas where
we grew through acquisition in 2023, therefore leading to
significant increases in economic benefit through job
creation within that state.
Beyond these economic benefits, employees across our
states continue to contribute to their communities through
volunteerism and donations, and Diversified is committed
to supporting these efforts.
COMMUNITY OUTREACH AND ENGAGEMENT
We are privileged to live and work in the 10 states across
our operational footprint. We believe with that privilege
and social license to operate comes a responsibility to
support those very communities in which we live and work,
and we recognize the long-lasting positive impact we can
have on both our communities and our business by
giving back.
Through our Community Giving and Engagement program,
we support organizations that have a positive, direct
impact on our communities. During 2023, through our grant
program and other corporate initiatives, we contributed
$2.1 million to more than 120 different charitable, education
related, and community and stakeholder engagement and
outreach organizations, including significant contributions
in geographic regions with large percentages of diverse
and/or socio-economically disadvantaged populations. Our
program is established around three main focus areas and
with the ultimate goal to support community initiatives that
fall under one or more of these areas: (1) community
enrichment, (2) education and workforce development and
(3) the environment. During 2023, our financial and human
capital supported organizations that included childhood
education, with emphasis on STEM (science, technology,
engineering and math), secondary and higher education,
children and adult physical and mental health and wellness,
environmental stewardship and biodiversity, fine arts for
children, food banks and meal programs, military and
veteran support groups, community and volunteer first
responders, and local infrastructure.
In addition to supporting employee volunteerism with these
and other deserving organizations, in 2023 we officially
launched the dollar-to-dollar matching gift program,
providing a company match on employee contributions up
to $1,500 per employee per year, where we matched
nearly $100 thousand in donations from employees during
the year.

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, 2023:
Our stakeholders are the many individuals and
organizations that are affected by our operations and with
whom we seek to proactively and positively engage on a
regular basis. 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 responses and information.
We maintain several communication methods that afford
two-way engagement with our stakeholder groups,
including personal contact via face-to-face or telephone
conversation, email exchange, company reports, press
releases, investor presentations or conference participation
and other company engagement.
As the owner and operator of long-life assets, we naturally
make decisions that consider 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 table provides a summary of stakeholder
engagements from 2023.
OUR STAKEHOLDERS
![]() |
Employees |
Action and Engagement
Our CEO and other executive management periodically
conduct town hall meetings and field visits to personally
and directly engage 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 our
updated corporate-wide Employee Experience Survey, 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.
|
We know our employees are our greatest asset and
therefore 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 that diversity and the contribution it affords.
Key Areas of Focus
—Incident management
—Employee, driver and process safety
—Diversity and equal opportunity
—Employee development
—Workplace culture
| ||
![]() |
Communities |
Action and Engagement
Through our formalized Community Giving and
Engagement Program and other corporate initiatives,
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, and municipal services
throughout our 10-state footprint. We were especially
pleased to support children’s initiatives which included
purchasing and distributing, for the third consecutive
year, more than 1,200 winter coats in the Central
Region through Operation Warm, and participating in
the U.S. Marine Corp Reserve Toys-for-Tots Christmas
gift program. We also supported the purchase of
back-to-school supplies for elementary classrooms
across our footprint and separately collected and
donated more than 4,200 books to local schools and
libraries. Further, we supported U.S. veteran-focused
programs that seek to promote mental health healing
and wellness among combat-wounded veterans or
those suffering with post-traumatic stress disorder.
|
We actively seek to 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.
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
—Socio-economic investment and outreach
—Local hiring
|
![]() |
Land and Mineral Owners |
Action and Engagement
During the year, our employees responded to nearly 34
thousand inquiries from our land and mineral owners
through our in-house call center and recorded ~800
personal visits with landowners. We also distributed
approximately $237 million in royalty payments
during 2023.
|
We seek to develop and maintain trusted relationships with
our land and mineral owners with the recognition that these
relationships are key to our business philosophy and ability
to achieve our operational goals.
Key Areas of Focus
—Royalty payments
—Incident management
—Effective grievance mechanisms
—Environmental protection
| ||
![]() |
Equity and Debt Investors |
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,
COO, SVP-Investor Relations, SVP-Sustainability, SVP-
EHS and/or Board Chairman, as applicable. The Annual
General Meeting (“AGM”) also provides an opportunity for
all 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, our recent ABS
transactions, inclusive of our sustainability-linked Credit
Facility, have included interest rate impacts tied to certain
of these sustainability targets.
|
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.
Key Areas of Focus
—Emissions reductions
—Climate risk and energy transition
—Incident management
—Risk management
—Corporate Governance
—Financial stability
—Access to funding
| ||
![]() |
Governments and Regulators |
Action and Engagement
Executive and operational management engage with
federal, state and local regulators to address legislative,
regulatory and operational matters important to our
business and our industry. With risk identification and
protection of the local environment and biodiversity in
mind, we proactively and fully engage all applicable
regulatory agencies before commencing a project to
ensure transparent dialogue during the completion and
approval of applicable environmental assessments and
related actions.
We also proactively and transparently engage with
regulatory agencies throughout the year to keep them
appraised of our operational and well retirement activities
and to provide objective and measurable progress
indicators. Our Next LVL well retirement subsidiary
supports company efforts to exceed annual state
plugging requirements while also supporting the well
retirement needs of other oil and gas operators in the
Appalachia Basin as well as the states in their respective
federal orphan well retirement programs.
|
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
|
![]() |
Suppliers and Customers |
Action and Engagement
We use local suppliers and vendors 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 suppliers, this
real-time monitoring helps to ensure our suppliers are
providing us with the necessary product and service
quality to meet the expectations of our stakeholders and
support ongoing agreements with those suppliers who
satisfy our safety thresholds.
We delivered 821 MMcfepd in 2023 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.
|
Our production is essential to supporting modern life. 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.
We strive to develop strong relationships with our suppliers
that are built on trust, transparency and quality products
and services.
Key Areas of Focus
—Incident management
—Process safety
—Procurement management
—Access to funding
| ||
![]() |
Joint Operating Partners |
Action and Engagement
We fulfill our responsibility as operator by responsibly
managing the wells, ensuring payment of related
expenses, and distributing applicable revenues and
royalties from the wells’ commodity sales.
|
As operator, we work on behalf of our joint operating
partners to safely and efficiently manage the assets and
deliver our products.
Key Areas of Focus
—Access to funding
—Risk management
—Employee and process safety
—Accident prevention
| ||
![]() |
Industry Associations |
Action and Engagement
Through our active participation and the sharing of
operating best practices, technical knowledge and
legislation updates, we believe that these associations
add value to our business, support our industry at large
and protect the interests of our stakeholders.
Collaborative engagements in these associations provide
us with a platform to help collectively advance the sector
and industry as a whole. Our leadership’s participation in
industry associations includes participation in national,
regional and state associations in West Virginia, Virginia,
Kentucky, Pennsylvania, Ohio, Oklahoma, Texas,
and Louisiana.
We are especially proud of employees’ involvement and
leadership roles in organizations like the Women’s Energy
Network of West Virginia which seeks to empower
women across the energy value chain and the recognition
of our efforts in receiving both the Industry Innovation
award (for use of innovative technologies in emissions
detection) and Individual Excellence award (for long-
standing, proven leadership in the industry) as conveyed
by the Virginia Department of Energy.
|
Recognizing the benefit of collective and collaborative
efforts among industry peers, we are actively involved in
leadership and other roles in industry associations within
the states in which we operate.
Key Areas of Focus
—Incident management
—Environmental protection
—Risk management
—Industry advocacy and leadership
—Accident prevention
—Employee and driver safety
—Landowner engagement
|
Non-Financial & Sustainability Information Statement
This section of the Strategic Report constitutes our Non-Financial & Sustainability Information Statement, produced to comply
with the Non-Financial & Sustainability Reporting Directive requirements from sections 414CA and 414CB of the UK Companies
Act 2006.
The table below sets out where relevant information can be found within this Annual Report & Form 20-F. Additional
information will be available in our Sustainability Report or on our website at www.div.energy. Our Policies can be found on
our website at www.div.energy.
Reporting Requirement |
Policies |
Reference within this
Annual Report & Form 20-F
|
Page |
Environmental Matters |
Code of Business Conduct & Ethics |
||
EHS |
|||
Climate |
|||
Business Partners |
|||
Biodiversity |
|||
Employees |
Employee Relations |
||
Anti-Bribery & Corruption |
|||
Compliance Hotline &
Whistleblowing
|
|||
Code of Business Conduct & Ethics |
|||
Human Rights |
|||
Securities Dealing |
|||
Human Rights |
Code of Business Conduct & Ethics |
||
Human Rights |
|||
Modern Slavery |
|||
Business Partners |
|||
Social Matters |
Code of Business Conduct & Ethics |
||
EHS |
|||
Human Rights |
|||
Tax |
|||
Anti-Corruption & Anti-Bribery |
Anti-Bribery & Corruption |
||
Compliance Hotline &
Whistleblowing
|
|||
Business Model |
Code of Business Conduct & Ethics |
||
Principal Risks and Uncertainties |
Compliance Hotline &
Whistleblowing
|
||
Non-Financial KPIs |
Code of Business Conduct & Ethics |
||
EHS |
|||
Climate |
|||
Reporting Requirement |
Reference within this Annual Report & Form 20-F
|
Page |
Board oversight of climate-related risks and
opportunities.
|
||
Identifying, assessing and managing climate-related risks
and opportunities.
|
||
How processes for identifying, assessing and managing
climate-related risks are integrated into the overall risk
management process.
|
||
Principal climate-related risk and opportunities arising in
connection with operations.
|
||
Time periods by reference to which risks and
opportunities are assessed.
|
||
Actual and potential impacts of the principal climate-
related risks and opportunities on the business model and
strategy.
|
||
Analysis of the resilience of the business model and
strategy, taking into consideration different climate-
related scenarios.
|
||
Targets used by the organization to manage climate-
related risks and to realize climate-related opportunities
and of performance against those targets.
|
||
KPIs used to assess progress against targets used to
manage climate-related risks and realize climate-related
opportunities and of the calculations on which those KPIs
are based.
|

A Message from Our
Chief Financial Officer
“ |
|||
I am very pleased to report that 2023
was an outstanding year for Diversified,
with record financial results and solid
operational performance from our
assets.
|
Financial Review
Before penning my first CFO letter after many years, I took
a few moments to go back through all of Diversified’s
annual reports since going public in 2017. It was satisfying,
though not surprising, to see the common threads of our
firm's strategy and values woven through those pages-
reliable production, stable cash flows, durable margins and
consistent shareholder distributions. As I look ahead, I
intend to reinforce a disciplined financial approach to our
business that will provide flexibility and resiliency
throughout commodity price cycles. Additionally, we will be
diligent in expense management while looking to drive
further capital efficiency improvements through
the business.
I am very pleased to report that 2023 was an outstanding
year for Diversified, with record financial results and solid
operational performance from our assets. Adjusted EBITDA
was above expectations and reached a record level for the
Group. An improvement of approximately 3% in our total
per unit operating expense helped to deliver margins that
were approximately 50% or better for the sixth straight
year, with 2023 coming in at approximately 52%.
2023 began with an accretive acquisition in the Central
Region, allowing the opportunity to capture operational
synergies while increasing exposure to the premium Gulf
Coast markets pricing and the long-term demand pull from
the growth in LNG markets.
Additionally, we commenced trading on the New York
Stock Exchange (NYSE), an important strategic milestone
for the Company. The U.S. listing will enhance trading
liquidity and facilitate increased ownership from U.S.
domestic equity funds.
We ended the year with a highly successful transaction that
was both value-enhancing and deleveraging. This
approximately $192 million asset sale resulted in an
approximate 10% reduction in net debt.
Moreover, we have once again demonstrated that our
disciplined acquisition strategy allows us to be selective
and thoughtful in our approach but unwavering in our quest
to extract value when the opportunity affords itself.
You will find the full financial results of our operations on
the following pages, which I hope will be helpful as you
review our performance.
We expect 2024 to be a year of transition for both the
world and Diversified. Macroeconomic and geopolitical
developments remain a concern in the short term, with
limited visibility on how inflation, as well as other
disruptions, might impact energy prices, particularly natural
gas prices. We move into 2024 in a sound financial position,
with a focus on further reducing our debt, investing in
accretive acquisitions, and providing returns to our
shareholders. It is shaping up to be another exceptional
year for Diversified, one in which we will focus on playing
offense and being opportunistic, as we have historically
found this commodity price backdrop to provide a
tremendous opportunity to creatively grow our business
and ultimately create value for shareholders.
I want to thank our shareholders, debt holders, banks,
analysts, rating agencies, insurers, business partners, and
key advisors for their continued trust in Diversified and their
ongoing support to execute the proper measures to
strengthen our company and be in the best position to take
advantage of the opportunities we see ahead. I also want to
thank all of our dedicated, caring employees that are
focused on the safe production of American energy and are
also focused on continuing to deliver superb results for
their team members and our shareholders.

Bradley G. Gray
President & Chief Financial Officer
March 19, 2024
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 intend to continue to make, strategic
acquisitions to solidify 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 $1.1 billion during the years
ended December 31, 2023, 2022 and 2021, comprised of:
—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 Assets 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 assets;
—February 2022: Certain plugging infrastructure in the
Appalachian Region;
—December 2021: The Tapstone Acquisition, where we
acquired working interests in certain upstream assets,
field infrastructure, equipment and facilities within the
Central Region in conjunction with Oaktree;
—August 2021: The Tanos Acquisition, in which we
acquired working interests in certain upstream assets
field infrastructure, equipment and facilities in the
Central Region in conjunction with Oaktree;
—July 2021: The Blackbeard Acquisition, in which we
acquired certain upstream assets and related gathering
infrastructure in the Central Region;
—May 2021: The Indigo Acquisition, in which we acquired
certain upstream assets and related gathering
infrastructure in the Central Region;
Our strategic acquisitions may affect the comparability of
our financial results with prior and subsequent periods. We
intend to continue to selectively pursue strategic
acquisitions to further strengthen our competitiveness. We
will evaluate and execute opportunities that complement
and scale our business, optimize our profitability, help us
expand into adjacent markets and add new capabilities to
our business. The integration of acquisitions also requires
dedication of substantial time and resources of
management, and we may never fully realize synergies and
other benefits that we expect.
Recent Developments
On March 19, 2024 we announced we entered into a
conditional agreement to acquire Oaktree’s proportionate
interest in the previously announced Indigo, Tanos III, East
Texas and Tapstone acquisitions for an estimated gross
purchase price of $410 million before customary purchase
price adjustments. The transaction is expected to be funded
through a combination of existing and expanded liquidity,
the assumption of Oaktree’s proportionate debt of
approximately $120 million associated with the ABS VI
amortizing note and approximately $90 million in deferred
cash payments to Oaktree. Additional liquidity for the
transaction may be generated from non-core asset sales
and the potential issuance of a private placement preferred
instrument.
Segment Reporting
We are an independent owner and operator of producing
natural gas and oil wells with properties located in the
states of Tennessee, Kentucky, Virginia, West Virginia, Ohio,
Pennsylvania, Oklahoma, Texas and Louisiana. Our strategy
is to acquire long-life producing assets, efficiently operate
those assets to maximize cash flow, and then to retire
assets safely and responsibly at the end of their useful life.
Our assets consist of natural gas and oil wells, pipelines and
a network of gathering lines and compression facilities that
are complementary to our core assets. We acquire and
manage these assets in a complementary fashion to
vertically integrate and improve margins rather than
managing them as separate operations. Accordingly, when
determining operating segments under IFRS 8, we
identified one operating segment that produces and
transports natural gas, NGLs and oil in the United States.
Refer to Note 2 in the Notes to the Group Financial
Statements for a description of our segment reporting.
RESULTS OF OPERATIONS
Please refer to the APMs section within this Annual Report & Form 20-F for information on how these metrics are calculated
and reconciled to IFRS measures. Discussion related to prior period results can be found in the Results of Operations section of
our 2022 Annual Report on our website at https://ir.div.energy/reports-announcements.
Year Ended |
||||
December 31, 2023 |
December 31, 2022 |
Change |
% Change |
|
Net production |
||||
Natural gas (MMcf) |
256,378 |
255,597 |
781 |
—% |
NGLs (MBbls) |
5,832 |
5,200 |
632 |
12% |
Oil (MBbls) |
1,377 |
1,554 |
(177) |
(11%) |
Total production (MMcfe) |
299,632 |
296,121 |
3,511 |
1% |
Average daily production (MMcfepd) |
821 |
811 |
10 |
1% |
% Natural gas (Mcfe basis) |
86% |
86% |
||
Average realized sales price
(excluding impact of derivatives settled in cash)
|
||||
Natural gas (Mcf) |
$2.17 |
$6.04 |
$(3.87) |
(64%) |
NGLs (Bbls) |
24.23 |
36.29 |
(12.06) |
(33%) |
Oil (Bbls) |
75.46 |
89.85 |
(14.39) |
(16%) |
Total (Mcfe) |
$2.68 |
$6.33 |
$(3.65) |
(58%) |
Average realized sales price
(including impact of derivatives settled in cash)
|
||||
Natural gas (Mcf) |
$2.86 |
$2.98 |
$(0.12) |
(4%) |
NGLs (Bbls) |
26.05 |
19.84 |
6.21 |
31% |
Oil (Bbls) |
68.44 |
72.00 |
(3.56) |
(5%) |
Total (Mcfe) |
$3.27 |
$3.30 |
$(0.03) |
(1%) |
Revenue (in thousands) |
||||
Natural gas |
$557,167 |
$1,544,658 |
$(987,491) |
(64%) |
NGLs |
141,321 |
188,733 |
(47,412) |
(25%) |
Oil |
103,911 |
139,620 |
(35,709) |
(26%) |
Total commodity revenue |
$802,399 |
$1,873,011 |
$(1,070,612) |
(57%) |
Midstream revenue |
30,565 |
32,798 |
(2,233) |
(7%) |
Other revenue |
35,299 |
13,540 |
21,759 |
161% |
Total revenue |
$868,263 |
$1,919,349 |
$(1,051,086) |
(55%) |
Gain (loss) on derivative settlements
(in thousands)
|
||||
Natural gas |
$177,139 |
$(782,525) |
$959,664 |
(123%) |
NGLs |
10,594 |
(85,549) |
96,143 |
(112%) |
Oil |
(9,669) |
(27,728) |
18,059 |
(65%) |
Net gain (loss) on commodity derivative
settlements(a)
|
$178,064 |
$(895,802) |
$1,073,866 |
(120%) |
Total revenue, inclusive of settled hedges |
$1,046,327 |
$1,023,547 |
$22,780 |
2% |
Year Ended |
||||
December 31, 2023 |
December 31, 2022 |
Change |
% Change |
|
Per Mcfe Metrics |
||||
Average realized sales price |
||||
(including impact of derivatives settled in cash) |
$3.27 |
$3.30 |
$(0.03) |
(1%) |
Midstream and other revenue |
0.22 |
0.16 |
0.06 |
38% |
LOE |
(0.71) |
(0.62) |
(0.09) |
15% |
Midstream operating expense |
(0.23) |
(0.24) |
0.01 |
(4%) |
Employees, administrative costs and professional
services
|
(0.26) |
(0.26) |
— |
—% |
Recurring allowance for credit losses |
(0.03) |
— |
(0.03) |
(100%) |
Production taxes |
(0.21) |
(0.25) |
0.04 |
(16%) |
Transportation expense |
(0.32) |
(0.40) |
0.08 |
(20%) |
Proceeds received from leasehold sales |
0.08 |
0.01 |
0.07 |
700% |
Adjusted EBITDA per Mcfe |
$1.81 |
$1.70 |
$0.11 |
6% |
Adjusted EBITDA Margin |
52% |
49% |
||
Other financial metrics (in thousands)
|
||||
Adjusted EBITDA |
$542,794 |
$502,954 |
$39,840 |
8% |
Operating profit (loss) |
$1,161,051 |
$(671,403) |
$1,832,454 |
(273%) |
Net income (loss) |
$759,701 |
$(620,598) |
$1,380,299 |
(222%) |
Year Ended |
||||
December 31, 2022 |
December 31, 2021 |
Change |
% Change |
|
Net production |
||||
Natural gas (MMcf) |
255,597 |
234,643 |
20,954 |
9% |
NGLs (MBbls) |
5,200 |
3,558 |
1,642 |
46% |
Oil (MBbls) |
1,554 |
592 |
962 |
163% |
Total production (MMcfe) |
296,121 |
259,543 |
36,578 |
14% |
Average daily production (MMcfepd) |
811 |
711 |
100 |
14% |
% Natural gas (Mcfe basis) |
86% |
90% |
||
Average realized sales price
(excluding impact of derivatives settled in cash)
|
||||
Natural gas (Mcf) |
$6.04 |
$3.49 |
$2.55 |
73% |
NGLs (Bbls) |
36.29 |
32.53 |
3.76 |
12% |
Oil (Bbls) |
89.85 |
65.26 |
24.59 |
38% |
Total (Mcfe) |
$6.33 |
$3.75 |
$2.58 |
69% |
Average realized sales price
(including impact of derivatives settled in cash)
|
||||
Natural gas (Mcf) |
$2.98 |
$2.36 |
$0.62 |
26% |
NGLs (Bbls) |
19.84 |
15.52 |
4.32 |
28% |
Oil (Bbls) |
72.00 |
71.68 |
0.32 |
—% |
Total (Mcfe) |
$3.30 |
$2.51 |
$0.79 |
31% |
Revenue (in thousands) |
||||
Natural gas |
$1,544,658 |
$818,726 |
$725,932 |
89% |
NGLs |
188,733 |
115,747 |
72,986 |
63% |
Oil |
139,620 |
38,634 |
100,986 |
261% |
Total commodity revenue |
$1,873,011 |
$973,107 |
$899,904 |
92% |
Midstream revenue |
32,798 |
31,988 |
810 |
3% |
Other revenue |
13,540 |
2,466 |
11,074 |
449% |
Total revenue |
$1,919,349 |
$1,007,561 |
$911,788 |
90% |
Year Ended |
||||
December 31, 2022 |
December 31, 2021 |
Change |
% Change |
|
Gain (loss) on derivative settlements
(in thousands)
|
||||
Natural gas |
$(782,525) |
$(263,929) |
$(518,596) |
196% |
NGLs |
(85,549) |
(60,530) |
(25,019) |
41% |
Oil |
(27,728) |
3,803 |
(31,531) |
(829%) |
Net gain (loss) on commodity derivative
settlements(a)
|
$(895,802) |
$(320,656) |
$(575,146) |
179% |
Total revenue, inclusive of settled hedges |
$1,023,547 |
$686,905 |
$336,642 |
49% |
Per Mcfe Metrics |
||||
Average realized sales price |
||||
(including impact of derivatives settled in cash) |
$3.30 |
$2.51 |
$0.79 |
31% |
Midstream and other revenue |
0.16 |
0.13 |
0.03 |
23% |
LOE |
(0.62) |
(0.46) |
(0.16) |
35% |
Midstream operating expense |
(0.24) |
(0.23) |
(0.01) |
4% |
Employees, administrative costs and professional
services
|
(0.26) |
(0.22) |
(0.04) |
18% |
Recurring allowance for credit losses |
— |
0.02 |
(0.02) |
(100%) |
Production taxes |
(0.25) |
(0.12) |
(0.13) |
108% |
Transportation expense |
(0.40) |
(0.31) |
(0.09) |
29% |
Proceeds received from leasehold sales |
0.01 |
— |
0.01 |
100% |
Adjusted EBITDA per Mcfe |
$1.70 |
$1.32 |
$0.38 |
29% |
Adjusted EBITDA Margin |
49% |
50% |
||
Other financial metrics (in thousands) |
||||
Adjusted EBITDA |
$502,954 |
$343,145 |
$159,809 |
47% |
Operating profit (loss) |
$(671,403) |
$(467,064) |
$(204,339) |
44% |
Net income (loss) |
$(620,598) |
$(325,206) |
$(295,392) |
91% |
(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.
FORWARD-LOOKING STATEMENT
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, industry trends, competition, commodity prices, changes in
regulation, currency fluctuations, our ability to recover our reserves, 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 AND HEDGING
Total revenue in the year ended December 31, 2023 of $868 million decreased 55% from $1,919 million reported for the year
ended December 31, 2022, primarily due to a 58% decrease in the average realized sales price slightly offset by 1% higher
production. Including commodity hedge settlement gains of $178 million and losses of $896 million in 2023 and 2022,
respectively, total revenue, inclusive of settled hedges, increased by 2% to $1,046 million in 2023 from $1,024 million in 2022.
During the current year’s low commodity price environment, we have benefited from our ability to opportunistically elevate
our hedge floor during the elevated commodity market cycle in 2022. This enhancement in our weighted average hedge floor
helped us minimize the impact of the suppressed commodity pricing environment in 2023, during which we realized a
decrease in total commodity revenue of just $8 million, inclusive of settled hedges. Offsetting this slight decrease was an
increase of $12 million in total commodity revenue, inclusive of settled hedges, generated through increases in production. We
sold 299,632 MMcfe in 2023 versus 296,121 MMcfe in 2022. This increase in volumes sold was due to the March 2023 Tanos II
acquisition as well as the integration of a full year of production from the East Texas and ConocoPhillips acquisitions which
occurred in April and September of 2022, respectively.
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, 2023 |
December 31, 2022 |
$ Change |
% Change |
|
Henry Hub |
$2.74 |
$6.62 |
$(3.88) |
(59%) |
Mont Belvieu |
34.11 |
51.04 |
(16.93) |
(33%) |
WTI |
77.62 |
93.53 |
(15.91) |
(17%) |
Year Ended |
||||
December 31, 2022 |
December 31, 2021 |
$ Change |
% Change |
|
Henry Hub |
$6.62 |
$3.84 |
$2.78 |
72% |
Mont Belvieu |
51.04 |
47.49 |
3.55 |
7% |
WTI |
93.53 |
68.26 |
25.27 |
37% |
Refer to Note 5 in the Notes to the Group Financial Statements for additional information regarding acquisitions.
COMMODITY REVENUE
The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) for the year
ended December 31, 2023 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, 2021 |
$818,726 |
$115,747 |
$38,634 |
$973,107 |
Volume increase (decrease) |
73,129 |
53,414 |
62,780 |
189,323 |
Price increase (decrease) |
652,803 |
19,572 |
38,206 |
710,581 |
Net increase (decrease) |
725,932 |
72,986 |
100,986 |
899,904 |
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 |
To manage our cash flows in a volatile commodity price environment and as required by our SPV-level asset-backed securities,
we utilize derivative contracts which allow us to fix the sales prices at a per unit level for approximately 83% of our production
to mitigate commodity risk. 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, 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 |
(In thousands, except per
unit data)
|
Year Ended December 31, 2022 |
|||||||
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 |
$1,544,658 |
$6.04 |
$188,733 |
$36.29 |
$139,620 |
$89.85 |
$1,873,011 |
$6.33 |
Commodity hedge impact |
(782,525) |
(3.06) |
(85,549) |
(16.45) |
(27,728) |
(17.85) |
(895,802) |
(3.03) |
Including hedge impact |
$762,133 |
$2.98 |
$103,184 |
$19.84 |
$111,892 |
$72.00 |
$977,209 |
$3.30 |
(In thousands, except per
unit data)
|
Year Ended December 31, 2021 |
|||||||
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 |
$818,726 |
$3.49 |
$115,747 |
$32.53 |
$38,634 |
$65.26 |
$973,107 |
$3.75 |
Commodity hedge impact |
(263,929) |
(1.13) |
(60,530) |
(17.01) |
3,803 |
6.42 |
(320,656) |
(1.24) |
Including hedge impact |
$554,797 |
$2.36 |
$55,217 |
$15.52 |
$42,437 |
$71.68 |
$652,451 |
$2.51 |
Refer to Note 13 in the Notes to the Group Financial Statements for additional information regarding derivative
financial instruments.
EXPENSES
(In thousands, except per unit data) |
Year Ended |
|||||||
December
31, 2023
|
Per |
December
31, 2022
|
Per |
Total Change |
Per Mcfe Change |
|||
Per Mcfe |
Per Mcfe |
$ |
% |
$ |
% |
|||
LOE(a)
|
$213,078 |
$0.71 |
$182,817 |
$0.62 |
$30,261 |
17% |
$0.09 |
15% |
Production taxes(b)
|
61,474 |
0.21 |
73,849 |
0.25 |
(12,375) |
(17%) |
(0.04) |
(16%) |
Midstream operating expenses(c)
|
69,792 |
0.23 |
71,154 |
0.24 |
(1,362) |
(2%) |
(0.01) |
(4%) |
Transportation expenses(d)
|
96,218 |
0.32 |
118,073 |
0.40 |
(21,855) |
(19%) |
(0.08) |
(20%) |
Total operating expenses |
$440,562 |
$1.47 |
$445,893 |
$1.51 |
$(5,331) |
(1%) |
$(0.04) |
(3%) |
Employees, administrative costs
and professional services(e)
|
78,659 |
0.26 |
77,172 |
0.26 |
1,487 |
2% |
— |
—% |
Costs associated with acquisitions(f)
|
16,775 |
0.06 |
15,545 |
0.05 |
1,230 |
8% |
0.01 |
20% |
Other adjusting costs(g)
|
17,794 |
0.06 |
69,967 |
0.24 |
(52,173) |
(75%) |
(0.18) |
(75%) |
Non-cash equity compensation(h)
|
6,494 |
0.02 |
8,051 |
0.03 |
(1,557) |
(19%) |
(0.01) |
(33%) |
Total operating and G&A expenses |
$560,284 |
$1.87 |
$616,628 |
$2.09 |
$(56,344) |
(9%) |
$(0.22) |
(11%) |
Depreciation, depletion and
amortization
|
224,546 |
0.75 |
222,257 |
0.75 |
2,289 |
1% |
— |
—% |
Allowance for credit losses(i)
|
8,478 |
0.03 |
— |
— |
8,478 |
100% |
0.03 |
100% |
Total expenses |
$793,308 |
$2.65 |
$838,885 |
$2.84 |
$(45,577) |
(5%) |
$(0.19) |
(7%) |
(In thousands, except per unit
data)
|
Year Ended |
|||||||
December
31, 2022
|
Per |
December
31, 2021
|
Per |
Total Change |
Per Mcfe Change |
|||
Per Mcfe |
Per Mcfe |
$ |
% |
$ |
% |
|||
LOE(a)
|
$182,817 |
$0.62 |
$119,594 |
$0.46 |
$63,223 |
53% |
$0.16 |
35% |
Production taxes(b)
|
73,849 |
0.25 |
30,518 |
0.12 |
43,331 |
142% |
0.13 |
108% |
Midstream operating
expenses(c)
|
71,154 |
0.24 |
60,481 |
0.23 |
10,673 |
18% |
0.01 |
4% |
Transportation expenses(d)
|
118,073 |
0.40 |
80,620 |
0.31 |
37,453 |
46% |
0.09 |
29% |
Total operating expenses |
$445,893 |
$1.51 |
$291,213 |
$1.12 |
$154,680 |
53% |
$0.39 |
35% |
Employees, administrative
costs and professional
services(e)
|
77,172 |
0.26 |
56,812 |
0.22 |
20,360 |
36% |
0.04 |
18% |
Costs associated with
acquisitions(f)
|
15,545 |
0.05 |
27,743 |
0.11 |
(12,198) |
(44%) |
(0.06) |
(55%) |
Other adjusting costs(g)
|
69,967 |
0.24 |
10,371 |
0.04 |
59,596 |
575% |
0.20 |
500% |
Non-cash equity
compensation(h)
|
8,051 |
0.03 |
7,400 |
0.03 |
651 |
9% |
— |
—% |
Total operating and G&A
expenses
|
$616,628 |
$2.09 |
$393,539 |
$1.52 |
$223,089 |
57% |
$0.57 |
38% |
Depreciation, depletion and
amortization
|
222,257 |
0.75 |
167,644 |
0.65 |
54,613 |
33% |
0.10 |
15% |
Allowance for credit losses(i)
|
— |
— |
(4,265) |
(0.02) |
4,265 |
(100%) |
0.02 |
(100%) |
Total expenses |
$838,885 |
$2.84 |
$556,918 |
$2.15 |
$281,967 |
51% |
$0.69 |
32% |
(a)LOE includes costs incurred to maintain producing properties. Such costs include direct and contract labor, repairs and maintenance, water
hauling, compression, automobile, insurance, and materials and supplies expenses.
(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 the Group’s natural gas and oil properties and midstream assets.
(c)Midstream operating expenses are daily costs incurred to operate the Group’s 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 the Group’s natural gas, NGLs and oil.
(e)Employees, administrative costs and professional services includes payroll and benefits for our administrative and corporate staff, costs of
maintaining administrative and corporate offices, costs of managing our production operations, franchise taxes, public company costs, fees
for audit and other professional services and legal compliance.
(f)We generally incur costs related to the integration of acquisitions, which will vary for each acquisition. For acquisitions considered to be a
business combination, these costs include transaction costs directly associated with a successful acquisition transaction. These costs also
include costs associated with transition service arrangements where we pay the seller of the acquired entity a fee to handle various G&A
functions until we have fully integrated the assets onto our systems. In addition, these costs include costs related to integrating IT systems
and consulting as well as internal workforce costs directly related to integrating acquisitions into our system.
(g)Other adjusting costs include items that affect the comparability of results or that are not indicative of trends in the ongoing business. 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 reflects the expense recognition related to share-based compensation provided to certain key members of
the management team. Refer to Note 17 in the Notes to the Group Financial Statements for additional information regarding 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
We experienced decreases in per unit operating expense of 3%, or $0.04 per Mcfe, resulting from:
—Higher per Mcfe LOE that increased 15%, or $0.09 per Mcfe, reflective of changes in our portfolio mix due to the higher cost
structure of the Central Region and our growing presence there. LOE includes cost from assets from our Tanos II acquisition
in March 2023 as well as a full year of expenses from the acquired East Texas Assets and ConocoPhillips assets acquired in
April and September 2022, respectively. Importantly, however, while per units costs increased, margins remained relatively
flat at 52%.
—Lower per Mcfe production taxes that declined 16%, or $0.04 per Mcfe were primarily attributable to a decrease in
severance taxes as a result of a decrease in revenue due to lower commodity prices; and
—Lower per Mcfe transportation expenses that declined 20%, or $0.08 per Mcfe, resulting from decreases in third-party
midstream rates that are tied to commodity pricing in the Central Region.
General and Administrative Expense
G&A expense decreased primarily due to:
—A decrease in other adjusting costs due to the comparatively limited transactional activity in 2023 as compared to 2022.
From time to time, we incur costs associated with potential acquisitions that include deposits, rights of first refusal, option
agreement costs and hedging costs incurred in connection with the potential acquisitions. At times, due to changing macro-
economic conditions, commodity price volatility and/or findings observed during our deal diligence efforts, we incur
expenses of this nature as breakage and/or deal sourcing fees. In 2021, we paid $25 million in costs associated with a
potential acquisition and, due to decisions we made in the first quarter of 2022, we terminated the transaction and wrote off
$25 million in certain acquisition related costs related to these items.
—In February 2022, we paid $28 million to terminate a fixed-price purchase contract associated with certain Barnett volumes
acquired during the Blackbeard acquisition. The contract extended through March 2024 and, as a result of the termination,
we will realize more favorable pricing over this period. This transaction also positioned us to refinance these assets as part
of the ABS IV financing arrangement and allowed us to enhance our liquidity by eliminating the need for a $20 million letter
of credit on our Credit Facility. This transaction was classified in other adjusting costs.
Other Expenses
Depreciation, depletion and amortization (“DD&A”) increased due to higher depletion expense due to a 1% increase in
production attributable to an increased number of producing wells from acquisitions.
Allowance for credit losses increased 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.
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, 2023 |
December 31, 2022 |
$ Change |
% Change |
|
Net gain (loss) on commodity derivatives
settlements(a)
|
$178,064 |
$(895,802) |
$1,073,866 |
(120%) |
Net gain (loss) on interest rate swap(a)
|
(2,722) |
(1,434) |
(1,288) |
90% |
Gain (loss) on foreign currency hedges(a)
|
(521) |
— |
(521) |
(100%) |
Total gain (loss) on settled derivative
instruments
|
$174,821 |
$(897,236) |
$1,072,057 |
(119%) |
Gain (loss) on fair value adjustments of
unsettled financial instruments(b)
|
905,695 |
(861,457) |
1,767,152 |
(205%) |
Total gain (loss) on derivative financial
instruments
|
$1,080,516 |
$(1,758,693) |
$2,839,209 |
(161%) |
(In thousands) |
Year Ended |
|||
December 31, 2022 |
December 31, 2021 |
$ Change |
% Change |
|
Net gain (loss) on commodity derivatives
settlements(a)
|
$(895,802) |
$(320,656) |
$(575,146) |
179% |
Net gain (loss) on interest rate swaps(a)
|
(1,434) |
(530) |
(904) |
171% |
Gain (loss) on foreign currency hedges(a)
|
— |
(1,227) |
1,227 |
(100%) |
Total gain (loss) on settled derivative
instruments
|
$(897,236) |
$(322,413) |
$(574,823) |
178% |
Gain (loss) on fair value adjustments of
unsettled financial instruments(b)
|
(861,457) |
(652,465) |
(208,992) |
32% |
Total gain (loss) on derivative financial
instruments
|
$(1,758,693) |
$(974,878) |
$(783,815) |
80% |
(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, 2023, we recognized a gain on derivative financial instruments of $1,081 million compared to
a loss of $1,759 million in 2022. Adjusting our unsettled derivative contracts to their fair values drove a gain of $906 million in
2023, as compared to a loss of $861 million in 2022.
For the year ended December 31, 2023, we recognized a gain on settled derivative instruments of $175 million as compared to
a loss of $897 million in 2022. The gain on settled derivative instruments relates to lower commodity market prices than we
secured through our derivative contracts. With consistent reliable cash flows central to our strategy, to protect our downside
risk we routinely hedge at levels that, based on our operating and overhead costs, provide a healthy margin even if it means
foregoing potential price upside.
Refer to Note 13 in the Notes to the Group Financial Statements for additional information regarding derivative
financial instruments.
GAIN ON BARGAIN PURCHASES
We recorded the following gain on bargain purchases in the Consolidated Statement of Comprehensive Income for the
periods presented:
(In thousands) |
Year Ended |
|||
December 31, 2023 |
December 31, 2022 |
$ Change |
% Change |
|
Gain on bargain purchases |
$— |
$4,447 |
$(4,447) |
(100%) |
(In thousands) |
Year Ended |
|||
December 31, 2022 |
December 31, 2021 |
$ Change |
% Change |
|
Gain on bargain purchases |
$4,447 |
$58,072 |
$(53,625) |
(92%) |
In past years the E&P segment of the broader energy sector has been in a period of transition and rebalancing, thus creating
opportunities for healthy companies like ours to acquire high quality assets for less than their fair value. We have established a
track record of being disciplined in our bidding to acquire assets that meet our strict asset profile and are accretive to our
overall corporate value.
In 2022, we recognized a gain on bargain purchases of $4 million that was primarily a result of measurement period
adjustments associated with the 2021 Tapstone acquisition.
In 2021, we recognized a gain on bargain purchases of $58 million related to the acquisition of Tapstone and Tanos.
Gain on bargain purchases are not recorded for transactions that are accounted for as an acquisition of assets under IFRS 3,
Business Combinations (“IFRS 3”). Rather, the consideration paid is allocated to the assets acquired on a relative fair
value basis.
Refer to Note 5 in the Notes to the Group Financial Statements for additional information regarding acquisitions and bargain
purchase gain.
FINANCE COSTS
(In thousands) |
Year Ended |
|||
December 31, 2023 |
December 31, 2022 |
$ Change |
% Change |
|
Interest expense, net of capitalized and
income amounts(a)
|
$117,808 |
$86,840 |
$30,968 |
36% |
Amortization of discount and deferred
finance costs
|
16,358 |
13,903 |
2,455 |
18% |
Other |
— |
56 |
(56) |
(100%) |
Total finance costs |
$134,166 |
$100,799 |
$33,367 |
33% |
(In thousands) |
Year Ended |
|||
December 31, 2022 |
December 31, 2021 |
$ Change |
% Change |
|
Interest expense, net of capitalized and
income amounts(a)
|
$86,840 |
$42,370 |
$44,470 |
105% |
Amortization of discount and deferred
finance costs
|
13,903 |
8,191 |
5,712 |
70% |
Other |
56 |
67 |
(11) |
(16%) |
Total finance costs |
$100,799 |
$50,628 |
$50,171 |
99% |
(a)Includes payments related to borrowings and leases.
For the year ended December 31, 2023, interest expense of $118 million increased by $31 million compared to $87 million in
2022, primarily due to the increase in borrowings to fund our 2023 acquisition, incurring a full year of interest on borrowings
associated with the 2022 acquisitions and an increase in the weighted average interest rate on borrowings year-over-year.
As of December 31, 2023 and 2022, total borrowings were $1,325 million and $1,498 million, respectively. For the period ended
December 31, 2023, the weighted average interest rate on borrowings was 6.03% as compared to 5.51% as of December 31,
2022. As of December 31, 2023, 87% of our borrowings now reside in fixed-rate, hedge-protected, amortizing structures
compared to 96% as of December 31, 2022.
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, 2023 |
December 31, 2022 |
$ Change |
% Change |
|
Income (loss) before taxation |
$1,000,344 |
$(799,502) |
$1,799,846 |
(225%) |
Income tax benefit (expenses) |
(240,643) |
178,904 |
(419,547) |
(235%) |
Effective tax rate |
24.1% |
22.4% |
(In thousands) |
Year Ended |
|||
December 31, 2022 |
December 31, 2021 |
$ Change |
% Change |
|
Income (loss) before taxation |
$(799,502) |
$(550,900) |
$(248,602) |
45% |
Income tax benefit (expenses) |
178,904 |
225,694 |
(46,790) |
(21%) |
Effective tax rate |
22.4% |
41.0% |
The differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:
Year Ended |
|||
December 31, 2023 |
December 31, 2022 |
December 31, 2021 |
|
Expected tax at statutory U.S. federal income tax rate |
21.0% |
21.0% |
21.0% |
State income taxes, net of federal tax benefit |
3.1% |
1.2% |
4.4% |
Federal credits |
—% |
—% |
15.4% |
Other, net |
—% |
0.2% |
0.2% |
Effective tax rate |
24.1% |
22.4% |
41.0% |
For the year ended December 31, 2023, we reported a tax expense of $241 million, a change of $420 million, compared to a
benefit of $179 million in 2022 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, 2023 and
2022 were 24.1% and 22.4%, 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 2021 effective tax rate. A marginal well tax credit was not
available in 2022 and this tax credit has not been announced for 2023. The federal government provides these credits to
encourage companies to continue operating lower-volume wells during periods of low prices to maintain 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 AND EPS
(In thousands, except per unit data) |
Year Ended |
|||
December 31, 2023 |
December 31, 2022 |
$ Change |
% Change |
|
Operating profit (loss) |
$1,161,051 |
$(671,403) |
$1,832,454 |
(273%) |
Net income (loss) |
759,701 |
(620,598) |
1,380,299 |
(222%) |
Adjusted EBITDA |
542,794 |
502,954 |
39,840 |
8% |
Earnings (loss) per share - basic |
$16.07 |
$(14.82) |
$30.89 |
(208%) |
Earnings (loss) per share - diluted |
$15.95 |
$(14.82) |
$30.77 |
(208%) |
(In thousands, except per unit data) |
Year Ended |
|||
December 31, 2022 |
December 31, 2021 |
$ Change |
% Change |
|
Operating profit (loss) |
$(671,403) |
$(467,064) |
$(204,339) |
44% |
Net income (loss) |
(620,598) |
(325,206) |
(295,392) |
91% |
Adjusted EBITDA |
502,954 |
343,145 |
159,809 |
47% |
Earnings (loss) per share - basic |
$(14.82) |
$(8.20) |
$(6.62) |
81% |
Earnings (loss) per share - diluted |
$(14.82) |
$(8.20) |
$(6.62) |
81% |
For the year ended December 31, 2023, we reported net income of $760 million and basic EPS of $16.07 ($15.95 diluted EPS)
compared to net loss of $621 million and basic loss per share of $14.82 ($14.82 diluted loss per share) in 2022, an increase of
222% and 208%, respectively. We also reported an operating profit of $1,161 million compared with an operating loss of $671
million for the years ended December 31, 2023 and 2022, respectively. This year-over-year increase was primarily attributable
to a $2,839 million increase in gains on derivatives, a $40 million increased in gains on sale of assets, offset by a decrease in
gross profit of $1,048 million, $33 million more in finance costs, and $420 million more income tax expense as compared
to 2022.
Excluding the mark-to-market gain on long-dated derivative valuations, as well as other customary adjustments, we reported
adjusted EBITDA of $543 million for the year ended December 31, 2023 compared to $503 million for the year ended
December 31, 2022, representing an increase of 8% driven by our growth through the Tanos II acquisition in 2023 and a full
year of the 2022 East Texas Assets and ConocoPhillips acquisitions.
LIQUIDITY AND 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 and as a result have
historically carried little cash on our Consolidated Statement of Financial Position as evidenced by our $4 million and $7 million
in cash and cash equivalents as of December 31, 2023 and 2022, respectively.
When we acquire assets to grow, we complement our Credit Facility with asset-backed debt securitized by certain natural gas
and oil assets, which are long-term, fixed-rate, fully-amortizing debt structures that better match the long-life nature of our
assets. These structures afford us low borrowing rates and also provide a visible path for reducing leverage as we make
scheduled principal payments. For larger value-adding acquisitions, and to ensure we maintain a leverage profile that we
believe is appropriate for the type of assets we acquire, we also raise proceeds through secondary equity offerings from time
to time.
We monitor our working capital to ensure that the levels remain adequate to operate the business with excess liquidity
primarily utilized for the repayment of debt or dividends to shareholders. 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.
Capital expenditures were $74 million for the year ended December 31, 2023 compared to $86 million for the year ended
December 31, 2022. This decrease in capital expenditures was primarily driven by the completion of wells in 2022 that were
under development by Tapstone at the time we closed that acquisition in 2021. While our March 2023 Tanos II acquisition also
contained wells under development at the time of acquisition, the capital expenditures needed for their development during
2023 was less significant than that required during 2022. 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 and future acquisitions, among other things.
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 13 in the Notes to the Group Financial Statements for additional information regarding our hedging program to
mitigate the risk associated with future cash flow generation.
The table below represents our liquidity position as of December 31, 2023, 2022 and 2021.
As of |
|||
(In thousands) |
December 31, 2023 |
December 31, 2022 |
December 31, 2021 |
LESS: Cash |
$3,753 |
$7,329 |
$12,558 |
Available borrowings under the Credit Facility(a)
|
134,817 |
183,332 |
222,263 |
Liquidity |
$138,570 |
$190,661 |
$234,821 |
(a)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. Represents available borrowings under the Credit Facility of $194 million as of December 31, 2022 less outstanding
letters of credit of $11 million as of such date. Represents available borrowings under the Credit Facility of $254 million as of December 31,
2021 less outstanding letters of credit of $32 million as of such date.
DEBT
Our net borrowings consisted of the following as of the reporting date:
As of |
||
(In thousands) |
December 31, 2023 |
December 31, 2022 |
Credit Facility |
$159,000 |
$56,000 |
ABS I Notes |
100,898 |
125,864 |
ABS II Notes |
125,922 |
147,458 |
ABS III Notes |
274,710 |
319,856 |
ABS IV Notes |
99,951 |
130,144 |
ABS V Notes |
290,913 |
378,796 |
ABS VI Notes |
159,357 |
212,446 |
Term Loan I |
106,470 |
120,518 |
Other |
7,627 |
7,084 |
Total debt |
$1,324,848 |
$1,498,166 |
LESS: Cash |
3,753 |
7,329 |
LESS: Restricted cash |
36,252 |
55,388 |
Net debt |
$1,284,843 |
$1,435,449 |
OUR CAPITAL EXPENDITURE PROGRAM
Our strategy to acquire and operate producing assets that generate adjusted EBITDA margins of approximately 50% allows us
to invest capital back into our operations. In addition, we have set goals to achieve “net zero” Scope 1 and Scope 2 emissions
by 2040 through new investments aimed at emissions reductions, such as investments in natural gas emissions detection
devices and conducting aerial scans of our assets.
The majority of our capital expenditures are focused on our midstream operations, which includes pipelines and compression,
while the remaining capital expenditures are focused on production optimization, technology, upstream operations, plugging
capacity expansion, fleet, emissions reductions, and when prudent, may include development activities targeted at replacing
production. Given our operational focus to acquire and operate mature conventional wells and unconventional wells with a
shallow decline rate, we do not incur the same level of large capital expenditures associated with drilling and completion
activities that would typically be incurred by other development focused exploration and production companies.
We have consistently targeted a disciplined leverage profile at or under 2.5 to 1.0 after giving effect to acquisitions and any
related financing arrangements. We believe this leverage range is supported by our differentiated business model, namely with
long-life, low-decline production providing resilient cash flows, and a strategic financial framework that is bolstered by
hedging and amortizing debt instruments. Our weighted-average hedge floor on natural gas production increased from $3.63
per Mcf as of December 31, 2022 to $3.87 per Mcf as of December 31, 2023.
Looking forward, we continue to seek to maximize cash flow. We plan to maintain our hedging strategy and take advantage of
market opportunities to raise the floor price of our risk management program. We will seek to retain our strategic advantages
in purposeful growth through a disciplined capital expenditure program that continues to secure low-cost financing that
supports acquisitive growth while maintaining low leverage and sufficient liquidity.
ASSET RETIREMENT OBLIGATIONS
We continue to be proactive and innovative with respect to asset retirement. In 2017, after our LSE IPO, we proactively began
to meet with state officials to develop a long-term plan to retire our growing portfolio of long-life wells. Collaborating with the
appropriate regulators, we designed our retirement activities to be equitable for all stakeholders with an emphasis on
the environment.
During the year ended December 31, 2023 we accomplished the following:
—Expanded asset retirement operations from 15 rigs at December 31, 2022 to 17 rigs at December 31, 2023 increasing our
asset retirement capacity in Appalachia;
—Retired 222 wells, inclusive of our Central Region operations, outpacing calendar year 2022 activity when we retired 214
wells. These retirements were achieved one full year in advance of our stated goal to retire 200 wells per year by year-end
2023; and
—Retired 182 outside party wells, including 148 state and federal orphan wells and 34 wells for other operators.
This growth in our asset retirement capacity provides us with the ability to further integrate our asset retirement operations
and generate cost efficiencies across a broader footprint. It will also provide us with the ability to generate additional third-
party revenues by providing a suite of services to other production companies which can be utilized to help fund the cost
associated with our own asset retirement program. As a result, we aim to obtain a prudent mix of both cost reduction and
third-party revenues to maximize the benefits of our internal asset retirement program.
Our asset retirement program reflects our solid commitment to a healthy environment and the surrounding communities, and
we anticipate continued investment and innovation in this area. During 2024, we will continue our work to realize the vertical
integration benefits of expanded internal asset retirement capacity to reduce reliance on third-party contractors, reduce
outsource risk, improve process quality and responsiveness, and increase 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, 2023 |
December 31, 2022 |
December 31, 2021 |
Balance at beginning of period |
$457,083 |
$525,589 |
$346,124 |
Additions(a)
|
3,250 |
24,395 |
96,292 |
Accretion |
26,926 |
27,569 |
24,396 |
Asset retirement costs |
(5,961) |
(4,889) |
(2,879) |
Disposals(b)
|
(17,300) |
(16,779) |
(16,500) |
Revisions to estimate(c)
|
42,650 |
(98,802) |
78,156 |
Balance at end of period |
$506,648 |
$457,083 |
$525,589 |
Less: Current asset retirement obligations |
5,402 |
4,529 |
3,399 |
Non-current asset retirement obligations |
$501,246 |
$452,554 |
$522,190 |
(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, 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 based on our recent asset
retirement experiences. Partially offsetting these decreases was a $1 million change attributed to timing. As of December 31, 2022, we
performed normal revisions to our asset retirement obligations, which resulted in a $99 million decrease in the liability. This decrease was
comprised of a $145 million decrease attributable to the lower discount rate which was then offset by a $29 million reduction in anticipated
asset retirement cost. The remaining change was attributable to timing. The lower discount rate was a result of macroeconomic factors
spurred by the COVID-19 recovery, which reduced bond yields and increased inflation. Cost reductions are based on our recent asset
retirement experiences. As of December 31, 2021, we performed normal revisions to our asset retirement obligations, which resulted in a $78
million increase in the liability. This increase was comprised of a $109 million increase attributable to the lower discount rate which was then
offset by a $27 million reduction in anticipated asset retirement cost. The remaining change was attributable to timing. The lower discount
rate was a result of macroeconomic factors spurred by the COVID-19 recovery, which reduced bond yields and increased inflation. Cost
reductions are based on our recent asset retirement experiences.
The anticipated future cash outflows for our asset retirement obligations on an undiscounted and discounted basis were as set
forth in the tables below as of December 31, 2023, 2022 and 2021. When discounting the obligation, we apply a contingency
allowance for 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 3.4%, 3.6% and 2.9% 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
2095, consistent with our reserve calculations which were independently evaluated by third-party engineers.
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 $2.1 billion, $8.8 billion and $4.0 billion as of December 31, 2023, 2022 and 2021,
respectively, illustrating residual cash flows well beyond our retirement obligations.
As of