November 16, 2023 - 20FR12B: Form for initial registration of a class of securities of foreign private issuers pursuant to Section 12(b)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 20-F

(Mark One)

☒

REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

☐

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

For the fiscal year ended

☐

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

☐

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

Date of event requiring this shell company report

For the transition period from to

Commission file number:

[MISSING IMAGE: lg_diversifiedenergy-4c.jpg]

Diversified Energy Company plc

(Exact name of Registrant as specified in its charter)

Not Applicable

(Translation of Registrant’s name into English)

England and Wales

(Jurisdiction of incorporation or organization)

1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909

(Address of principal executive offices)

Bradley G. Gray
Diversified Energy Company plc
1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909

(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
	Ordinary shares, nominal (par) value £0.01 per share			DEC			New York 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 ☒

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 ☐

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 ☐ 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 ☐ 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

☐ Accelerated filer

☒ Non-accelerated filer

☐ Emerging growth company

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

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

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

☐

U.S. GAAP

☒

International Financial Reporting Standards as issued by the International Accounting Standards Board

☐

Other

If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow. Item 17 ☐ Item 18 ☐

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☐

(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 ☐

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CONTENTS

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COMMONLY USED DEFINED TERMS		iv
ABOUT THIS REGISTRATION STATEMENT		ix
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		1
PRESENTATION OF FINANCIAL INFORMATION		3
PART I		5
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS		5
A. Directors and Senior Management.		5
B. Advisers.		5
C. Auditors.		5
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE		5
ITEM 3. KEY INFORMATION		6
A. [Reserved.]		6
B. Cash and Cash Equivalents, Capitalization and Indebtedness		6
C. Reasons for the Offer and Use of Proceeds		6
D. Risk Factors		6
ITEM 4. INFORMATION ON THE COMPANY.		37
A. History and Development of the Company		37
B. Business Overview		38
C. Organizational Structure		57
D. Property, Plants and Equipment		59
ITEM 4A. UNRESOLVED STAFF COMMENTS		60
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS		60
A. Operating Results		60
B. Liquidity and Capital Resources		84
C. Research and Development, Patents and Licenses, etc.		103
D. Trend Information		103
E. Critical Accounting Estimates		103
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES		103
A. Directors and Senior Management		103
B. Compensation		106
C. Board Practices		110
D. Employees		118
E. Share Ownership		119
F. Clawback Policy		119
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS		119
A. Major Shareholders		119
B. Related Party Transactions		120
C. Interests of Experts and Counsel		121
ITEM 8. FINANCIAL INFORMATION		121
A. Consolidated Statements and Other Financial Information		121
B. Significant Changes		122

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	Page
ITEM 9. THE LISTING		122
A. Listing Details		122
B. Plan of Distribution		123
C. Markets		123
D. Selling Shareholders		123
E. Dilution		123
F. Expenses of the Issue		124
ITEM 10. ADDITIONAL INFORMATION		124
A. Share Capital		124
B. Memorandum and Articles of Association		126
C. Material Contracts		143
D. Exchange Controls		146
E. Taxation		146
F. Dividends and Paying Agents		154
G. Statement by Experts		154
H. Documents on Display		154
I. Subsidiary Information		154
J. Annual Report to Securities Holders		154
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		155
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES		155
A. Debt Securities		155
B. Warrants and Rights		155
C. Other Securities		155
D. American Depositary Shares		155
PART II		156
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES		156
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS		156
ITEM 15. CONTROLS AND PROCEDURES		156
ITEM 16. [RESERVED]		156
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT		156
ITEM 16B. CODE OF ETHICS		156
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES		156
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES		156
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS		156
ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT		156
ITEM 16G. CORPORATE GOVERNANCE		156
ITEM 16H. MINE SAFETY DISCLOSURE		156
ITEM 16I. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS		156

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	Page
PART III		157
ITEM 17. FINANCIAL STATEMENTS		157
ITEM 18. FINANCIAL STATEMENTS		157
ITEM 19. EXHIBITS		157
SIGNATURES		161
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		F-1

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COMMONLY USED DEFINED TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the natural gas and oil industry:

“Basin.” A large natural depression on the earth’s surface in which sediments accumulate.

“Bbl.” Barrel or barrels of oil or natural gas liquids.

“Boe.” Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.

“Boepd.” Barrel of oil equivalent per day.

“Btu or British Thermal Unit.” A British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

“Development wells.” Wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Drilling.” means any activity related to drilling pad make-ready costs, rig mobilization and creating a wellbore in order to facilitate the ultimate production of hydrocarbons.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses, taxes and the royalty burden.

“E&P.” Exploration and production of natural gas, NGLs and oil.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

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

“Henry Hub.” A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a high angle to vertical (which can be greater than 90 degrees) in order to stay with a specified interval.

“Hydraulic fracturing.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“IFRS.” International Financial Reporting Standards, as issued by the International Accounting Standards Board.

“IASB.” The International Accounting Standards Board.

“LIBOR.” London Inter-bank Offered Rate, which is a market rate of interest.

“MBbls.” One thousand barrels of oil, condensate or NGL.

“Mboe.” One thousand Boe.

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“Mboepd.” One thousand Boe per day.

“Mcf.” One thousand cubic feet of natural gas.

“Mcfe.” One thousand cubic feet of natural gas equivalent.

“MMBoe.” One million Boe.

“MMBtu.” One million British Thermal Units.

“MMcf.” One million cubic feet of natural gas.

“MMcfe.” One million cubic feet of natural gas equivalent.

“MMcfepd.” One million cubic feet of natural gas equivalent per day.

“Mont Belvieu.” A mature trading hub with a high level of liquidity and transparency that sets spot and futures prices for NGLs.

“MtCO2e.” Metric tons of carbon dioxide equivalent.

“Net acres or net wells.” The sum of the fractional working interest owned in gross acres or gross wells, as the case may be. For example, an owner who has a 50% interest in 100 acres owns 50 net acres and an owner who has a 50% interest in 100 wells owns 50 net wells.

“NGL or NGLs.” Natural gas liquids, such as ethane, propane, butane and natural gasoline that are extracted from natural gas production streams.

“NYMEX.” The New York Mercantile Exchange.

“Oil.” Includes crude oil and condensate.

“OPEC.” The Organization of the Petroleum Exporting Countries.

“Possible reserves.” Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(a) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(b) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(c) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(d) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(e) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(f) Where direct observation has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally

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higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

“Probable Reserves.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(a) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(b) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(c) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proved developed reserves.” Reserves of any category that can be expected to be recovered through:

(a) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(b) installed extraction equipment and infrastructure operation at the time of the reserve estimate if the extraction is by means not involving a well.

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

(a) The area of reservoir considered as proved includes:

(i) the area identified by drilling and limited by fluid contacts, if any, and

(ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas, NGLs or oil on the basis of available geosciences and engineering data.

(b) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(c) Where direct observation from well penetrations has defined a HKO elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(d) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

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(i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

(e) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“Proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, NGLs or oil, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas, NGLs and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres, e.g., 40-acre spacing, and is established by regulatory agencies.

“SOFR.” The Secured Overnight Financing Rate, or SOFR.

“Standardized measure.” The year-end present value (discounted at an annual rate of 10%) of estimated future net cash flows to be generated from the production of proved reserves net of estimated income taxes associated with such net cash flows, as determined in accordance with FASB guidelines, without giving effect to non-property related expenses such as indirect general and administrative expenses and debt service or to depreciation, depletion and amortization. Standardized measure does not give effect to derivative transactions.

“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas, NGLs and oil regardless of whether such acreage contains proved reserves.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“U.S. GAAP.” Accounting principles generally accepted in the United States of America.

“Wellbore” or “well.” The hole drilled by the bit that is equipped for natural gas, NGLs or oil production on a completed well. Also called a well or borehole.

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“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas, NGLs, oil or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

“WTI.” West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.

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ABOUT THIS REGISTRATION STATEMENT

Except where the context otherwise requires or where otherwise indicated, the terms “Diversified Energy,” the “Company,” “DEC,” “we,” “us,” “our company” and “our business” refer to Diversified Energy Company plc, formerly Diversified Gas & Oil plc, together with its consolidated subsidiaries.

For the convenience of the reader, in this registration statement, unless otherwise indicated, translations from pound sterling into U.S. dollars were made at the rate of £1.00 to $ , which was the noon buying rate of the Federal Reserve Bank of New York on , 2023. Such U.S. dollar amounts are not necessarily indicative of the amounts of U.S. dollars that could actually have been purchased upon exchange of pound sterling at the dates indicated or any other date.

We obtained the industry, market and competitive position data in this registration statement from our own internal estimates, surveys and research, as well as from publicly available information, industry and general publications and research, surveys and studies.

Industry publications, research, surveys, studies and forecasts generally state that the information they contain has been obtained from sources believed to be reliable but that the accuracy and completeness of such information is not guaranteed. Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties as the other forward-looking statements in this registration statement. These forecasts and forward-looking information are subject to uncertainty and risk due to a variety of factors, including those described in the section titled “Risk Factors” found elsewhere in this registration statement. These and other factors could cause results to differ materially from those expressed in the forecasts or estimates from independent third parties and us.

We have proprietary rights to trademarks used in this registration statement that are important to our business, many of which are registered under applicable intellectual property laws. Solely for convenience, trademarks and trade names referred to in this registration statement may appear without the “®” or “™” symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent possible under applicable law, our rights or the rights of the applicable licensor to these trademarks and trade names. We do not intend our use or display of other companies’ trademarks, trade names or service marks to imply a relationship with, or endorsement or sponsorship of us by, any other companies. Each trademark, trade name or service mark of any other company appearing in this registration statement is the property of its respective holder.

Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and reserve data presented in this registration statement is as of December 31, 2022.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this registration statement, including those in “Item 3.D. Risk Factors,” “Item 4.B. Business Overview” and “Item 5. Operating and Financial Review and Prospects” and elsewhere in this registration statement, contain forward-looking statements. In some cases, you can identify forward-looking statements by the following words: “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 comparable terminology, although not all forward-looking statements contain these words. Forward-looking statements are not guarantees of performance. We have based forward-looking statements in this registration statement on our current expectations and beliefs about future developments and their potential effect on us.

These statements involve risks, uncertainties and other factors that may cause our actual results, levels of activity, performance or achievements to be materially different from the information expressed or implied by these forward-looking statements. Although we believe that we have a reasonable basis for each forward-looking statement contained in this registration statement, we caution you that these statements are based on a combination of facts and factors currently known by us and our projections of the future, about which we cannot be certain. Forward-looking statements contained in this registration statement are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties (some of which are beyond our control) and assumptions that could cause our actual results to differ materially from our historical experience and present expectations or projections. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements. Known material factors that could cause actual results to differ from those expressed in or implied by forward-looking statements contained or incorporated in this registration statement are described under “Risk Factors” and in other sections of this registration statement. Such factors include, but are not limited to:

•

declines in, the sustained depression of, or increased volatility in the prices we receive for our natural gas, oil and NGLs, or increases in the differential between index natural gas, oil and NGL prices and prices received;

•

risks related to and the effects of actual or anticipated pandemics such as the COVID-19 pandemic; uncertainties about the estimated quantities of natural gas, oil and NGL reserves;

•

operating risks, including, but not limited to, risks related to properties where we do not serve as the operator;

•

the adequacy of our capital resources and liquidity, including, but not limited to, access to additional borrowing capacity under our Credit Facility and the ability to obtain future financing on commercially reasonable terms or at all;

•

the effects of government regulation, permitting and other legal requirements, including, but not limited to, new legislation;

•

the effects of environmental, natural gas, oil and NGL related and occupational health and safety laws and regulations, including, but not limited to delays, curtailment or cessation of operations or exposure to material costs and liabilities;

•

difficult and adverse conditions in the domestic and global capital and credit markets and economies, including effects of diseases, political instability, including but not limited to instability related to the military conflict in Ukraine, and pricing and production decisions;

•

the concentration of our operations in the Appalachian Basin, the Barnett Shale, the Cotton Valley Formation, the Haynesville Shale of the United States and the Mid-Continent producing region;

•

potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity price risks;

•

the failure by counterparties to our derivative risk management activities to perform their obligations;

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•

shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;

•

access to pipelines, storage platforms, shipping vessels and other means of transporting and storing and refining gas and oil, including without limitation, changes in availability of, and access to, pipeline usage;

•

risks and liabilities associated with acquired properties, including, but not limited to, the assets acquired in connection with our recent acquisitions;

•

uncertainties about our ability to replace reserves;

•

our hedging strategy;

•

competition in the natural gas, oil and NGL industry; and

•

our substantial existing indebtedness. Reserve engineering is a process of estimating underground accumulations of natural gas, oil and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve and PV-10 estimates may differ significantly from the quantities of natural gas, oil and NGLs that are ultimately recovered.

You should refer to “Item 3.D Risk Factors” of this registration statement for a discussion of other important factors that may cause our actual results to differ materially from those expressed or implied by our forward-looking statements. As a result of these factors, we cannot assure you that the forward-looking statements in this registration statement will prove to be accurate.

In addition, statements that “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based upon information available to us as of the date of this registration statement, and although we believe such information forms a reasonable basis for such statements, such information may be limited or incomplete, and our statements should not be read to indicate that we have conducted a thorough inquiry into, or review of, all potentially available relevant information. These statements are inherently uncertain, and investors are cautioned not to unduly rely upon these statements. Furthermore, if our forward-looking statements prove to be inaccurate, the inaccuracy may be material. In light of the significant uncertainties in these forward-looking statements, you should not regard these statements as a representation or warranty by us or any other person that we will achieve our objectives and plans in any specified time frame, or at all. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

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PRESENTATION OF FINANCIAL INFORMATION

This registration statement includes our audited consolidated financial statements as of December 31, 2022 and 2021 and for each of the three years in the period ended December 31, 2022 as well as our unaudited interim condensed consolidated financial statements as of June 30, 2023 and for the six months ended June 30, 2023 and 2022, which have been prepared in accordance with IFRS, as issued by the IASB, which differ in certain significant respects from U.S. GAAP. None of our financial statements were prepared in accordance with U.S. GAAP.

Our financial information is presented in U.S. dollars. Our fiscal year begins on January 1 and ends on December 31 of the same year. Certain amounts and percentages included in this registration statement have been rounded. Accordingly, in certain instances, the sum of the numbers in a column of a table may not exactly equal the total figure for that column.

All references in this registration statement to “$” mean U.S. dollars and all references to “£” and “GBP” mean pound sterling. We have made rounding adjustments to some of the figures included in this registration statement. Accordingly, numerical figures shown as totals in some tables may not be an arithmetic aggregation of the figures that preceded them.

Use of Non-IFRS Measures

Certain key operating metrics that are not defined under IFRS (alternative performance measures) are included in this registration statement. These non-IFRS measures are used by us to monitor the underlying business performance of the Company from period to period and to facilitate comparison with our peers. Since not all companies calculate these or other non-IFRS metrics in the same way, the manner in which we have chosen to calculate the non-IFRS metrics presented herein may not be compatible with similarly defined terms used by other companies. The non-IFRS metrics should not be considered in isolation of, or viewed as substitutes for, the financial information prepared in accordance with IFRS. Certain of the key operating metrics set forth below are based on information derived from our regularly maintained records and accounting and operating systems. See “Item 5. Operating and Financial Review and Prospects — A. Operating Results” for reconciliations of such measures to the most directly comparable IFRS measures and reasons for the use of such non-IFRS measures.

Adjusted EBITDA. As used herein, EBITDA represents earnings before interest, taxes, depletion, depreciation and amortization. Adjusted EBITDA includes adjusting for items that are not comparable period over period, namely, accretion of asset retirement obligation, other (income) expense, loss on joint and working interest owners receivable, gain on bargain purchase, (gain) loss on fair value adjustments of unsettled financial instruments, (gain) loss on natural gas and oil property and equipment, costs associated with acquisitions, other adjusting costs, non-cash equity compensation, (gain) loss on foreign currency hedge, net (gain) loss on interest rate swaps and items of a similar nature.

Adjusted EBITDA should not be considered in isolation or as a substitute for operating profit or loss, net income or loss, or cash flows provided by operating, investing and financing activities. However, we believe such measure is useful to an investor in evaluating DEC’s financial performance because it (1) is widely used by investors in the natural gas and oil industry as an indicator of underlying business performance; (2) helps investors to more meaningfully evaluate and compare the results of DEC’s operations from period to period by removing the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement; (3) is used in the calculation of a key metric in our revolving credit facility by and among DP RBL Co LLC, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto (the “Credit Facility”) financial covenants; and (4) is used by the Company as a performance measure in determining executive compensation. When evaluating this measure, we believe investors also commonly find it useful to evaluate this metric as a percentage of our Total Revenue, inclusive of settled hedges, producing what we refer to as our Adjusted EBITDA Margin throughout this report. Please refer to the definitions of these added profitability metrics below for additional details.

Net Debt. As used herein, Net Debt represents total debt as recognized on the balance sheet less cash and restricted cash. Total debt includes DEC’s borrowings under the Credit Facility and borrowings under

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or issuances of, as applicable, its subsidiaries’ securitization facilities. Net Debt is a useful indicator of DEC’s leverage and capital structure.

Total Revenue, inclusive of settled hedges. As used herein, Total Revenue, inclusive of settled hedges, includes the impact of derivatives settled in cash. We believe that Total Revenue, inclusive of settled hedges, is a useful measure because it enables investors to discern DEC’s realized revenue after adjusting for the settlement of derivative contracts.

Adjusted EBITDA Margin. As used herein, Adjusted EBITDA Margin is measured as Adjusted EBITDA, as a percentage of Total Revenue, inclusive of settled hedges. Adjusted EBITDA Margin includes the direct operating cost and the portion of general and administrative cost it takes to produce each Boe. This metric includes operating expense, employees, administrative costs and professional services and recurring allowance for credit losses, which include fixed and variable cost components. We believe that Adjusted EBITDA Margin is a useful measure of DEC’s profitability and efficiency as well as its earnings quality given its ability to measure the company on a more comparable basis period over period given we are often involved in transactions that are not comparable between periods.

Free Cash Flow. As used herein, Free Cash Flow represents net cash provided by operating activities less expenditures on natural gas and oil properties and equipment and cash paid for interest. We believe that Free Cash Flow is a useful indicator of DEC’s ability to generate cash that is available for activities other than capital expenditures. Management believes that Free Cash Flow provides investors with an important perspective on the cash available to service debt obligations, make strategic acquisitions and investments and pay dividends.

Adjusted Operating Cost per Boe. Adjusted Operating Cost per Boe is a metric that allows us to measure the direct operating cost and the portion of general and administrative cost it takes to produce each Boe. This metric, similar to Adjusted EBITDA Margin, includes operating expense, employees, administrative costs and professional services and recurring allowance for credit losses, which include fixed and variable cost components.

Employees, administrative costs and professional services. As used herein, employees, administrative costs and professional services represents total administrative expenses excluding cost associated with acquisitions, other adjusting costs and non-cash expenses. We use Employees, administrative costs and professional services because this measure excludes items that affect the comparability of results or that are not indicative of trends in the ongoing business.

PV-10. PV-10 is a non-IFRS measure because it excludes the effects of applicable income tax. Management believes that the presentation of the non-IFRS financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating natural gas and oil companies. PV-10 is not a measure of financial or operating performance under IFRS. PV-10 should not be considered as an alternative to the standardized measure as defined under IFRS. We have included a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, its most directly comparable IFRS measure, elsewhere in this registration statement. PV-10 differs from the standardized measure of discounted future net cash flows because it does not include the effects of income taxes. Neither PV-10 nor the standardized measure represents an estimate of fair market value of our natural gas and oil properties.

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PART I

Item 1. Identity of Directors, Senior Management and Advisers

A. Directors and Senior Management.

Directors

The following table sets forth the names and positions of the members of our Board as of the date of this registration statement. The business address of each of the directors is c/o Diversified Energy Company plc, 1600 Corporate Drive, Birmingham, Alabama 35242.

Name	Position	Director Since(1)
Robert Russell (“Rusty”) Hutson, Jr.	Co-Founder, Chief Executive Officer and Director	July 2014
David E. Johnson	Independent Chairman of the Board	Feb. 2017
Martin K. Thomas	Vice Chairman of the Board	Jan. 2015
Kathryn Z. Klaber	Independent Director	Jan. 2023
Sylvia J. Kerrigan	Senior Independent Director	Oct. 2021
Sandra M. Stash	Independent Director	Oct. 2019
David J. Turner, Jr.	Independent Director	May 2019

(1)

The executive director’s service agreement is of indefinite duration, subject to termination by the Company or the individual on six months’ notice. The non-executive director serves for an initial period of 12 months, subject to re-election at each annual general meeting of the Company and is terminable on three months’ notice given by either party.

Senior Management

The following table sets forth the names and positions of the members of our Senior Management team as of the date of this registration statement. The business address for each member of our Senior Management is c/o Diversified Energy Company plc, 1600 Corporate Drive, Birmingham, Alabama 35242.

Name			Position
Robert Russell (“Rusty”) Hutson, Jr.			Co-Founder, Chief Executive Officer and Director
Bradley G. Gray			President and Chief Financial Officer
Benjamin Sullivan			Senior Executive Vice President, Chief Legal & Risk Officer, and Corporate Secretary

B. Advisers.

Our external legal advisers are Latham & Watkins LLP, whose address is 300 Colorado Street, Suite 2400, Austin, Texas 78701, and Latham & Watkins (London) LLP, whose address is 99 Bishopsgate London EC2M 3XF United Kingdom.

C. Auditors.

PricewaterhouseCoopers LLP has been our statutory auditor since 2020. PricewaterhouseCoopers LLP has audited our financial statements for the periods ended December 31, 2022, 2021 and 2020. PricewaterhouseCoopers LLP is an independent registered public accounting firm, registered with the Public Company Accounting Oversight Board (United States). For more information on our auditors, see “Item 10. Additional Information — G. Statements by Experts.”

Item 2. Offer Statistics and Expected Timetable

Not applicable.

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Item 3. Key Information

A. [Reserved.]

B. Cash and Cash Equivalents, Capitalization and Indebtedness

The table below sets forth our cash and cash equivalents, capitalization and indebtedness as of June 30, 2023, to which no significant updates have occurred through the date of this filing. This table should be read in conjunction with “Item 5. Operating and Financial Review and Prospects,” and the unaudited condensed consolidated interim financial statements and the related notes thereto, which appear elsewhere in this registration statement.

(in thousands)
Total debt	$	l,555,208
Shareholders’ equity:
Ordinary shares, nominal value £0.01 per share: shares, actual; shares, as adjusted
Share capital		13,056
Share premium account		1,208,192
Treasury reserve		(92,811)
Share based payment and other reserves		9,620
Retained earnings (accumulated deficit)		(590,109)
Non-controlling interest		13,050
Total shareholders’ equity		560,998
Total capitalization	$	2,116,206

C. Reasons for the Offer and Use of Proceeds

Not applicable.

D. Risk Factors

You should carefully consider the risks described below, together with all of the other information in this registration statement on Form 20-F. The risks and uncertainties below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we believe to be immaterial may also adversely affect our business. If any of the following risks occur, our business, financial condition, and results of operations could be seriously harmed and you could lose all or part of your investment. This registration statement also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including the risks described below and elsewhere in this registration statement.

Summary of Risk Factors

We are subject to a variety of risks and uncertainties which could have a material adverse effect on our business, financial condition, and results of operations. The summary below is not exhaustive and is qualified by reference to the full set of risk factors set forth in this “Risk Factors” section.

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Volatility and future decreases in natural gas, NGLs and oil prices could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

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We face production risks and hazards that may affect our ability to produce natural gas, NGLs and oil at expected levels, quality and costs that may result in additional liabilities to us.

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

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The present value of future net cash flows from our reserves, or PV-10, will not necessarily be the same as the current market value of our estimated natural gas, NGL and oil reserves.

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

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

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The COVID-19 pandemic (or another pandemic or epidemic) may have an adverse effect on our business, results of operations, financial condition, cash flows or prospects.

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Deterioration in the economic conditions in any of the industries in which our customers operate, a domestic or worldwide financial downturn, or negative credit market conditions could have a material adverse effect on our liquidity, results of operations, business and financial condition that we cannot predict.

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Our operations are subject to a series of risks relating to climate change.

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We rely on third-party infrastructure such as TC Energy (formerly TransCanada), Enbridge, CNX, Dominion Energy Transmission, Enlink, Williams and MarkWest (defined herein) that we do not control and/ or, in each case, are subject to tariff charges that we do not control.

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Failure by us, our contractors or our primary offtakers to obtain access to necessary equipment and transportation systems could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

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

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We depend on our directors, key members of management, independent experts, technical and operational service providers and on our ability to retain and hire such persons to effectively manage our growing business.

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We may face unanticipated water and other waste disposal costs.

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

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Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability to enter into future debt financing.

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

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

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Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

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The securitizations of our limited purpose, bankruptcy-remote, wholly owned subsidiaries may expose us to financing and other risks, and there can be no assurance that we will be able to access the securitization market in the future, which may require us to seek more costly financing.

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

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Our operations are dependent on our compliance with obligations under permits, licenses, contracts and field development plans.

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Our operations are subject to the risk of litigation.

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The price of our ordinary shares may be volatile and may fluctuate due to factors beyond our control.

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The dual listing of our ordinary shares may adversely affect the liquidity and value of our ordinary shares.

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•

Failure to comply with requirements to design, implement and maintain effective internal control over financial reporting could have a material adverse effect on our business.

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

Risks Related to Our Business, Operations and Industry

Volatility and future decreases in natural gas, NGLs and oil prices could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

Our business, results of operations, financial condition, cash flows or prospects depend substantially upon prevailing natural gas, NGL and oil prices, which may be adversely impacted by unfavorable global, regional and national macroeconomic conditions, including but not limited to instability related to the military conflict in Ukraine and the COVID-19 pandemic. Natural gas, NGLs and oil are commodities for which prices are determined based on global and regional demand, supply and other factors, all of which are beyond our control.

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

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global and regional supply and demand, and expectations regarding future supply and demand, for gas and oil products;

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global and regional economic conditions;

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evolution of stocks of oil and related products;

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increased production due to new extraction developments and improved extraction and production methods;

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geopolitical uncertainty;

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threats or acts of terrorism, war or threat of war, which may affect supply, transportation or demand;

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weather conditions, natural disasters, climate change and environmental incidents;

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access to pipelines, storage platforms, shipping vessels and other means of transporting, storing and refining gas and oil, including without limitation, changes in availability of, and access to, pipeline ullage;

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prices and availability of alternative fuels;

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prices and availability of new technologies affecting energy consumption;

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increasing competition from alternative energy sources;

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the ability of OPEC and other oil-producing nations, to set and maintain specified levels of production and prices;

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political, economic and military developments in gas and oil producing regions generally;

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governmental regulations and actions, including the imposition of export restrictions and taxes and environmental requirements and restrictions as well as anti-hydrocarbon production policies;

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trading activities by market participants and others either seeking to secure access to natural gas, NGLs and oil or to hedge against commercial risks, or as part of an investment portfolio; and

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market uncertainty, including fluctuations in currency exchange rates, and speculative activities by those who buy and sell natural gas, NGLs and oil on the world markets.

It is impossible to accurately predict future gas, NGL and oil price movements. Historically, natural gas prices have been highly volatile and subject to large fluctuations in response to relatively minor changes in the demand for natural gas. According to the U.S. Energy Information Administration, the historical high and low Henry Hub natural gas spot prices per MMBtu for the following periods were as follows: in 2020, high

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of $3.14 and low of $1.33; in 2021, high of $23.86 and low of $2.43; in 2022, high of $9.85 and low of $3.46, and for the six months ended June 30, 2023, high of $3.78 and low of $1.74 — highlighting the volatile nature of commodity prices.

The economics of producing from some wells and assets may also result in a reduction in the volumes of our reserves which can be produced commercially, resulting in decreases to our reported reserves. Additionally, further reductions in commodity prices may result in a reduction in the volumes of our reserves. We might also elect not to continue production from certain wells at lower prices, or our license partners may not want to continue production regardless of our position.

Each of these factors could result in a material decrease in the value of our reserves, which could lead to a reduction in our natural gas, NGLs and oil development activities and acquisition of additional reserves. In addition, certain development projects or potential future acquisitions could become unprofitable as a result of a decline in price and could result in us postponing or canceling a planned project or potential acquisition, or if it is not possible to cancel, to carry out the project or acquisition with negative economic impacts. Further, a reduction in natural gas, NGL or oil prices may lead our producing fields to be shut down and to be entered into the decommissioning phase earlier than estimated.

Our revenues, cash flows, operating results, profitability, dividends, future rate of growth and the carrying value of our gas and oil properties depend heavily on the prices we receive for natural gas, NGLs and oil sales. Commodity prices also affect our cash flows available for capital investments and other items, including the amount and value of our gas and oil reserves. In addition, we may face gas and oil property impairments if prices fall significantly. In light of the continuing increase in supply coming from the Utica and Marcellus shale plays of the Appalachian Basin, no assurance can be given that commodity prices will remain at levels which enable us to do business profitably or at levels that make it economically viable to produce from certain wells and any material decline in such prices could result in a reduction of our net production volumes and revenue and a decrease in the valuation of our production properties, which could negatively impact our business, results of operations, financial condition, cash flows or prospects.

We conduct our business in a highly competitive industry.

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

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engagement of third-party service providers whose capacity to provide key services may be limited;

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acquisition of other companies that may already own licenses or existing producing assets;

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acquisition of assets offered for sale by other companies;

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access to capital (debt and equity) for financing and operational purposes;

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purchasing, leasing, hiring, chartering or other procuring of equipment that may be scarce; and

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employment of qualified and experienced skilled management and gas and oil professionals and field operations personnel.

Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their degree of vertical integration and pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships with the relevant authorities. The cost to attract and retain qualified and experienced personnel has increased and may increase substantially in the future.

Our competitors also include those entities with greater technical, physical and financial resources than us. Finally, companies and certain private equity firms not previously investing in gas and oil may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect us.

The effects of operating in a competitive industry may include:

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higher than anticipated prices for the acquisition of licenses or assets;

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the hiring by competitors of key management or other personnel; and

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restrictions on the availability of equipment or services.

If we are unsuccessful in competing against other companies, our business, results of operations, financial condition, cash flows or prospects could be materially adversely affected.

We may experience delays in production, marketing and transportation.

Various production, marketing and transportation conditions may cause delays in natural gas, NGLs and oil production and adversely affect our business. For example, the gas gathering systems that we own connect to other pipelines or facilities which are owned and operated by third parties. These pipelines and other midstream facilities and others upon which we rely may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage. In periods where NGL prices are high, we benefit greatly from the ability to process NGLs. Our largest processor of NGLs is the MarkWest Energy Partners, L.P., (“MarkWest”) plant located in Langley, Kentucky. If we were to lose the ability to process NGLs at MarkWest’s plant during a period of high pricing, our revenues would be negatively impacted. As a short-term measure, we could divert the natural gas through other pipeline routes; however, certain pipeline operators would eventually decline to transport the gas due to its liquid content at a level that would exceed tariff specifications for those pipelines. The lack of available capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells. Any significant changes affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay our production, which could negatively impact our business, results of operations, financial condition, cash flows or prospects.

We face production risks and hazards that may affect our ability to produce natural gas, NGLs and oil at expected levels, quality and costs that may result in additional liabilities to us.

Our natural gas and oil production operations are subject to numerous risks common to our industry, including, but not limited to, premature decline of reservoirs, incorrect production estimates, invasion of water into producing formations, geological uncertainties such as unusual or unexpected rock formations and abnormal geological pressures, low permeability of reservoirs, contamination of natural gas and oil, blowouts, oil and other chemical spills, explosions, fires, equipment damage or failure, challenges relating to transportation, pipeline infrastructure, natural disasters, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, shortages of skilled labor, delays in obtaining regulatory approvals or consents, pollution and other environmental risks.

If any of the above events occur, environmental damage, including biodiversity loss or habitat destruction, injury to persons or property and other species and organisms, loss of life, failure to produce natural gas, NGLs and oil in commercial quantities or an inability to fully produce discovered reserves could result. These events could also cause substantial damage to our property or the property of others and our reputation and put at risk some or all of our interests in licenses, which enable us to produce, and could result in the incurrence of fines or penalties, criminal sanctions potentially being enforced against us and our management, as well as other governmental and third-party claims. Consequent production delays and declines from normal field operating conditions and other adverse actions taken by third parties may result in revenue and cash flow levels being adversely affected.

Moreover, should any of these risks materialize, we could incur legal defense costs, remedial costs and substantial losses, including those due to injury or loss of life, human health risks, severe damage to or destruction of property, natural resources and equipment, environmental damage, unplanned production outages, clean-up responsibilities, regulatory investigations and penalties, increased public interest in our operational performance and suspension of operations, which could negatively impact our business, results of operations, financial condition, cash flows or prospects.

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

The reserves data as of December 31, 2022, 2021 and 2020 contained in this registration statement have been audited by Netherland, Sewell & Associates, Inc. (“NSAI”) unless stated otherwise. The standards

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utilized to prepare the reserves information that has been extracted in this document may be different from the standards of reporting adopted in other jurisdictions. Investors, therefore, should not assume that the data found in the reserves information set forth in this registration statement is directly comparable to similar information that has been prepared in accordance with the reserve reporting standards of other jurisdictions, such as the United Kingdom.

In general, estimates of economically recoverable natural gas, NGLs and oil reserves are based on a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological, geophysical and engineering estimates (which have inherent uncertainties), historical production from the properties or analogous reserves, the assumed effects of regulation by governmental agencies and estimates of future commodity prices, operating costs, gathering and transportation costs and production related taxes, all of which may vary considerably from actual results.

Underground accumulations of hydrocarbons cannot be measured in an exact manner and estimates thereof are a subjective process aimed at understanding the statistical probabilities of recovery. Estimates of the quantity of economically recoverable natural gas and oil reserves, rates of production and, where applicable, the timing of development expenditures depend upon several variables and assumptions, including the following:

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production history compared with production from other comparable producing areas;

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quality and quantity of available data;

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interpretation of the available geological and geophysical data;

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effects of regulations adopted by governmental agencies;

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future percentages of sales;

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future natural gas, NGLs and oil prices;

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capital investments;

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effectiveness of the applied technologies and equipment;

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effectiveness of our field operations employees to extract the reserves;

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natural events or the negative impacts of natural disasters;

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future operating costs, tax on the extraction of commercial minerals, development costs and workover and remedial costs; and

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the judgment of the persons preparing the estimate.

As all reserve estimates are subjective, each of the following items may differ materially from those assumed in estimating reserves:

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the quantities and qualities that are ultimately recovered;

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the timing of the recovery of natural gas and oil reserves;

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the production and operating costs incurred;

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the amount and timing of development expenditures, to the extent applicable;

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future hydrocarbon sales prices; and

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decommissioning costs and changes to regulatory requirements for decommissioning.

Many of the factors in respect of which assumptions are made when estimating reserves are beyond our control and therefore these estimates may prove to be incorrect over time. Evaluations of reserves necessarily involve multiple uncertainties. The accuracy of any reserves evaluation depends on the quality of available information and natural gas, NGLs and oil engineering and geological interpretation. Furthermore, less historical well production data is available for unconventional wells because they have only become technologically viable in the past twenty years and the long-term production data is not always sufficient to determine terminal decline rates. In comparison, some conventional wells in our portfolio have been

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productive for a much longer time. As a result, there is a risk that estimates of our shale reserves are not as reliable as estimates of the conventional well reserves that have a longer historical profile to draw on. Interpretation, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserves and resources data. Moreover, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves will vary from estimates and the variances may be material.

If the assumptions upon which the estimates of our natural gas and oil reserves prove to be incorrect or if the actual reserves available to us (or the operator of an asset in we have an interest) are otherwise less than the current estimates or of lesser quality than expected, we may be unable to recover and produce the estimated levels or quality of natural gas, NGLs or oil set out in this document and this may materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

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

You should not assume that the present value of future net cash flows from our reserves is the current market value of our estimated natural gas, NGL and oil reserves. Actual future net cash flows from our natural gas and oil properties will be affected by factors such as:

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actual prices we receive for natural gas, NGL and oil;

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actual cost of development and production expenditures;

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the amount and timing of actual production;

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transportation and processing; and

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changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of our natural gas and oil properties will affect the timing and amount of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Actual future prices and costs may differ materially from those used in the present value estimate. See the subsection titled “Presentation of Financial Information — Use of Non-IFRS Measures” for additional information regarding our use of PV-10.

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

In the future, we may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for the processing of natural gas and oil reserves. With regards to plugging, we are party to agreements with regulators in the states of Ohio, West Virginia, Kentucky and Pennsylvania, four of our largest wellbore states, setting forth plugging and abandonment schedules spanning a period ranging from 10 to 15 years. We will incur such decommissioning costs at the end of the operating life of some of our properties. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques, the shortage of plugging vendors, difficult terrain or weather conditions or experience at other production sites. The expected timing and amount of expenditure can also change, for example, in response to changes in reserves, wells losing commercial viability sooner than forecasted or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The use of other funds to satisfy such decommissioning costs may impair our ability to focus capital investment in other areas of our business, which could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

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

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies, such as emissions controls and

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processing technologies. Rapid technological advancements in information technology and operational technology domains require seamless integration. Failure to integrate these technologies efficiently may result in operational inefficiencies, security vulnerabilities, and increased costs. During mergers and acquisitions, integrating technology assets from acquired companies can be complex. Poor integration may lead to data inconsistencies, security gaps and operational disruptions. Technology systems are also susceptible to cybersecurity threats, including malware, data breaches, and ransomware attacks. These threats may disrupt operations, compromise sensitive data and lead to significant financial losses. Further, inefficient data management practices may result in data breaches, data loss and missed opportunities for operational insights. The presence of legacy technology systems can also pose challenges, as they may lack modern security features, making them vulnerable to cyber threats and necessitating costly upgrades. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, which may in the future allow them to implement new technologies before we can. Additionally, reliance on global supply chains for information technology hardware, software and operational technology equipment exposes the industry to supply chain disruptions, shortages and cybersecurity risks.

A lowering or withdrawal of the ratings, outlook or watch assigned to us or our debt by rating agencies may increase our future borrowing costs and reduce our access to capital.

The rating, outlook or watch assigned to us or our debt could be lowered or withdrawn entirely by a rating agency if, in that rating agency’s judgment, current or future circumstances relating to the basis of the rating, outlook, or watch such as adverse changes to our business, so warrant. Our credit ratings may also change as a result of the differing methodologies or changes in the methodologies used by the rating agencies. Any future lowering of our debt’s ratings, outlook or watch likely would make it more difficult or more expensive for us to obtain additional debt financing.

It is also possible that such ratings may be lowered in connection with this listing or in connection with future events, such as future acquisitions. Holders of our ordinary shares will have no recourse against us or any other parties in the event of a change in or suspension or withdrawal of such ratings. Any lowering, suspension or withdrawal of such ratings may have an adverse effect on the market price or marketability of our ordinary shares.

If we do not have access to capital on favorable terms, on the timeline we require, or at all, our financial condition and results of operations could be materially adversely affected.

We require capital to complete acquisitions that we believe will enhance shareholder return. Significant volatility or disruption in the global financial markets may result in us not being able to obtain additional financing on favorable terms, on the timeline we anticipate, or at all, and we may not be able to refinance, if necessary, any outstanding debt when due, all of which could have a material adverse effect on our financial condition. Any inability to obtain additional funding on favorable terms, on the timeline we anticipate, or at all, may prevent us from acquiring new assets, cause us to curtail our operations significantly, reduce planned capital expenditures or obtain funds through arrangements that management does not currently anticipate, including disposing of our assets, the occurrence of any of which may significantly impair our ability to deliver shareholder returns. If our operating results falter, our cash flow or capital resources prove inadequate, or if interest rates increase significantly, we could face liquidity problems that could materially and adversely affect our results of operations and financial condition.

The COVID-19 pandemic (or another pandemic or epidemic) may have an adverse effect on our business, results of operations, financial condition, cash flows or prospects.

The COVID-19 pandemic has brought considerable change and is expected to continue to bring considerable change to the risk landscape, increasing the impact of many of our principal risks and creating uncertainty in how the future risk landscape will unfold. For example, the impact of the COVID-19 pandemic on commodity pricing in the second quarter of 2020 led to a sharp decline in production of oil from shale players, consequently impacting the production of associated natural gas. We continue to monitor

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the evolving COVID-19 pandemic and although our operations have not incurred any significant disruption related to COVID-19, the situation is uncertain and could change in the future.

The extent of the impact of the pandemic on our business, results of operations, financial condition, cash flows or prospects will depend largely on future developments, including operational shutdowns due to the unavailability of qualified personnel, third party utilities or spare parts required to safely maintain operations due to outbreaks of COVID-19 or any future pandemics or epidemics, delayed execution of projects or increased project costs due to governmental restrictions and measures put in place to safeguard employees and contractors, such as reducing personnel and deferring discretionary activities at our assets, which may cause delays in expected future cash flows, all of which are highly uncertain and cannot be predicted. This situation continues to evolve, and additional impacts may arise due to COVID-19, or another pandemic or epidemic, that we are not aware of currently. Any negative impact could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects.

Economic conditions in a number of industries in which our customers operate have experienced substantial deterioration in the past, resulting in reduced demand for natural gas and oil. Renewed or continued weakness in the economic conditions of any of the industries we serve or that are served by our customers, or the increased focus by markets on carbon-neutrality, could adversely affect our business, financial condition, results of operation and liquidity in a number of ways. For example:

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demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas business;

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a decrease in international demand for natural gas or NGLs produced in the United States could adversely affect the pricing for such products, which could adversely affect our results of operations and liquidity;

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the tightening of credit or lack of credit availability to our customers could adversely affect our liquidity, as our ability to receive payment for our products sold and delivered depends on the continued creditworthiness of our customers;

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our ability to refinance our Credit Facility may be limited and the terms on which we are able to do so may be less favorable to us depending on the strength of the capital markets or our credit ratings;

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our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our natural gas reserves;

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increased capital markets scrutiny of oil and gas companies may lead to increased costs of capital or lack of credit availability; and

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a decline in our creditworthiness may require us to post letters of credit, cash collateral, or surety bonds to secure certain obligations, all of which would have an adverse effect on our liquidity.

In addition, the COVID-19 pandemic has materially and adversely impacted many businesses, industries and economies. For further detail regarding the risks to our business resulting from COVID-19, see the Risk Factor below titled “— The COVID-19 pandemic (or another pandemic or epidemic) may have an adverse effect on our business, results of operations, financial condition, cash flows or prospects.”

Our operations are subject to a series of risks relating to climate change.

Continued public concern regarding climate change and potential mitigation through regulation could have a material impact on our business. International agreements, national, regional, state and local legislation, and regulatory measures to limit GHG emissions are currently in place or in various stages of discussion or implementation. 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

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for new and existing gas and oil operations. Given that some of our operations are associated with emissions of GHGs, these and other GHG emissions-related laws, policies and regulations may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted by particular countries, states, provinces and municipalities.

Internationally, the United Nations-sponsored “Paris Agreement” requires member nations to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, 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 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Such commitments were re-affirmed at the 27th Conference of the Parties in Sharm El Sheikh. The emission reduction targets and other provisions of legislative or regulatory initiatives and policies enacted in the future by the United States or states in which we operate, could adversely impact our business by imposing increased costs in the form of higher taxes or increases in the prices of emission allowances, limiting our ability to develop new gas and oil reserves, transport hydrocarbons through pipelines or other methods to market, decreasing the value of our assets, or reducing the demand for hydrocarbons and refined petroleum products. With increased pressure to reduce GHG emissions by replacing fossil fuel energy generation with alternative energy generation, it is possible that peak demand for gas and oil will be reached, and gas and oil prices will be adversely impacted as and when this happens. Further, the consequences of the effects of global climate change, and the continued political and societal attention afforded to mitigating the effects of climate change, may generate adverse investor and stakeholder sentiment towards the hydrocarbon industry and negatively impact the ability to invest in the sector. Similarly, longer term reduction in the demand for hydrocarbon products due to the pace of commercial deployment of alternative energy technologies or due to shifts in consumer preference for lower GHG emissions products could reduce the demand for the hydrocarbons that we produce.

Additionally, the SEC’s proposed climate rule published in March 2022, requiring disclosure of a range of climate related risks, is expected to be finalized late-2023. We are currently assessing this rule, and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. 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.

Further, in response to concerns related to climate change, companies in the fossil fuel sector may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to sustainable lending practices, and some of them may elect in the future not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In 2021, President Biden signed an executive order calling for the development of a “climate finance plan,” and, separately, the Federal Reserve announced in 2020 that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, and transportation activities, which could in turn negatively affect our operations.

The Company may also be subject to activism from environmental non-governmental organizations (“NGOs”) campaigning against fossil fuel extraction or negative publicity from media alleging inadequate remedial actions to retire non-producing wells effectively, which could affect our reputation, disrupt our programs, require us to incur significant, unplanned expense to respond or react to intentionally disruptive

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campaigns or media reports, create blockades to interfere with operations or otherwise negatively impact our business, results of operations, financial condition, cash flows or prospects. Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

Finally, our operations are subject to disruption from the physical effects that may be caused or aggravated by climate change. These include risks from extreme weather events, such as hurricanes, severe storms, floods, heat waves, and ambient temperature increases, as well as wildfires, each of which may become more frequent or more severe as a result of climate change.

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

A significant portion of our production passes through third-party owned and controlled infrastructure. If these third-party pipelines or liquids processing facilities experience any event that causes an interruption in operations or a shut-down such as mechanical problems, an explosion, adverse weather conditions, a terrorist attack or labor dispute, our ability to produce or transport natural gas could be severely affected. For example, we have an agreement with a third-party where approximately 51% of the NGLs we sold during the year ending December 31, 2022 were processed at the third-party’s facility in Kentucky. Any material decrease in our ability to process or transport our natural gas through third-party infrastructure could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

Our use of third-party infrastructure may be subject to tariff charges. Although we seek to manage our flow via our midstream infrastructure, we may not always be able to avoid higher tariffs or basis blowouts due to the lack of interconnections. In such instances, the tariff charges can be substantial and the cost is not subject to our direct control, although we may have certain contractual or governmental protections and rights. Generally, the operator of the gathering or transmission pipelines sets these tariffs and expenses on a cost sharing basis according to our proportionate hydrocarbon through-put of that facility. A provisional tariff rate is applied during the relevant year and then finalized the following year based on the actual final costs and final through-put volumes. Such tariffs are dependent on continued production from assets owned by third parties and, may be priced at such a level as to lead to production from our assets ceasing to be economic and thus may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

Furthermore, our use of third-party infrastructure exposes us to the possibility that such infrastructure will cease to be operational or be decommissioned and therefore require us to source alternative export routes and/or prevent economic production from our assets. This could also have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

We rely on our natural gas and oil field suppliers and contractors to provide materials and services that facilitate our production activities, including plugging and abandonment contractors. Any competitive pressures on the oil field suppliers and contractors could result in a material increase of costs for the materials and services required to conduct our business and operations. For example, we are dependent on the availability of plugging vendors to help us satisfy abandonment schedules that we have agreed to with the states of Ohio, West Virginia, Kentucky and Pennsylvania. Such personnel and services can be scarce and may not be readily available at the times and places required. Future cost increases could have a material adverse effect on our asset retirement liability, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of our properties, our planned level of spending for development and the level of our reserves. Prices for the materials and services we depend on to conduct our business may not be sustained at levels that enable us to operate profitably.

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We and our offtakers rely, and any future offtakers will rely, upon the availability of pipeline and storage capacity systems, including such infrastructure systems that are owned and operated by third parties. As a result, we may be unable to access or source alternatives for the infrastructure and systems which we currently use or plan to use, or otherwise be subject to interruptions or delays in the availability of infrastructure and systems necessary for the delivery of our natural gas, NGLs and oil to commercial markets. In addition, such infrastructure may be close to its design life and decisions may be taken to decommission such infrastructure or perform life extension work to maintain continued operations. Any of these events could result in disruptions to our projects and thereby impact our ability to deliver natural gas, NGLs and oil to commercial markets and/or may increase our costs associated with the production of natural gas, NGLs and oil reliant upon such infrastructure and systems. Further, our offtakers could become subject to increased tariffs imposed by government regulators or the third-party operators or owners of the transportation systems available for the transport of our natural gas, NGLs and oil, which could result in decreased offtaker demand and downward pricing pressure.

If we are unable to access infrastructure systems facilitating the delivery of our natural gas, NGLs and oil to commercial markets due to our contractors or primary offtakers being unable to access the necessary equipment or transportation systems, our operations will be adversely affected. If we are unable to source the most efficient and expedient infrastructure systems for our assets then delivery of our natural gas, NGLs and oil to the commercial markets may be negatively impacted, as may our costs associated with the production of natural gas, NGLs and oil reliant upon such infrastructure and systems.

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

A part of our business strategy is to optimize or refurbish producing assets where possible to maximize the efficiency of our operations while avoiding significant expenses associated with purchasing new equipment. Our producing assets and midstream infrastructure require ongoing maintenance to ensure continued operational integrity. For example, some older wells may struggle to produce suitable line pressure and will require the addition of compression to push natural gas. Despite our planned operating and capital expenditures, there can be no guarantee that our assets or the assets we use will continue to operate without fault and not suffer material damage in this period through, for example, wear and tear, severe weather conditions, natural disasters or industrial accidents. If our assets, or the assets we use, do not operate at or above expected efficiencies, we may be required to make substantial expenditures beyond the amounts budgeted. Any material damage to these assets or significant capital expenditure on these assets for improvement or maintenance may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects. In addition, as with planned operating and capital expenditure, there is no guarantee that the amounts expended will ensure continued operation without fault or address the effects of wear and tear, severe weather conditions, natural disasters or industrial accidents. We cannot guarantee that such optimization or refurbishment will be commercially feasible to undertake in the future and we cannot provide assurance that we will not face unexpected costs during the optimization or refurbishment process.

Our future operating results depend in significant part upon the continued contribution of our directors, key senior management and technical, financial and operations personnel. Management of our growth will require, among other things, stringent control of financial systems and operations, the continued development of our control environment, the ability to attract and retain sufficient numbers of qualified management and other personnel, the continued training of such personnel and the presence of adequate supervision.

In addition, the personal connections and relationships of our directors and key management are important to the conduct of our business. If we were to unexpectedly lose a member of our key management or fail to maintain one of the strategic relationships of our key management team, our business, results of operations, financial condition, cash flows or prospects could be materially adversely affected. In particular, we are highly dependent on our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr. Acquisitions

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are a key part of our strategy, and Mr. Hutson has been instrumental in sourcing them and securing their financing. Furthermore, as our founder, Mr. Hutson is strongly associated with our success, and if he were to cease being the Chief Executive Officer, perception of our future prospects may be diminished. We maintain a “key person” life insurance policy on Mr. Hutson, but not any other of our employees. As a result, we are insured against certain losses resulting from the death of Mr. Hutson, but not any of our other employees.

Attracting and retaining additional skilled personnel will be fundamental to the continued growth and operation of our business. We require skilled personnel in the areas of development, operations, engineering, business development, natural gas, NGLs and oil marketing, finance and accounting relating to our projects. Personnel costs, including salaries, are increasing as industry wide demand for suitably qualified personnel increases. We may not successfully attract new personnel and retain existing personnel required to continue to expand our business and to successfully execute and implement our business strategy.

We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas, oil and NGL production operations. Productive zones frequently contain water that must be removed for the natural gas, oil and NGL to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas, oil and NGL in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. We have entered into various water management services agreements in the Appalachian Basin which provide for the disposal of our produced water by established counterparties with large integrated pipeline networks. If these counterparties fail to perform, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase for a number of reasons, including if new laws and regulations require water to be disposed in a different manner.

In 2016, the EPA adopted effluent limitations for the treatment and discharge of wastewater resulting from onshore unconventional natural gas, oil and NGL extraction facilities to publicly owned treatment works. In addition, the injection of fluids gathered from natural gas, oil and NGL producing operations in underground disposal wells has been identified by some groups and regulators as a potential cause of increased seismic events in certain areas of the country, including the states of West Virginia, Ohio and Kentucky in the Appalachian Basin as well as Oklahoma, Texas and Louisiana in our Central Region. Certain states, including those located in the Appalachian Basin have adopted, or are considering adopting, laws and regulations that may restrict or prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic events have occurred to restrict or suspend disposal well permits or operations or impose certain conditions related to disposal well construction, monitoring, or operations. Any of these developments could increase our cost to dispose of our produced water.

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

Pursuant to the authority under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), as amended by the Pipeline Safety Improvement Act of 2002 (“PSIA”), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPESA”) and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

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perform ongoing assessments of pipeline integrity;

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identify and characterize applicable threats to pipeline segments that could impact HCAs;

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of pipeline integrity testing, but the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the safe and reliable operation of our pipelines.

The 2011 Pipeline Safety Act amends the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. Additionally, pursuant to one of the requirements of the 2011 Pipeline Safety Act, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain gas lines, extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond HCAs to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as five dwellings within the potential impact area and require gas pipelines installed before 1970 that were exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”). Other requirements proposed by PHMSA under the rulemaking include: reporting to PHMSA in the event of certain MAOP exceedances; strengthening PHMSA integrity management requirements; considering seismicity in evaluating threats to a pipeline; conducting hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and using more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The proposed rulemaking also seeks to impose a number of requirements on gathering lines. In January 2017, PHMSA finalized new regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to an HCA. The final rule also requires all pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accident reporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure PHMSA regularly revises its pipeline safety regulations. For example, in June 2016, the President signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “2016 PIPES Act”) into law. The 2016 PIPES Act reauthorizes PHMSA through 2019, and facilitates greater pipeline safety by providing PHMSA with emergency order authority, including authority to issue prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities to address imminent hazards, without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements, requiring a review of both natural gas and hazardous liquid integrity management programs, and mandating the creation of a working group to consider the development of an information-sharing system related to integrity risk analyses. The 2016 PIPES Act also requires that PHMSA publish periodic updates on the status of those mandates outstanding from the 2011 Pipeline Safety Act PHMSA has recently published three parts of its so-called “Mega Rule,” including rules focused on: the safety of gas transmission pipelines, the safety of hazardous liquid pipelines and enhanced emergency order procedures. PHMSA finalized the first part of the rule, which primarily addressed maximum operating pressure and integrity management near HCAs for onshore gas transmission pipelines, in October 2019. PHMSA finalized the second part of the rule, which extended federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures, in November 2021. PHMSA published the final of the three components of the Mega Rule in August 2022, which took effect in May 2023. The final rule applies to onshore gas transmission pipelines, and

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clarifies integrity management regulations, expands corrosion control requirements, mandates inspection after extreme weather events, and updates existing repair criteria for both HCA and non-HCA pipelines. Finally, PHMSA published a Notice of Proposed Rulemaking regarding more stringent gas pipeline leak detection and repair requirements to reduce natural gas emissions on May 18, 2023.

At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Moreover as of January 2023, the maximum civil penalties PHMSA can impose are $257,664 per pipeline safety violation per day, with a maximum of $2,576,627 for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA regulations thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. States are also pursuing regulatory programs intended to safely build pipeline infrastructure. The adoption of new or amended regulations by PHMSA or the states that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on us and similarly situated midstream operators.

We are currently operating in a period of economic uncertainty and capital markets disruption, which has been significantly impacted by geopolitical instability due to the ongoing military conflict between Russia and Ukraine, and more recently, the Israel-Hamas war. Our business may be adversely affected by any negative impact on the global economy and capital markets resulting from the conflict in Ukraine or any other geopolitical tensions.

U.S. and global markets are experiencing volatility and disruption following the escalation of geopolitical tensions and the start of the military conflict between Russia and Ukraine. In February 2022, a full-scale military invasion of Ukraine by Russian troops was reported. Although the length and impact of the ongoing military conflict is highly unpredictable, the conflict in Ukraine has led, and could continue to lead, to market disruptions, including significant volatility in commodity prices, credit and capital markets, as well as supply chain interruptions.

Additionally, Russia’s prior annexation of Crimea, recent recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsequent military interventions in Ukraine have led to sanctions and other penalties being levied by the United States, European Union and other countries against Russia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic, and the so-called Luhansk People’s Republic, including agreement to remove certain Russian financial institutions from the Society for Worldwide Interbank Financial Telecommunication (“SWIFT”) payment system, expansive bans on imports and exports of products to and from Russia and bans on the exportation of U.S. denominated banknotes to Russia or persons located there. Additional potential sanctions and penalties have also been proposed and/or threatened. Russian military actions and the resulting sanctions could adversely affect the global economy and financial markets and lead to instability and lack of liquidity in capital markets, potentially making it more difficult for us to obtain additional funds.

Additionally, on October 7, 2023, Hamas, a U.S. designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel. On October 8, 2023, Israel formally declared war on Hamas, and the armed conflict is ongoing as of the date of this filing. Hostilities between Israel and Hamas could escalate and involve surrounding countries in the Middle East. We are actively monitoring the situation in Ukraine and Israel and assessing their impact on our business. To date we have not experienced any material interruptions in our infrastructure, supplies, technology systems or networks needed to support our operations given our operating areas are exclusively located within the Central Region and the Appalachian Basins of the U.S. We have no way to predict the progress or outcome of the conflicts in Ukraine or Israel or their impacts in Ukraine, Russia, Belarus, Israel or the Gaza Strip as the conflicts, and any resulting government reactions, are rapidly developing and beyond our control. The extent and duration of the military actions, sanctions and resulting market disruptions could be significant and could potentially

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have substantial impact on the global economy and our business for an unknown period of time. Any of the aforementioned factors could affect our business, financial condition and results of operations. Any such disruptions may also magnify the impact of other risks described in this registration statement.

Risks Relating to our Financing, Acquisitions, Investment and Indebtedness

Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability to enter into future debt financing.

Inflation can adversely affect us by increasing costs of materials, equipment, labor and other services. In addition, inflation is often accompanied by higher interest rates. Continued inflationary pressures could impact our profitability. Though we believe that the rates of inflation in recent years, including the 12 months ended June 30, 2023, have not had a significant impact on our operations, a continued increase in inflation, including inflationary pressure on labor, could result in increases to our operating costs, and we may be unable to pass these costs on to our customers. These inflationary pressures could also adversely impact our ability to procure materials and equipment in a cost-effective manner, which could result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected. We continue to undertake actions and implement plans to address these inflationary pressures and protect the requisite access to materials and equipment. With respect to our costs of capital, our ABS Notes (as defined below) are fixed-rate instruments (subject to adjustment pursuant to the sustainability-linked features described under “Item 5.B Liquidity and Capital Resources”) and as of June 30, 2023 we had $265 million outstanding on our Credit Facility. Nevertheless, inflation may also affect our ability to enter into future debt financing, including refinancing of our Credit Facility or issuing additional SPV-level asset backed securities, as high inflation may result in a relative increase in the cost of debt capital.

We are taking efforts to mitigate inflationary pressures, by working closely with other suppliers and service providers to ensure procurement of materials and equipment in a cost-effective manner. However, these mitigation efforts may not succeed or may be insufficient.

Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which natural gas, NGLs and oil can be sold, which could affect our results of operations, financial condition, cash flows and prospects.

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

Acquisitions are an essential part of our strategy for protecting and growing cash flow, particularly in relation to the risk that some of our wells may have a higher than anticipated production decline rate. Over the past several years, we have undertaken a number of acquisitions of natural gas and oil assets (and of companies holding such assets), including, but not limited to the acquisition of certain assets of Carbon Energy Corporation (the “Carbon Acquisition”), the acquisition of certain assets and infrastructure of EQT Corporation (the “EQT Acquisition”), the acquisition of certain assets from Triad Hunter, LLC (the “Utica Acquisition”), the acquisition of 51.25% working interest in certain assets and infrastructure from Indigo Minerals LLC (the “Indigo Acquisition”), the acquisition of certain assets and infrastructure from Blackbeard Operating LLC (the “Blackbeard Acquisition”), the acquisition of 51.25% working interest in certain assets, infrastructure, equipment and facilities in conjunction with Oaktree from Tanos Energy Holdings III, LLC (the “Tanos Acquisition”), the acquisition of 51.25% working interest in certain assets, infrastructure, equipment and facilities in conjunction with Oaktree from Tapstone Energy Holdings LLC (the “Tapstone Acquisition”), the acquisition of 52.5% working interest in certain upstream assets and related facilities within the Central Region from a private seller, in conjunction with Oaktree (the “East Texas Assets Acquisition”), the acquisition of certain upstream assets and related infrastructure within the Central Region from Tanos Energy Holdings II LLC (the “Tanos II Acquisition”) and the acquisition of certain upstream assets and related gathering infrastructure in the Central Region from ConocoPhillips (the “Conoco Acquisition”). Our ability to complete future acquisitions will depend on us being able to identify suitable acquisition candidates and negotiate favorable terms for their acquisition, in each case,

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before any attractive candidates are purchased by other parties such as private equity firms, some of whom have substantially greater financial and other resources than we do. We may face competition for attractive acquisition targets that may also increase the price of the target business. As a result, there is no assurance that we will always be able to source and execute acquisitions in the future at attractive valuations.

Furthermore, to further the Company’s growth, we have made further acquisitions outside the Appalachian Basin, a region in which we have developed our operational experience into the Bossier Shale, the Haynesville Shale, the Barnett Shale Play, and the Cotton Valley and Mid-Continent producing areas. Accordingly, an acquisition in a new area in which we lack experience may present unanticipated risks and challenges that were not accounted for or previously experienced. Ordinarily, our due diligence efforts are focused on higher valued and material properties or assets. Even an in-depth review of all properties and records may not reveal all existing or potential problems, nor will such review always permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Generally, physical inspections are not performed on every well or facility, and structural or environmental problems are not necessarily observable even when an inspection is undertaken.

There can be no assurance that our prior acquisitions or any other potential acquisition will perform operationally as anticipated or be profitable. We could fail to appropriately value any acquired business and the value of any business, company or property that we acquire or invest in may actually be less than the amount paid for it or its estimated production capacity. We may be required to assume pre-closing liabilities with respect to an acquisition, including known and unknown title, contractual, and environmental and decommissioning liabilities, and may acquire interests in properties on an “as is” basis without recourse to the seller of such interest or the seller may have limited resources to provide post-sale indemnities.

In addition, successful acquisitions of gas and oil assets require an assessment of a number of factors, including estimates of recoverable reserves, the time of recovering reserves, exploration potential, future natural gas, NGLs and oil prices and operating costs. Such assessments are inexact, and we cannot guarantee that we make these assessments with a high degree of accuracy. In connection with assessments, we perform a review of the acquired assets. However, such a review will not reveal all existing or potential problems. Furthermore, review may not permit us to become sufficiently familiar with the assets to fully assess their deficiencies and capabilities.

Integrating operations, technology, systems, management, back office personnel and pre- or post-completion costs for future acquisitions may prove more difficult or expensive than anticipated, thereby rendering the value of any company or assets acquired less than the amount paid. We may also take on unexpected liabilities which are uncapped, have to undertake unanticipated capital expenditures in connection with a new acquisition or provide uncapped liabilities in connection with the purchase and sale of assets, which are customary in such agreements. The integration of acquired businesses or assets requires significant time and effort on the part of our management. Following such integration efforts, prior acquisitions may still not achieve the level of financial or operational performance that was anticipated when they were acquired. In addition, the integration of new acquisitions can be difficult and disrupt our own business because our operational and business culture may differ from the cultures of the acquired businesses, unpopular cost-cutting measures may be required, internal controls may be more difficult to maintain and control over cash flows and expenditures may be difficult to establish. If we encounter any of the foregoing issues in relation to one of our acquisitions this could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. However, we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.

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In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

Our Credit Facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

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

Although we believe that we take due care and conduct due diligence on new acquisitions in a manner that is consistent with industry practice, there can be no assurance that we have good title to all our assets and the rights to develop and produce natural gas and oil from our assets. Such reviews are inherently incomplete and it is generally not feasible to review in depth every individual well or field involved in each acquisition. There can be no assurance that any due diligence carried out by us or by third parties on our behalf in connection with any assets that we acquire will reveal all of the risks associated with those assets, and the assets may be subject to preferential purchase rights, consents and title defects that were not apparent at the time of acquisition. We may acquire interests in properties on an “as is” basis without recourse to the seller of such interest or the seller may have limited resources to provide post-sale indemnities. In addition, changes in law or change in the interpretation of law or political events may arise to defeat or impair our claim to certain properties which we currently own or may acquire which could result in a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

The issuance of additional ordinary shares in the Company in connection with future acquisitions or other growth opportunities, any share incentive or share option plan or otherwise may dilute all other shareholdings.

We may seek to raise financing to fund future acquisitions and other growth opportunities. We may, for these and other purposes, issue additional equity or convertible equity securities. As a result, existing holders of ordinary shares may suffer dilution in their percentage ownership or the market price of the ordinary shares may be adversely affected.

As of June 30, 2023, we have issued options under our equity incentive plans to employees and executive directors for a total of 4,784,274 new ordinary shares of the Company, all of which are currently outstanding, and have also entered into restricted stock unit agreements and performance stock unit agreements with certain employees, of which 9,361,961 restricted stock units and 16,294,943 performance stock units are outstanding. We may, in the future, issue further options and/or warrants to subscribe for new ordinary shares to certain advisers, employees, directors, senior management and/or consultants of the Company. The exercise of any such options would result in a dilution of the shareholdings of other investors. Additionally, although we currently have no plans for an offering of ordinary shares, it is possible that we may decide to offer additional ordinary shares in the future. Subject to any applicable pre-emption rights, any future issues of ordinary shares by the Company may have a dilutive effect on the holdings of shareholders and could have a material adverse effect on the market price of ordinary shares as a whole.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our Credit Facility contains a number of significant covenants that may limit our ability to, among other things:

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incur additional indebtedness;

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incur liens;

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sell assets;

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make certain debt payments;

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enter into agreements that restrict or prohibit the payment of dividends;

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limits our subsidiaries’ ability to make certain payments with respect to their equity, based on the pro forma effect thereof on certain financial ratios, which would be the source of distributable profits from which we may issue a dividend; and

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conduct hedging activities.

In addition, our Credit Facility requires us to maintain compliance with certain financial covenants.

We may also be prevented from taking advantage of business opportunities that arise because of the limitations from the restrictive covenants under our Credit Facility. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities.

A breach of any covenant in our Credit Facility will result in a default under the agreement and may result in an event of default under the Credit Facility if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under our Credit Facility and in an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Any significant reduction in our borrowing base under our Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, unilaterally determine based upon our reserve reports for the applicable period and other data and reports. Such determinations will be made on a regular basis semi-annually (each a “Scheduled Redetermination”) and at the option of the lenders with more than 66.6% of the loans and commitments under the Credit Facility, no more than one time in between each Scheduled Redetermination. As of the date hereof, our borrowing base is $425 million.

In the future, we may not be able to access adequate funding under our Credit Facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a borrowing base redetermination, or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender’s portion. Declines in commodity prices from their current levels could result in a determination to lower the borrowing base and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to make acquisitions or otherwise carry out business plans, which could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

Through limited purpose, bankruptcy-remote, wholly owned subsidiaries (“SPVs”), we have securitized and expect to securitize in the future, certain of our assets to generate financing. In such transactions, we convey a pool of assets to an SPV, that, in turn, issues certain securities or enters into certain debt agreements, such as our Term Loan I. The securities issued by the SPVs and the Term Loan I are each collateralized by a pool of assets. In exchange for the transfer of finance receivables to the SPV, we typically receive the cash proceeds from the sale of the securities or entering into term loans.

Although our SPVs have successfully completed securitizations in connection with the Term Loan I, the ABS I Notes, ABS II Notes, ABS III Notes, ABS IV Notes, ABS V Notes and ABS VI Notes (each as defined herein), there can be no assurance that we, through our SPVs, will be able to complete additional securitizations, particularly if the securitization markets become constrained. In addition, the value of any securities that our limited purpose, bankruptcy-remote, wholly owned subsidiaries retain in our

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securitizations, including securities retained to comply with applicable risk retention rules, might be reduced or, in some cases, eliminated as a result of an adverse change in economic conditions or the financial markets. In addition, our Term Loan I, ABS I Notes, ABS II Notes, ABS III Notes, ABS IV Notes, ABS V Notes and ABS VI Notes are subject to customary accelerated amortization events, including events tied to the failure to maintain stated debt service coverage ratios.

If it is not possible or economical for us to securitize our assets in the future, we would need to seek alternative financing to support our operations and to meet our existing debt obligations, which may be less efficient and more expensive than raising capital via securitizations and may have a material adverse effect on our results of operations, financial condition, cash flows and liquidity.

An increase in interest rates would increase the cost of servicing our indebtedness and could reduce our profitability, decrease our liquidity and impact our solvency.

Our Credit Facility provides for, and our future debt agreements may provide for, debt incurred thereunder to bear interest at variable rates. As of June 30, 2023, we had $265 million outstanding on our Credit Facility. Increases in interest rates would increase the cost of servicing indebtedness under our Credit Facility or under future debt agreements subject to interest at variable rates, and materially reduce our profitability, decrease our liquidity and impact our solvency. As of October 31, 2023, we had $313 million outstanding on our Credit Facility.

Our hedging activities could result in financial losses or could reduce our net income.

To achieve more predictable cash flows, we employ a hedging strategy involving opportunistically hedging a majority of our first two years of production as well as hedging a significant percentage of production beyond our first two years of forecasted production. Even so, the remainder of our production that is unhedged is exposed to the continuing and prolonged declines in the prices of natural gas, NGLs and oil. Our results of operations and financial condition would be negatively impacted if the prices of natural gas, NGLs or oil were to remain depressed or decline materially from current levels. To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of natural gas, NGLS and oil, we may enter into additional hedging arrangements for a significant portion of our production.

Our derivative contracts may result in substantial gains or losses. For example, we reported an operating loss of $671 million for the year ended December 31, 2022, compared with an operating loss of $467 million for the year ended December 31, 2021. While our earnings are impacted by a variety of factors as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” a key driver of our year over year increase in operating loss was attributable to an increase of $209 million in the mark-to-market valuation adjustment on our derivative financial instrument valuations to $861 million in 2022 from $652 million in 2021. There can be no assurance that we will not realize additional losses due to our hedging activities in the future. In addition, if we enter into any derivative contracts and experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Our ability to use hedging transactions to protect us from future natural gas, NGL and oil price volatility will be dependent upon natural gas, NGL and oil prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes. In addition, if commodity prices remain low, we will not be able to replace our hedges or enter into new hedges at favorable prices.

Our price hedging strategy and future hedging transactions will be determined at our discretion, subject to the terms of certain agreements governing our indebtedness. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our natural gas, NGL and oil revenues becoming more sensitive to commodity price fluctuations.

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The failure of our hedge counterparties to meet their obligations to us may adversely affect our financial results.

An attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by the counterparty to these derivative contracts when they become due would have a material adverse effect on our results of operations, financial condition, cash flows and prospects.

We may not be able to enter into commodity derivatives on favorable terms or at all.

To achieve a more predictable cash flow, we employ a hedging strategy involving opportunistically hedging a majority of our first two years of production as well as hedging a significant percentage of production beyond our first two years of forecasted production. If we are unable to maintain sufficient hedging capacity with our counterparties, we could have greater exposure to changes in commodity prices and interest rates, which could have a material adverse impact on our business, results of operations, financial condition, cash flows or prospects.

Risks Relating to Legal, Tax, Environmental and Regulatory Matters

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

We operate in an industry that has certain inherent hazards and risks, and consequently we are subject to stringent and comprehensive laws and regulations, especially with regard to the protection of health, safety and the environment. For example, we are subject to laws and regulations related to occupational safety and health, hydraulic fracturing activities, air emissions, soil and water quality, the protection of threatened and endangered plant and animal species, biodiversity and ecosystems, and the safety of our assets and employees. Although we believe that we have adequate procedures in place to mitigate operational risks, there can be no assurances that these procedures will be adequate to address every potential health, safety and environmental hazard, and a failure to adequately mitigate risks may result in loss of life, injury, or adverse impacts on the health of employees, contractors and third-parties or the environment. Any failure by us or one of our subcontractors, whether inadvertent or otherwise, to comply with applicable legal or regulatory requirements may give rise to civil, administrative and/or criminal liabilities, civil fines and penalties, delays or restrictions in acquiring or disposing of assets and/or delays in securing or maintaining required permits, licenses and approvals. Further, a lack of regulatory compliance may lead to denial, suspension, or termination of permits, licenses, or approvals that are required to operate our sites or could result in other operational restrictions or obligations. Our health, safety and environmental policies require us to observe local, state and national legal and regulatory requirements and to apply generally accepted industry best practices where legislation or regulation does not exist.

The terms and conditions of licenses, permits, regulatory orders, approvals or permissions may include more stringent operational, environmental and/or health and safety requirements. Obtaining development or production licenses and permits may become more difficult or may be delayed due to federal, regional, state or local governmental constraints, considerations, or requirements on issuing. Furthermore, third-parties such as environmental NGOs may administratively or judicially contest or protest licenses and permits already granted by relevant authorities or applications for the same and operations may be subject to other administrative or judicial challenges.

In addition, under certain environmental laws and regulations, we could be subject to joint and several strict liability for the removal or remediation of previously released materials, pollution, or property contamination regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties on or adjacent to well sites and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property

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damage. In addition, the risk of accidental spills or releases of pollutants or contaminants could expose us to significant liabilities that could have a material adverse effect on our business, financial condition and results of operations.

We incur, and expect to continue to incur, capital and operating costs in an effort to comply with increasingly complex operational health and safety and environmental laws and regulations. New laws and regulations, the imposition of more stringent requirements in permits and licenses, increasingly strict enforcement of, or new interpretations of, existing laws, regulations and permits and licenses, or the discovery of previously unknown contamination or hazards may require further costly expenditures to, for example:

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modify operations, including an increase in plugging and abandonment operations;

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install or upgrade pollution or emissions control equipment;

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perform site clean ups, including the remediation and reclamation of gas and oil sites;

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curtail or cease certain operations;

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provide financial securities, bonds, and/or take out insurance; or

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pay fees or fines or make other payments for pollution, discharges to the environment or other breaches of environmental or health and safety requirements or consent agreements with regulatory agencies.

We cannot predict with any certainty the full impact of any new laws, regulations, or policies on our operations or on the cost or availability of insurance to cover the risks associated with such operations. The costs of such measures and liabilities related to potential operational health and safety or environmental risks associated with the Company may increase, which could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects. In addition, it is not possible to predict what future operational health and safety or environmental laws and regulations will be enacted or how current or future operational, health, safety or environmental laws and regulations will be applied or enforced. We may have to incur significant expenditure for the installation and operation of additional systems and equipment for monitoring and carry out remedial measures in the event that operational health and, safety and environmental regulations become more stringent or costly reform is implemented by regulators. Any such expenditure may have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects. No assurance can be given that compliance with occupational health and safety and environmental laws or regulations in the regions where we operate will not result in a curtailment of production or a material increase in the cost of production or development activities.

Increasing attention to ESG matters may impact our business and financial results.

Increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ board of directors and promoting the use of alternative forms of energy. These activities may result in demand shifts for oil and natural gas products and additional governmental investigations and private ligation against us. In addition, a failure to comply with evolving investor or customer expectations and standards or if we are perceived to not have responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operation.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other companies or industries, which could have a negative impact on our stock price and our

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access to and costs of capital. Also, institutional lenders may decide not to provide funding for oil and natural gas companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

The current U.S. administration, acting through the executive branch and/or in coordination with Congress, could enact rules and regulations that impose more onerous permitting and other costly environmental, health and safety requirements on our operations.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change-related commitments expressed by some political candidates who are now, or may in the future be, in political office.

While our operations are largely not conducted on federal lands, we may in the future consider acquisitions of natural gas and oil assets located in areas in which the development of such assets would require permits and authorizations to be obtained from or issued by federal agencies. To conduct these operations, we may be required to file applications for permits, seek agency authorizations and comply with various other statutory and regulatory requirements. Further, new oil and gas leasing on public lands has been the subject of recent proposed reforms, including bans in certain areas, raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases. Complying with any of these requirements may adversely affect our ability to conduct operations at the costs and in the time periods anticipated, and may consequently adversely impact our anticipated returns from our operations.

Presidential or congressional actions could adversely affect our operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements. Any such measures or increased costs could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

Our operations are dependent on our compliance with obligations under permits, licenses, contracts and field development plans.

Our operations must be carried out in accordance with the terms of permits, licenses, operating agreements, annual work programs and budgets. Fines, penalties, or enforcement actions may be imposed and a permit or license may be suspended or terminated if a permit or license holder, or party to a related agreement, fails to comply with its obligations under such permit, license or agreement, or fails to make timely payments of levies and taxes for the licensed activity, or fails to provide the required geological information or meet other reporting requirements. It may from time to time be difficult to ascertain whether we have complied with obligations under permits or licenses as the extent of such obligations may be unclear or ambiguous and regulatory authorities in jurisdictions in which we do business, or in which we may do business in the future, may not be forthcoming with confirmatory statements that work obligations have been fulfilled, which can lead to further operational uncertainty.

In addition, we and our commercial partners, as applicable, have obligations to operate assets in accordance with specific requirements under certain licenses and related agreements, field development agreements, laws and regulations. If we or our partners were to fail to satisfy such obligations with respect to a specific field, the license or related agreements for that field may be suspended, revoked or terminated. Although we have in the past acquired and may in the future acquire shale assets, a significant source of our natural gas and crude oil remains conventional wells. In some instances, these conventional wells are located on the same property as unconventional wells that produce shale oil. In these cases, the rights to access the shale layers of the property will typically be conditioned on the ongoing productivity of conventional wells on the property. Furthermore, the shale rights may be owned by a third party, and in such instances, we will enter into a joint use agreement with the third party. This joint use agreement may stipulate that in consideration for permission to operate the conventional wells, we are to use reasonable efforts to maintain production so that the third party retains the shale licenses. If we fail to maintain production in the conventional wells, under the joint use agreement, we may be liable to the third party for replacing the lost land rights. The relevant authorities are typically authorized to, and do from time to time, inspect to verify compliance by us or our commercial partners, as applicable, with relevant laws and the licenses or the agreements pursuant to which we conduct our business. There can be no assurance that the views of the

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relevant government agencies regarding the development of the fields that we operate or the compliance with the terms of the licenses pursuant to which we conduct such operations will coincide with our views, which might lead to disagreements that may not be resolved.

The suspension, revocation, withdrawal or termination of any of the permits, licenses or related agreements pursuant to which we may conduct business, as well as any delays in the continuous development of or production at our fields caused by the issues detailed above could materially and adversely affect our business, results of operations, financial condition, cash flows or prospects. In addition, failure to comply with the obligations under the permits, licenses or agreements pursuant to which we conduct business, whether inadvertent or otherwise, may lead to fines, penalties, restrictions, enforcement actions brought by governmental authorities, withdrawal of licenses and termination of related agreements.

We do not insure against certain risks and our insurance coverage may not be adequate for covering losses arising from potential operational hazards and unforeseen interruptions.

We insure our operations in accordance with industry practice and plan to continue to insure the risks we consider appropriate for our needs and circumstances. However, we may elect not to have insurance for certain risks, due to the high premium costs associated with insuring those risks or for various other reasons, including an assessment in some cases that the risks are remote.

Our insurance may not be adequate to cover all losses or liabilities we may suffer. We cannot assure that we will be able to obtain insurance coverage at reasonable rates (or at all), or that any coverage we or the relevant operator obtain, and any proceeds of insurance, will be adequate and available to cover any claims arising. We may become subject to liability for pollution, blow-outs or other hazards against which we have not insured or cannot insure, including those in respect of past activities for which we were not responsible. Any indemnities we may receive from sub-contractors, operators or joint venture partners may be difficult to enforce if such sub-contractors, operators or joint venture partners lack adequate resources.

Operational insurance policies are usually placed in one year contracts and the insurance market can withdraw cover for certain risks due to events occurring in other parts of the industry, thus greatly increasing the costs of risk transfer. For example, in September 2018, a gas pipeline operated by another midstream company exploded in Beaver County, Pennsylvania, a state in which we have operations. The explosion resulted in the destruction of residential property and motor vehicles as well as the evacuation of nearby households. Catastrophic events such as these may cause the insurance costs for our midstream operations to rise, despite us not being involved in the catastrophic event. In the event that insurance coverage is not available or our insurance is insufficient to fully cover any losses, including losses incurred due to lost revenues resulting from third party operations or processing plants, claims and/or liabilities incurred, or indemnities are difficult to enforce, our business and operations, financial results or financial position may be disrupted and adversely affected.

The payment by our insurers of any insurance claims may result in increases in the premiums payable by us for our insurance coverage and could adversely affect our financial performance. In the future, some or all of our insurance coverage may become unavailable or prohibitively expensive.

Our internal systems and website may be subject to intentional and unintentional disruption, and our confidential information may be misappropriated, stolen or misused, which could adversely impact our reputation and future sales.

We have faced, and may in the future continue to face, cyber-attacks and data security breaches. Such cyber-attacks and breaches are designed to penetrate our network security or the security of our internal systems, misappropriate proprietary information and/or cause interruptions to our services, and we expect to continue to face similar threats in the future. We cannot guarantee that we will be able to successfully prevent all attacks in the future. Such future attacks could include hackers obtaining access to our systems, the introduction of malicious computer code or denial of service attacks. If an actual or perceived breach of our network security occurs, it could adversely affect our business or reputation, and may expose us to the loss of information, litigation and possible liability. An actual security breach could also impair our ability to operate our business and provide products and services to our customers. Additionally, malicious attacks, including cyber-attacks, may damage our assets, prevent production at our producing assets and otherwise

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significantly affect corporate activities. For example, we utilize electronic monitoring of meters and flow rate devices to monitor pressure build-up in our production wells. If there were a cyber-attack that penetrated our monitoring systems such that they provided false readings, this could result in an unknown pressure build-up, creating a dangerous situation which could end up in an explosion. As techniques used to obtain unauthorized access to or to sabotage systems change frequently and may not be known until launched against us or our third-party service providers, we may be unable to anticipate or implement adequate measures to protect against these attacks and our service providers may likewise be unable to do so. Such an outcome would have a material adverse impact on our business, results of operations, financial condition, cash flows or prospects.

In addition, confidential or financial payment information that we maintain may be subject to misappropriation, theft and deliberate or unintentional misuse by current or former employees, third-party contractors or other parties who have had access to such information. Any such misappropriation and/or misuse of our information could result in the Company, among other things, being in breach of certain data protection requirements and related legislation as well as incurring liability to third parties. We expect that we will need to continue closely monitoring the accessibility and use of confidential information in our business, educate our employees and third-party contractors about the risks and consequences of any misuse of confidential information and, to the extent necessary, pursue legal or other remedies to enforce our policies and deter future misuse. If our confidential information is misappropriated, stolen or misused as a result of a disruption to our website or internal systems this could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

Although we maintain insurance to protect against losses resulting from certain of data protection breaches and cyber-attacks, our coverage for protecting against such risks may not be sufficient.

Our operations are subject to the risk of litigation.

From time to time, we may be subject, directly or indirectly, to litigation arising out of our operations and the regulatory environments in our areas of operations. Historically, categories of litigation that we have faced included actions by royalty owners over payment disputes, personal injury claims and property related claims, including claims over property damage, trespass or nuisance. Although we currently face no material litigation that is reasonably expected to have an adverse material impact for which we are not sufficiently indemnified or insured, damages claimed under such litigation in the future may be material or may be indeterminate, and the outcome of such litigation, if determined adversely to us, could individually or in the aggregate, be reasonably expected to have a material and adverse effect on our business, financial position or results of operations. While we assess the merits of each lawsuit and defend ourselves accordingly, we may be required to incur significant expenses or devote significant resources to defend against such litigation. In addition, the adverse publicity surrounding such claims may have a material adverse effect on our business.

We are subject to certain tax risks.

Any change in our tax status or in taxation legislation in the United Kingdom or the United States could affect our ability to provide returns to shareholders. Statements in this document concerning the taxation of holders of our ordinary shares are based on current law and practice, which is subject to change.

We are subject to income taxes in the United Kingdom and the United States, and there can be no certainty that the current taxation regime in the United Kingdom, the United States or other jurisdictions within which we currently operate or may operate in the future will remain in force or that the current levels of corporation taxation will remain unchanged. For example, the U.S. government has imposed a minimum tax on corporations and proposed and may enact significant changes to the taxation of business entities including, among others, an increase in the U.S. federal income tax rate applicable to corporations, like us, and surtaxes on certain types of income. Certain U.S. localities also maintain a severance tax or impact fee on the removal of oil and natural gas from the ground and such tax rates may be increased or new severance taxes or impact fees may be implemented. In addition, in response to current global events and consumer hardship, the United Kingdom announced on May 26, 2022 a new “Energy Profits Levy” on oil and gas exploration and production companies operating in the United Kingdom and the UK Continental Shelf at a rate of 25% (subsequently increased to 35%). As we do not operate our exploration, production or

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extraction activities in the United Kingdom or in the UK Continental Shelf, we do not expect the Energy Profits Levy to impact our headline corporation tax rate in the United Kingdom, however, the taxation of energy companies remains uncertain, particularly in the context of current global events, and the future stability of such tax regimes cannot be guaranteed.

Our domestic and international tax liabilities are subject to the allocation of expenses in differing jurisdictions. Our effective tax rate could be adversely affected by changes in the mix of earnings and losses in taxing jurisdictions with differing statutory tax rates, certain non-deductible expenses, the valuation of deferred tax assets and liabilities and changes in federal, state or international tax laws and accounting principles. Increases in our effective tax rate could materially affect our net financial results. Although we believe that our income tax liabilities are reasonably estimated and accounted for in accordance with applicable laws and principles, an adverse resolution of one or more uncertain tax positions in any period could have a material adverse effect on our business, results of operations, financial condition, cash flows or prospects.

In the past we have been able to offset a large portion of our U.S. federal income tax burden with marginal well tax credits that are available to qualified producers who operate lower-volume wells during a low commodity pricing environment. There can be no assurance that there will be no amendment to the existing taxation laws applicable to us, which may have a material adverse effect on our financial position. Our ability to utilize marginal well tax credits in the United States could be or become subject to limitations (for example, if we are deemed to undergo an “ownership change” for applicable U.S. federal income tax purposes).

The nature and amount of tax that we expect to pay and the reliefs expected to be available to us are each dependent upon several assumptions, any one of which may change and which would, if so changed, affect the nature and amount of tax payable and reliefs available. In particular, the nature and amount of tax payable may be dependent on the availability of relief under tax treaties and is subject to changes to the tax laws or practice in any of the jurisdictions we currently are subject to or may be subject to in the future. Any limitation in the availability of relief under these treaties, any change in the terms of any such treaty or any changes in tax law, interpretation or practice could increase the amount of tax payable by us.

Finally, because we are an entity incorporated in the United Kingdom that is treated as a U.S. corporation for all purposes of U.S. federal income tax law, any changes in U.S. federal income tax law could negatively impact our effective tax rate and cash flows, which could cause our business, results of operations, financial condition, cash flows or prospects to be materially adversely affected.

The taxation of an investment in our ordinary shares depends on the individual circumstances of the holders of our ordinary shares. Holders of our ordinary shares are strongly advised to consult their professional tax advisers.

Tax legislation may be enacted in the future that could negatively impact our current or future tax structure and effective tax rates.

Long-standing international tax initiatives that determine each country’s jurisdiction to tax cross-border international trade and profits are evolving as a result of, among other things, initiatives such as the Anti-Tax Avoidance Directives, as well as the Base Erosion and Profit Shifting reporting requirements, mandated and/or recommended by the EU, G8, G20 and Organization for Economic Cooperation and Development, including the imposition of a minimum global effective tax rate for multinational businesses regardless of the jurisdiction of operation and where profits are generated (Pillar Two). As these and other tax laws and related regulations change (including changes in the interpretation, approach and guidance of tax authorities), our financial results could be materially impacted. Given the unpredictability of these possible changes and their potential interdependency, it is difficult to assess whether the overall effect of such potential tax changes would be cumulatively positive or negative for our earnings and cash flow, but such changes could adversely affect our financial results.

Risks Relating to Our Ordinary Shares

Our ordinary shares are subject to market price volatility and the market price may decline disproportionately in response to developments that are unrelated to our operating performance.

The market price of our ordinary shares has been, and may in the future be, volatile and subject to wide fluctuations as a result of a variety of factors including, but not limited to:

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operating results that vary from our financial guidance or the expectations of securities analysts and investors;

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the financial performance of the major end markets that we target;

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the operating and securities price performance of companies that investors consider to be comparable to us;

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announcements of strategic developments, acquisitions and other material events by us or our competitors;

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failure to meet or exceed financial estimates and projections of the investment community or that we provide to the public;

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issuance of new or updated research or reports by securities analysts;

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changes in government regulations;

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financing or other corporate transactions;

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the loss of any of our key personnel;

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sales of our ordinary shares by us, our executive officers and board members or our shareholders in the future;

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price and volume fluctuations in the overall stock market, including as a result of trends in the economy as a whole; and

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other events and factors, many of which are beyond our control.

These and other market and industry factors may cause the market price and demand for our ordinary shares to fluctuate substantially, regardless of our actual operating performance, which may limit or prevent investors from readily selling their ordinary shares and may otherwise negatively affect the liquidity of our ordinary shares. In the past, when the market price of a stock has been volatile, holders of that stock have sometimes instituted securities class action litigation against the issuer. If any of the holders of our ordinary shares were to bring such a lawsuit against us, we could incur substantial costs defending the lawsuit and the attention of our senior management would be diverted from the operation of our business. Any adverse determination in litigation could also subject us to significant liabilities.

Prior to this listing, we had a limited public market in the United States for our ordinary shares, and an active market may not develop in which investors can resell our ordinary shares.

Prior to this listing, there was a limited public market in the United States for our ordinary shares on the OTCQX, although our ordinary shares have traded on the Main Market of the LSE. We cannot predict the extent to which an active market for our ordinary shares in the United States will develop or be sustained or how the development of such a market might affect the market price for our ordinary shares. The initial price of our ordinary shares in the United States will be based on a number of factors, including the trading price of our ordinary shares on the LSE, which may not be indicative of the price at which our ordinary shares will trade following completion of the listing.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our ordinary shares. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

The dual listing of our ordinary shares following this listing may adversely affect the liquidity and value of our ordinary shares.

Following this listing and after our ordinary shares begin trading on the New York Stock Exchange (“NYSE”), our ordinary shares will continue to be admitted to the premium segment of the Official List of

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the Financial Conduct Authority and to trading on the Main Market of the LSE. We cannot predict the effect of this dual listing on the value of our ordinary shares. However, the dual listing of our ordinary shares may dilute the liquidity of these securities in one or both markets and may adversely affect the development of an active trading market for our ordinary shares in the United States.

The requirements of being a U.S. public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

Upon becoming a U.S. public company, we will be required to comply with new laws, regulations and requirements, certain corporate governance provisions of Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and will significantly increase our costs and expenses. We will need to: institute a more comprehensive compliance function to test and conclude on the sufficiency of our internal control over financial reporting; comply with rules promulgated by the NYSE; prepare and distribute periodic public reports; establish new internal policies, such as those relating to insider trading; and involve and retain to a greater degree outside professionals in the above activities. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls does not address all relevant financial statement risks. In our second annual report on Form 20-F, our independent registered public accounting firm must attest to the effectiveness of our internal control over financial reporting. Our independent registered public accounting firm may issue a report that concludes it does not believe our internal control over financial reporting is effective. Compliance with Sarbanes-Oxley Act requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a U.S. public company, we will be subject to significant regulatory oversight and reporting obligations under U.S. federal securities laws and the continuous scrutiny of securities analysts and investors. In addition, most members of our management team have limited experience managing a U.S. public company, interacting with U.S. public company investors, and complying with the increasingly complex laws pertaining to U.S. public companies. Our management team may not successfully or efficiently manage us as a U.S. public company. These new obligations and constituents require significant attention from our management team and could divert our management team’s attention away from the day-to-day management of our business, which could adversely affect our business, results of operations and financial condition.

Further, we expect that being a U.S. public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

We qualify as a foreign private issuer and, as a result, we will not be subject to U.S. proxy rules and will be subject to Exchange Act reporting obligations that, to some extent, are more lenient and less frequent than those of a U.S. domestic public company.

Following this listing, we will report under the Exchange Act as a non-U.S. company with foreign private issuer status. Because we qualify as a foreign private issuer under the Exchange Act, we are exempt from certain provisions of the Exchange Act that are applicable to U.S. domestic public companies, including (i) the sections of the Exchange Act regulating the solicitation of proxies, consents or authorizations in respect of a security registered under the Exchange Act; (ii) the sections of the Exchange Act requiring insiders to file public reports of their stock ownership and trading activities and liability for insiders who profit from trades made in a short period of time; and (iii) the rules under the Exchange Act requiring the filing with the SEC of quarterly reports on Form 10-Q containing unaudited financial and other specified information, or current reports on Form 8-K, upon the occurrence of specified significant events. In addition, foreign private issuers are not required to file their annual report on Form 20-F until 120 days

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after the end of each fiscal year, while U.S. domestic issuers that are accelerated filers are required to file their annual report on Form 10-K within 75 days after the end of each fiscal year. Foreign private issuers also are exempt from Regulation Fair Disclosure, aimed at preventing issuers from making selective disclosures of material information. As a result of the above, you may not have the same protections afforded to shareholders of companies that are not foreign private issuers, some investors may find the ordinary shares less attractive, and there may be a less active trading market for the ordinary shares.

As a foreign private issuer, we are permitted to adopt certain home country practices in relation to corporate governance matters that differ significantly from the corporate governance listing standards of the NYSE. These practices may afford less protection to shareholders than they would enjoy if we complied fully with the corporate governance listing standards of the NYSE.

As a foreign private issuer listed on the NYSE, we will be subject to corporate governance listing standards. However, NYSE rules permit a foreign private issuer like us to follow the corporate governance practices of its home country in lieu of certain NYSE corporate governance listing standards, provided that we disclose which requirements that we have not complied with in any year and confirm the UK corporate governance practices we have complied with. Certain corporate governance practices in the United Kingdom, which is our home country, may differ significantly from the NYSE corporate governance listing standards. Although we voluntarily comply with the higher corporate governance standards of the UK Corporate Governance Code, we could include non-independent directors as members of our nomination and remuneration committee, and our independent directors would not necessarily hold regularly scheduled meetings at which only independent directors are present. We may in the future elect to follow home country practices in the United Kingdom with regard to other matters. Therefore, our shareholders may be afforded less protection than they otherwise would have under the NYSE corporate governance listing standards applicable to U.S. domestic issuers. See “Item 6.Directors, Senior Management and Employees — C. Board Practices.”

We may lose our foreign private issuer status, which would then require us to comply with the Exchange Act’s domestic reporting regime and cause us to incur significant legal, accounting and other expenses.

As a foreign private issuer, we are not required to comply with all of the periodic disclosure and current reporting requirements of the Exchange Act applicable to U.S. domestic issuers. To the extent we no longer qualify as a foreign private issuer as of June 30, 2024 (the end of our second fiscal quarter in the fiscal year after this listing), we would be required to comply with all of the periodic disclosure and current reporting requirements of the Exchange Act applicable to U.S. domestic issuers as of July 1, 2024. In order to maintain our current status as a foreign private issuer, either (a) a majority of our ordinary shares must be either directly or indirectly owned of record by non-residents of the United States or (b)(i) a majority of our executive officers or directors cannot be U.S. citizens or residents, (ii) more than 50% of our assets must be located outside the United States and (iii) our business must be administered principally outside the United States. If we lose our status as a foreign private issuer, we would be required to comply with the Exchange Act reporting and other requirements applicable to U.S. domestic issuers, including the requirement to prepare our financial statements in accordance with U.S. generally accepted accounting principles, which are more detailed and extensive than the requirements for foreign private issuers. We may also be required to make changes in our corporate governance practices in accordance with various SEC and NYSE rules. The regulatory and compliance costs to us under U.S. securities laws if we are required to comply with the reporting requirements applicable to a U.S. domestic issuer may be significantly higher than the cost we would incur as a foreign private issuer. As a result, we expect that a loss of foreign private issuer status would increase our legal and financial compliance costs and would make some activities highly time consuming and costly. If we lose foreign private issuer status and are unable to comply with the reporting requirements applicable to a U.S. domestic issuer by the applicable deadlines, we would not be in compliance with applicable SEC rules or the rules of NYSE, which could cause investors could lose confidence in our public reports and could have a material adverse effect on the trading price of our ordinary shares. We also expect that if we were required to comply with the rules and regulations applicable to U.S. domestic issuers, it would make it more difficult and expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These rules and regulations could also make it more difficult for us to attract and retain qualified members of our board of directors.

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Failure to comply with requirements to design, implement and maintain effective internal control over financial reporting could have a material adverse effect on our business.

As a UK public company traded on the Main Market of the LSE, we are not required to evaluate our internal control over financial reporting in a manner that meets the rules and regulations of the SEC.

The process of designing and implementing effective internal control over financial reporting is a continuous effort that requires us to anticipate and react to changes in our business and the economic and regulatory environments and to expend significant resources to maintain internal control over financial reporting that is adequate to satisfy our reporting obligations as a U.S. public company. If we are unable to establish or maintain adequate internal control over financial reporting, it could cause us to fail to meet our reporting obligations on a timely basis, result in material misstatements in our consolidated financial statements and harm our results of operations. In addition, we will be required, pursuant to the rules and regulations of the SEC, to furnish a report by management on the effectiveness of our internal control over financial reporting in the second annual report following the completion of this listing. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. Assessing the effectiveness of our internal control over financial reporting will require significant documentation, testing and possible remediation. Testing and maintaining internal control over financial reporting may divert our management’s attention from other matters that are important to our business.

We may not be able to conclude on an annual basis that we have effective internal control over financial reporting or our independent registered public accounting firm may not issue an unqualified opinion on the effectiveness of our internal control over financial reporting. If either we are unable to conclude that we have effective internal control over financial reporting or our independent registered public accounting firm is unable to issue an unqualified opinion on the effectiveness of internal control over financial reporting, investors could lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our ordinary shares.

During the preparation of our December 31, 2021 consolidated financial statements, we identified a material weakness in the design of our internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis.

We did not design and maintain an effective control related to the completeness and accuracy of the data provided to specialists used in business combinations. Although this deficiency did not result in a material misstatement to the consolidated financial statements, this deficiency could result in misstatements in our accounting for acquisitions that we account for as business combinations that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

During 2022, we implemented a remediation plan, primarily consisting of adding control activities to re-validate the completeness and accuracy of the data provided to specialists throughout the business combination business cycle for each acquisition. While we believe our remediation efforts were successful, we are also not required to evaluate our internal control over financial reporting in a manner that meets the rules and regulations of the SEC given our foreign private issuer status as a UK public company. Our independent registered public accounting firm must attest to and report on the effectiveness of our internal control over financial reporting in our second annual report on Form 20-F. No other material weakness in financial reporting has been identified in the years ended 2021 or 2022, or through June 30, 2023.

We will incur increased costs as a result of operating as a public company in the United States, and our management will be required to devote substantial time to new compliance initiatives and corporate governance practices.

As a U.S. public company, we will incur significant legal, accounting and other expenses that we did not incur previously. The Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the listing requirements of NYSE and other applicable securities rules and regulations impose various

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requirements on non-U.S. reporting public companies, including the establishment and maintenance of disclosure controls and procedures, internal control over financial reporting and corporate governance practices. Our management and other personnel will need to devote a substantial amount of time to these compliance initiatives. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time consuming and costly. For example, we expect that these rules and regulations may increase the cost of our director and officer liability insurance.

However, these rules and regulations are often subject to varying interpretations, in many cases due to their lack of specificity, and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices.

Because we may not pay any cash dividends on our ordinary shares in the future, capital appreciation, if any, may be your sole source of gains and you may never receive a return on your investment.

Under current UK law, a company’s accumulated realized profits, so far as not previously utilized by distribution or capitalization, must exceed its accumulated realized losses so far as not previously written off in a reduction or reorganization of capital duly made (on a non-consolidated basis), before dividends can be paid. Therefore, we must have distributable profits before issuing a dividend. Although we historically declared dividends on our ordinary shares, in the future, our board of directors may decide, in its discretion, not to declare and pay dividends based on a number of factors, including our performance and financial condition, cash requirements, future prospects, commodity prices, the performance and dividend yield of our peers, in addition to general economic conditions. Further, the Company’s Credit Facility contains a restricted payment covenant that limits its subsidiaries’ ability to make certain payments with respect to their equity, based on the pro forma effect thereof on certain financial ratios, which would be the source of distributable profits from which we may issue a dividend. Consequently, any historical declared dividends are in no way a guide to potential future dividends and capital appreciation, if any, on our ordinary shares may be your sole source of gains.

There is no guarantee that we will continue to pay dividends on our ordinary shares in the future.

Our ability and the Board’s decision to pay dividends is dependent upon our performance and financial condition, cash requirements, future prospects, commodity prices, the performance and dividend yield of our peers, compliance with the financial covenants and restricted payments covenant in our Credit Facility, profits available for distribution and other factors deemed to be relevant at the time and on the continued health of the markets in which we operate. Further, subsequent to our listing on the NYSE, while our Board’s evaluation of our ability or need to pay dividends will primarily remain a question of the foregoing factors, it will also take into account the performance of our ordinary shares, including relative to our peer group. There can be no guarantee that we will continue to pay dividends in the future on our ordinary shares.

The rights of our shareholders may differ from the rights typically offered to shareholders of a U.S. corporation.

We are incorporated under UK law. The rights of holders of ordinary shares are governed by UK law, including the provisions of the UK Companies Act 2006 (the “Companies Act 2006”), and by our Articles of Association. These rights differ in certain respects from the rights of shareholders in typical U.S. corporations. See “Item 10. Additional Information — B. Memorandum and Articles of Association” in this registration statement for a description of the principal differences between the provisions of the Companies Act 2006 applicable to us and, for example, the Delaware General Corporation Law relating to shareholders’ rights and protections.

Claims of U.S. civil liabilities may not be enforceable against us.

We are incorporated under the laws of the United Kingdom. In addition, certain of our directors and officers reside outside the United States. As a result, it may not be possible for investors to effect service of process within the United States upon such persons or to enforce judgments obtained in U.S. courts against them or us, including judgments predicated upon the civil liability provisions of the U.S. federal securities laws.

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The United States and the United Kingdom do not currently have a treaty providing for recognition and enforcement of judgments (other than arbitration awards) in civil and commercial matters. Consequently, a final judgment for payment given by a court in the United States, whether or not predicated solely upon U.S. securities laws, would not automatically be recognized or enforceable in the United Kingdom. In addition, uncertainty exists as to whether UK courts would entertain original actions brought in the UK against us or our directors or senior management predicated upon the securities laws of the United States or any state in the United States. Provided that certain requirements are met, a final and conclusive monetary judgment for a definite sum obtained against us in U.S. courts (that is not a sum payable in respect of taxes or similar charges or in respect of a fine or a penalty), would be treated by the courts of the UK as a cause of action in itself and sued upon as a debt at common law without any retrial of the issue. Whether the relevant requirements are met in respect of a judgment based upon the civil liability provisions of the U.S. securities laws, including whether the award of monetary damages under such laws would constitute a penalty, is an issue for the court making such decision. If a UK court gives judgment for the sum payable under a U.S. judgment, the UK judgment will be enforceable by methods generally available for this purpose. These methods generally permit the UK court discretion to prescribe the manner of enforcement.

As a result, U.S. investors may not be able to enforce against us or our executive officers, board of directors or certain experts named herein who are residents of the United Kingdom or countries other than the United States any judgments obtained in U.S. courts in civil and commercial matters, including judgments under the U.S. federal securities laws.

General Risks

Events of force majeure may limit our ability to operate our business and could adversely affect our operating results.

The weather, unforeseen events, or other events of force majeure in the areas in which we operate could cause disruptions or suspension of our operations. This suspension could result from a direct impact to our properties or result from an indirect impact by a disruption or suspension of the operations of those upon whom we rely for gathering and transportation. If disruption or suspension were to persist for a long period, our results of operations would be materially impacted.

If securities or industry analysts do not publish research, or publish inaccurate or unfavorable research, about our business, the price of our ordinary shares and our trading volume could decline.

The trading market for our ordinary shares will depend in part on the research and reports that securities or industry analysts publish about us or our business. Securities and industry analysts do not currently, and may never, publish research on us. If no or too few securities or industry analysts commence coverage on us, the trading price for our ordinary shares would likely be negatively affected. In the event securities or industry analysts initiate coverage, if one or more of the analysts who cover us downgrade our ordinary shares or publish inaccurate or unfavorable research about our business, the price of our ordinary shares would likely decline. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, demand for our ordinary shares could decrease, which might cause the price of our ordinary shares and trading volume to decline.

Item 4. Information on the Company.

A. History and Development of the Company

The Company, formerly Diversified Gas & Oil plc, is an independent energy company engaged in the production, marketing and transportation 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. We were incorporated in 2014 in the United

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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 June 30, 2023, we have completed 24 acquisitions for a combined purchase price of approximately $2.6 billion. We had average daily production of 852 MMcfepd and 811 MMcfepd for the six months ended June 30, 2023 and for the year ended 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 ESG 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.

Recent Developments

We announced on July 17, 2023 the sale of undeveloped acres in Oklahoma, within the Company’s Central Region, for net consideration of approximately $16 million.

We announced on September 26, 2023 that we completed the semi-annual borrowing base redetermination of our revolving Credit Facility. The borrowing base under the Credit Facility was increased to $425 million reflective of the addition of certain collateral previously acquired from EQT and certain smaller operators in Appalachia.

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 segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE. The shares trading on AIM were cancelled concurrent to their admittance on the LSE. With the change in corporate name in 2021, our shares listed on the LSE began trading under the new ticker “DEC.”

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 registration statement. We have included our website address solely as an inactive textual reference.

For a description of our principal capital expenditures and divestitures for the three years ended December 31, 2022 and for those currently in progress, see “Item 5. Operating and Financial Review and Prospects”.

B. 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

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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

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Optimization of long-life, low-decline assets to enhance margins and improve cash flow

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Generate consistent shareholder returns through vertical integration, strategic hedging and cost optimization

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Disciplined growth through accretive acquisitions of producing assets

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Maintain a strong balance sheet with ability to opportunistically access capital markets

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Operate assets in a safe, efficient manner with what we believe are industry-leading ESG initiatives

Our Strengths

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Low-risk and low-cost portfolio of assets

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Long-life and low-decline production

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High margin assets benefiting from significant scale and owned midstream and asset retirement infrastructure

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Highly experienced management and operational team

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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 ESG endeavors by seeking to secure future capital allocation for ESG initiatives.

Reserve Data

Summary of Reserves

The following table presents our estimated net proved reserves, Standardized Measure and PV-10 as of December 31, 2022, 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 NSAI, our independent petroleum engineering firm. A copy of the proved reserve report is included as an exhibit to the registration statement of which this registration statement forms a part. See the below subsections titled “— Preparation of Reserve Estimates” and “— Estimation of Proved Reserves” for a definition of proved reserves and the technologies and economic data used in their estimation.

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	December 31, 2022
	SEC Pricing(1)
Proved developed reserves
Natural gas (MMcf)			4,340,779
NGLs (MBbls)			101,931
Oil (MBbls)			14,830
Total proved developed reserves (MBoe)			840,224
Proved undeveloped reserves
Natural gas (MMcf)			8,832
NGLs (MBbls)			—
Oil (MBbls)			—
Total proved undeveloped reserves (MBoe)			1,472
Total proved reserves
Natural gas (MMcf)			4,349,611
NGLs (MBbls)			101,931
Oil (MBbls)			14,830
Total proved reserves (MBoe)			841,696
Prices used
Natural gas (MMBtu)		$	6.36
Oil and NGLs (Bbls)		$	94.14
PV-10 (thousands)
Pre-tax (Non-GAAP)(2)		$	8,825,462
PV of Taxes			(2,082,362)
Standardized Measure		$	6,743,100
Percent of estimated total proved reserves that are:
Natural gas			86.1%
Proved developed			99.8%
Proved undeveloped			0.2%

(1)

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 $6.36 per MMBtu as of December 31, 2022 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 $94.14 per Bbl as of December 31, 2022 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.

(2)

The PV-10 of our proved reserves as of December 31, 2022 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.

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Proved Reserves

As of December 31, 2022, our estimated proved reserves totaled 842 MMBoe, an increase of 9.1% from the prior year-end with a Standardized Measure of $6.7 billion. Natural gas constituted approximately 86.1% of our total estimated proved reserves and 86.1% of our total estimated proved developed reserves. The following table provides a summary of the changes in our proved reserves for the years ended December 31, 2022, 2021 and 2020.

	Total (MBoe)
Total proved reserves as of December 31, 2019		535,979
Extensions and discoveries		—
Revisions to previous estimates		(65,911)
Purchase of reserves in place		108,781
Sales of reserves in place		(547)
Production		(36,538)
Total proved reserves as of December 31, 2020		541,765
Extensions and discoveries		—
Revisions to previous estimates		90,251
Purchase of reserves in place		210,086
Sales of reserves in place		(27,340)
Production		(43,257)
Total proved reserves as of December 31, 2021		771,505
Extensions and discoveries		2,221
Revisions to previous estimates		63,302
Purchase of reserves in place		55,174
Sales of reserves in place		(1,152)
Production		(49,354)
Total proved reserves as of December 31, 2022		841,696

Extensions and Discoveries

In 2022, we elected to participate in select development activities on a non-operated basis generating 2,221 MBoe in reserves.

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

During 2020, no reserves were added from extension or discovery activities.

Revisions to Previous Estimates

During 2022, we recorded 63,302 MBoe 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 64,344 MBoe due to changes in pricing that impacted well economics. These increases were offset by a 1,042 MBoe downward revision for changes in timing.

During 2021, 90,251 MBoe 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.

During 2020, 65,911 MBoe in revisions to previous estimates were primarily associated with changes in the 12-month average realized Henry Hub spot price, which decreased approximately 24% as compared to December 31, 2019.

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Purchase of Reserves in Place

During 2022, 55,174 MBoe of purchases of reserves in place were associated with the East Texas and ConocoPhillips acquisitions. Refer to Note 5 in the Notes to the Consolidated Financial Statements found elsewhere in this registration statement for additional information about these acquisitions.

During 2021, 210,086 MBoe 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 Consolidated Financial Statements found elsewhere in this registration statement for additional information about these acquisitions.

During 2020, 108,781 MBoe of purchases of reserves in place were associated with the Carbon and EQT acquisitions. Refer to Note 5 in the Notes to the Consolidated Financial Statements found elsewhere in this registration statement for additional information about these acquisitions.

Sales of Reserves in Place

During 2022, 1,152 MBoe of sales of reserves in place were primarily associated with the divestitures of non-core assets.

During 2021, 27,340 MBoe 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 Consolidated Financial Statements for additional information about divestitures.

During 2020, 547 MBoe of sales of reserves in place were primarily associated with the divestitures of non-core assets.

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, 2022.

	As of December 31, 2022
Total gross productive wells		77,598
Natural gas wells		74,690
Oil wells		2,908
Total net productive wells		62,176
Natural gas wells		60,847
Oil wells		1,329

	As of December 31, 2022(1)
Total gross in progress wells		7
Total net in progress wells		1

(1)

Comprised of wells in the Appalachian Region.

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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
2022		5		2		—		—		5		2
2021		—		—		—		—		—		—
2020		—		—		—		—		—		—

We drilled no exploratory wells (productive or dry) during the years ended December 31, 2022, 2021 and 2020.

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. As of the date of this registration statement, two of the Appalachian development wells have been completed and five remain in progress.

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, 2022, 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 2020, 2021 and 2022:

	Total (MBoe)
Proved undeveloped reserves as of December 31, 2019		—
Extensions and discoveries		—
Revisions to previous estimates		—
Purchase of reserves in place		—
Sales of reserves in place		—
Converted to proved developed reserves		—
Proved undeveloped reserves as of December 31, 2020		—
Extensions and discoveries		—
Revisions to previous estimates		—
Purchase of reserves in place		584
Sales of reserves in place		—
Converted to proved developed reserves		—

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	Total (MBoe)
Proved undeveloped reserves as of December 31, 2021		584
Extensions and discoveries		1,472
Revisions to previous estimates		—
Purchase of reserves in place		—
Sales of reserves in place		—
Converted to proved developed reserves		(584)
Proved undeveloped reserves as of December 31, 2022		1,472

Extensions and Discoveries

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 1,472 MBoe in proved undeveloped reserves.

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

During 2020, no reserves were added from extension or discovery activities.

Purchase of Reserves in Place

There were no purchases of proved undeveloped reserves in place during 2022.

During 2021, the 584 MBoe 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 Consolidated Financial Statements for additional information about acquisitions.

During 2020, there were no purchases of proved undeveloped reserves in place.

Converted to Proved Developed Reserves

During 2022, we completed the development of the five wells referenced in the preceding paragraph that were under development as of December 31, 2021, thereby converting those wells to proved developed reserves. Total capital expenditures in connection with converting those wells to proved developed reserves were approximately $20 million.

During 2021, no reserves were converted to proved developed reserves.

During 2020, no reserves were converted to proved developed reserves.

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, 2022. Developed acres are acres spaced or assigned to productive wells and does 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 92% of our acreage was held by production at December 31, 2022.

Developed Acreage

Undeveloped Acreage

Total Acreage

Gross(1)

Net(2)

Gross(1)

Net(2)

Gross(1)

Net(2)

As of December 31, 2022

5,049,469

2,742,117

8,009,257

5,516,466

13,058,726

8,258,583

(1)

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.

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(2)

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 oil and gas 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, 2022 that will expire in 2023, 2024 and 2025 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
2023		680,886		678,191
2024		3		3
2025		344		29

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, 2022, 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, 2022 included in this registration statement were independently evaluated by our independent engineers, NSAI, in accordance with petroleum engineering and evaluation standards published by the Society of Petroleum Evaluation Engineers 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 in 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

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of Reservoir Engineering. The Vice President of Reservoir Engineering has been with the Company 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 Company 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 economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, micro-seismic data and well-test data.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of natural gas, NGLs and oil that are ultimately recovered. Estimates of economically recoverable natural gas, NGLs and oil and of future net cash flows are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Item 3. Key Information — D. Risk Factors” for additional information.

Production Volumes, Average Sales Prices and Operating Costs

	Year Ended
	December 31, 2022			December 31, 2021			December 31, 2020
Production
Natural Gas (MMcf)			255,597			234,643			199,667
NGLs (MBbls)			5,200			3,558			2,843
Oil (MBbls)			1,554			592			417
Total production (MBoe)			49,354			43,257			36,538
Average realized sales price
(excluding impact of derivatives settled in cash)
Natural gas (Mcf)		$	6.04		$	3.49		$	1.72
NGLs (Bbls)			36.29			32.53			8.15
Oil (Bbls)			89.85			65.26			36.12
Total (Boe)		$	37.95		$	22.50		$	10.45
Average realized sales price
(including impact of derivatives settled in cash)
Natural gas (Mcf)		$	2.98		$	2.36		$	2.33
NGLs (Bbls)			19.84			15.52			13.95
Oil (Bbls)			72.00			71.68			52.97
Total (Boe)		$	19.80		$	15.08		$	14.40

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	Year Ended
	December 31, 2022			December 31, 2021			December 31, 2020
Operating costs per Boe
LOE(1)		$	3.70		$	2.76		$	2.53
Production taxes(2)			1.50			0.71			0.38
Midstream operating expense(3)			1.44			1.40			1.45
Transportation expense(4)			2.39			1.86			1.24
Total operating expense per Boe		$	9.03		$	6.73		$	5.58

(1)

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

(2)

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.

(3)

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

(4)

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

Significant Fields

The Company operates in four primary fields: (i) Appalachia, which is comprised of the stacked Marcellus and Utica shales (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 Company’s Appalachian region, which is considered significant, or greater than 15% of the Company’s total proved reserves.

	Appalachia
	December 31, 2022		December 31, 2021		December 31, 2020
Production
Natural Gas (MMcf)		180,194		201,635		199,667
NGLs (MBbls)		2,810		2,690		2,843
Oil (MBbls)		423		446		417
Total production (MBoe)		33,265		36,743		36,538

Customers

Our production is generally sold on month-to-month contracts at prevailing market prices. 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. During the year ended December 31, 2020, 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.

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Delivery Commitments

We have contractually agreed to deliver firm quantities of natural gas to various customers, which we expect to fulfill with production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet these commitments. The following table summarizes our total gross commitments, compiled using best estimates based on our sales strategy, as of December 31, 2022.

	Natural gas (MMcf)
2023		61,367
2024		44,162
2025		972
Thereafter		—

Transportation and Marketing

Diversified Energy Marketing, LLC, our wholly owned marketing subsidiary, provides marketing services and contractual pipeline capacity management services primarily for our benefit, but also to certain third parties.

Our transportation infrastructure is diversified and allows us to capitalize on strengthening markets while also providing reliable takeaway capacity. This is principally achieved through our vertically integrated midstream systems and the synergistic nature of our asset base. As a result, our midstream infrastructure allows for access to advantageous pricing year-round and flow assurance while entering into minimal firm transportation agreements.

When prudent, however, we enter into arrangements that capture opportunities related to the marketing and transportation of natural gas, NGLs and oil, which primarily involve the marketing of our own equity production and that of royalty owners that hold interests in our wells. Additionally, from time-to-time, we assume firm transportation agreements when acquiring wells.

Our midstream systems, as well as our arrangements, allow us to access growing high-demand markets in the U.S. Gulf Coast region while low-cost transportation on northeast pipelines allows us to capture in-basin pricing. Certain of our capacity agreements contain multiple extension and reduction options that allow us to adjust our transportation infrastructure as necessary for our production or to capture future market opportunities. As of December 31, 2022, our transportation arrangements provide access to 636 MMcfepd of takeaway capacity. These firm transportation agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.

To date, we have not experienced significant difficulty in transporting or marketing our natural gas, NGLs and oil production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production. See “Risk Factors — Risks Relating to Our Business, Operations and Industry — We may experience delays in production, marketing and transportation.”

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

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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.

Environmental, Health and Safety

Overview

Environmental, health, and safety (“EHS”) management remains a top priority for our company, and we demonstrate our commitment to environmental stewardship in the communities in which we live and operate.

We believe that good business includes improving the safety of assets we have acquired, eliminating and reducing fugitive emissions, consolidating duplicative pipeline networks, eliminating excessive compression facilities and extending the lives of producing wells in order to offset the need to generate supply from newly drilled wells. We seek to take a rigorous approach to managing the potential impacts of production fluid spills, which may include natural gas liquids, oil or produced water. Proper waste management and protection of biodiversity are of high importance to us, and we continuously work to mitigate or manage any impact from these spills.

Our board of directors and employees have a shared commitment to becoming good and trusted stewards of the environment, to ensure that our operations meet or exceed all applicable EHS standards, and to achieve EHS excellence.

We expect a similar commitment to safety and environmental stewardship from our business partners with whom we conduct business, so we utilize a leading supply chain risk management firm to help us prescreen contractors with high safety performance records and then to continuously monitor the contractors’ performance for ongoing compliance with our own expectations as well as with state and federal operating standards.

Total Recordable Incident Rate

We strive to maintain a zero-harm working environment and remain steadfast in our commitment to improving safety performance throughout our footprint. The goal of our occupational health and safety program is to foster a safe and healthy occupational environment for employees and other stakeholders that encounter our operations. Health and safety is a top priority for us and is underscored by our operating performance, as well as our daily operational goals of promoting “Safety — No Compromises.” Our Total Recordable Incident Rate (“TRIR”), defined as the sum of lost time injuries, restricted work injuries and medical treatment injuries per 200,000 work hours, and represents all injuries that require medical treatment in excess of simple first aid, exceeded our goals in 2022 and in 2021 and was driven by a lower frequency of minor incidents throughout the year. Our much improved result in 2022 included several months where we incurred no safety incidents across the organization, reflective of the consistent and continual focus we are investing in our employees. As with any kind of company incident, our senior operations and EHS leadership teams review results with a specific emphasis on root causes and change improvements to

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mitigate future incidents. These mitigation efforts are shared with all employees, whether new to the Company following an acquisition or a long-term employee, to help ensure improved performance in the future.

Preventable Motor Vehicle Accident Rate

With more than 1,200 employees on the road each day, road safety awareness and safe driving are of paramount importance to us; our goal is zero preventable vehicle incidents. Given our expansive asset portfolio across the Appalachian Basin and Central Region, our well tenders and other field employees often spend a significant portion of their days driving. We realized a significant improvement in our preventable Motor Vehicle Accident (“MVA”) Rate, defined as the rate of preventable accidents that occurred during the year per million miles driven by our field personnel, in 2022. We are proud of this accomplishment given the 24.5 million miles driven by our employees during the course of the year largely as a result of the often rural and widespread nature of our asset base and the additional staff members that joined the Company from our 2022 acquisitions. The improvement in our MVA rate can be attributed to our widespread emphasis on safety in our operations, including driving, the use of dedicated training modules and our Safe Passages recognition program for drivers who achieve an accident-free driving record during the calendar year.

Reportable Spills

A spill is the introduction into the environment, other than as authorized and whether intentional or unintentional, of a substance that has the potential to cause adverse effects to the environment, human health or infrastructure. A reportable spill is one that must be disclosed to any regulatory agency where we operate. Intensity rate reflects the reportable volume of oil and produced water spills divided by the total gross volume of oil and produced water handled during the period.

The continued expansion of our operating footprint through Central Region acquisitions has resulted in an increased volume of water produced and handled in our operations due to the geological nature of the formations in the Central Region when compared to Appalachia and the higher concentration of unconventional wells. As a result, we experienced a corresponding increase in the absolute volume of reportable spills compared to prior years of operations, which excluded Central Region operations. We aim for zero spills and continue to seek process enhancements, safety procedures and training to manage and reduce the number of spills in the future.

Our exposure to significant spills of liquid products is inherently low given our current production profile of 86% dry natural gas. Nonetheless, we seek to take a rigorous approach to managing any impact of a potential fluid spill and implement practices and processes to minimize or eliminate such spills.

Socio-Economic Contribution

Our community investments are designed to make long-lasting, positive impacts on the communities where we operate and live. We want our actions and economic contributions to make a difference. We start with employing local people to do local work wherever possible, specifically individuals who care about the communities and environments in which they work and live, and that demonstrate passion in how they approach and accomplish their work every day.

We are committed to balancing our business needs with the needs of the communities in which we and our employees operate. In 2022 and throughout 2023, we have continued to develop company-wide programs to enhance our community outreach, including a new grant-giving program and an employee wellness program. In response to our community outreach and engagement work, we have contributed to nearly 140 different 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, homeless shelters, community and volunteer first responders, and local infrastructure.

Our Approach to ESG

Our approach to ESG management encompasses consideration of our climate, environmental and social impacts as well as our responsibility to conduct business in accordance with high standards of

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governance. Through our commitment to stakeholder engagement and regular consideration of internal and external feedback, we seek to proactively manage the topics most important to our business and corporate strategy. Our objectives to improve and address these key areas have served as the foundation of our ESG efforts and strategy, informing where progress should be tracked, and new forward-looking targets should be set.

Our ESG programs are bolstered by a unique business model focused on two key environmental stewardship approaches which keep our net zero ambitions at the forefront of our decision-making. First, our operational approach to owned assets centers on investments in improving or restoring production, optimizing the integrity and efficiency of our assets and reducing emissions before safely and permanently retiring those assets at the end of their productive life. Additionally, our approach to new acquisition utilizes intentional consideration of the emissions profile and geographic location of target assets in determining their compatibility with our portfolio and our emissions reduction goals. In doing so, we are able to recognize the immediate accretive benefit of the acquisitions to our emissions profile or to develop a near-term plan to achieve those benefits.

While our current environmental focus is on methane reductions, we also continued work on our marginal abatement cost curve (“MACC”) to help share our Scope 1 and 2 net zero greenhouse gas (“GHG”) emissions goals. Further, we are endeavoring to partner our MACC efforts with a new process aimed at building and maintaining real-time emissions intelligence through our emissions analytics and reporting platform in order to enhance the accuracy and power of predictive analytics related to our emissions, thus offering management potential access to better data and more tools for more informed decision-making.

Though our upstream, midstream and asset retirement business units 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. Our OneDEC approach is an effort centered around supporting and encouraging company-wide initiatives by ensuring alignment of our corporate and ESG initiatives with departmental action supported by financial investment and boots on the ground. Thus, we embed our strategic frameworks, values and stewardship business model in our OneDEC culture to align our organization, our goals and our priorities around continued progress.

We view sustainability through the dual lens of seeking to create long-term value for our stakeholders and to ensure our daily actions contribute to a sustainable environment and planet for society at large. When we align our stewardship-focused business model and OneDEC culture with our commitment to ESG, we are doing so with this dual lens in mind.

At Diversified, we challenge ourselves to consider these topics and more when we effectuate our business model, corporate strategy, ESG commitments, daily operations and risk management practices.

Human Capital Management

As of December 31, 2022, we had 1,582 full-time employees.

We have an experienced and professional workforce and continue to grow rapidly through successful acquisitions and, in doing so, we welcomed approximately 160 new employees in 2022. The vast majority of our employee base consists of production employees, including our upstream and midstream field personnel. All other employee positions, including back office, administrative and executive positions, are production support roles.

As part of a coordinated diversity and engagement strategy within our recruitment processes, we have engaged a number of external agencies across specific geographic areas of focus within our operating footprint in support of driving diversity within the Company. The composition of our employee workforce is a reflection of the employees that we retain from the sellers at the time of acquisitions. When coupled with a total annual turnover rate of approximately 17.6%, our opportunity to further diversify our workforce is somewhat limited. Nonetheless, we seek to generate a diverse candidate pool from which we can identify and hire the most qualified individuals, regardless of gender, to the benefit of the Company and our stakeholders.

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Our board of directors currently consists of three females and four males, and our senior management, including our executive committee and its direct reports but excluding the executive director, consisted of 87 employees. Although our board of directors does not currently have any ethnically diverse members, it acknowledges the UK Listing Rules’ requirements of having at least one individual on its board of directors who is from a minority ethnic background, which we are required to comply with by the end of 2023. We intend to add an ethnically diverse member to the board of directors and have engaged a third-party advisor to assist with the search process. The board of directors continues to demonstrate diversity in a wider sense, with directors from the U.S. as well as the UK, bringing a range of domestic and international experience to the board of directors. The board of director’s diverse range of experience and expertise covers not only a wealth of experience of operating in the natural gas and oil industry but also extensive technical, operational, financial, legal and environmental expertise.

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 corresponding state laws and regulations regulate air emissions primarily through permitting and/or emissions control requirements. This affects natural gas production and processing operations. Various activities in our operations are subject to regulation, including pipeline compression, venting and flaring of natural gas, and hydraulic fracturing and completion processes, as well as fugitive emissions from operations. We obtain permits, typically from state or local authorities, to conduct these

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activities. Additionally, we are required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions. Further, emissions from certain proximate and related sources may need to be aggregated to provide for regulation and permitting of a single, major source. Federal and state governmental agencies continue to investigate the potential for emissions from oil and natural gas activities, and further regulation could increase our cost or temporarily restrict our ability to produce. For instance, in November 2021, the Environmental Protection Agency (“EPA”) proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing and storage segments. In November 2022, the EPA issued supplemental proposed regulations that would strengthen and expand on the regulations proposed in 2021. The public comment period for the proposed supplemental regulations closed in February 2023, and the EPA is in the process of finalizing the regulations. Additionally, the Inflation Reduction Act, which was signed into law in August 2022, included a “methane fee” on natural gas emissions from oil and gas operations based on certain emissions intensity thresholds. The EPA plans to finalize rules related to the methane fee in 2023 and expects the new fees to be imposed beginning with emissions reported for calendar year 2024. The impact of future regulatory and legislative developments, if adopted or enacted, could result in increased compliance costs, increased utility costs, additional operating restrictions on our business and an increase in the cost of products generally. Although such costs may impact our business directly or indirectly by impacting our facilities or operations, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding the additional measures and how they will be implemented.

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

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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

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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.

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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 European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Such commitments were re-affirmed at the 27th Conference of the Parties in Sharm El Sheikh. 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 suit 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’s proposed climate rule published in March 2022, requiring the disclosure of a range of climate-related risks, is expected to be finalized late 2023. We are currently assessing this rule, and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. 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.

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

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C. Organizational Structure

The following table sets out details of the Company’s significant subsidiaries as of November 16, 2023:

Name	Country of incorporation/ Principal place of business	Principal activity	Effective interest and proportion of equity held
Diversified Gas & Oil Corporation	United States	Oil and natural gas operations	100
Diversified Production LLC	United States	Oil and natural gas operations	100
Diversified Midstream LLC	United States	Oil and natural gas operations	100
Diversified Energy Marketing, LLC	United States	Oil and natural gas operations	100
Diversified ABS Holdings LLC	United States	Holding company	100
Diversified ABS LLC	United States	Oil and natural gas non-operated assets	100
Diversified ABS Phase II Holdings LLC	United States	Holding company	100
Diversified ABS Phase II LLC	United States	Oil and natural gas non-operated assets	100
Diversified ABS Phase III Holdings LLC	United States	Holding company	100
Diversified ABS Phase III LLC	United States	Holding company	100
Diversified ABS Phase III Upstream LLC	United States	Oil and natural gas non-operated assets	100
Diversified ABS Phase III Midstream LLC	United States	Oil and natural gas non-operated assets	100
Diversified ABS Phase IV Holdings LLC	United States	Holding company	100
Diversified ABS Phase IV LLC	United States	Oil and natural gas non-operated assets	100
Diversified ABS Phase V Holdings LLC	United States	Holding company	100
Diversified ABS Phase V LLC	United States	Oil and natural gas non-operated assets	100
Diversified ABS Phase V Upstream LLC	United States	Oil and natural gas non-operated assets	100
Sooner State Joint ABS Holdings LLC	United States	Holding company	51.25
Diversified ABS Phase VI Holdings LLC	United States	Holding company	100
Diversified ABS Phase VI LLC	United States	Holding company	100
Diversified ABS VI Upstream LLC	United States	Oil and natural gas non-operated assets	100
Oaktree ABS VI Upstream LLC	United States	Oil and natural gas non-operated assets	100
ABS 7 Manager LLC	United States	Holding company	100
DP Lion Equity Holdco LLC	United States	Holding company	100
DP Lion HoldCo LLC	United States	Holding company	100

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Name	Country of incorporation/ Principal place of business	Principal activity	Effective interest and proportion of equity held
DP RBL Co LLC	United States	Holding company	100
DP Legacy Central LLC	United States	Oil and natural gas non-operated assets	100
DP Production Holdings II LLC	United States	Holding company	100
DGOC Holdings Sub II LLC	United States	Holding company	100
DP Bluegrass Holdings LLC	United States	Holding company	100
DP Bluegrass LLC	United States	Oil and natural gas non-operated assets	100
BlueStone Natural Resources II, LLC	United States	Oil and natural gas non-operated assets	100
Cranberry Pipeline Corporation	United States	Oil and natural gas non-operated assets	100
Coalfield Pipeline Company	United States	Oil and natural gas non-operated assets	100
DM Bluebonnet LLC	United States	Oil and natural gas non-operated assets	100
DP Tapstone Energy Holdings, LLC	United States	Holding company	100
DP Legacy Tapstone LLC	United States	Oil and natural gas non-operated assets	100
Chesapeake Granite Wash Trust	United States	Oil and natural gas non-operated assets	50.8
TGG Cotton Valley Assets, LLC	United States	Oil and natural gas non-operated assets	100
Black Bear Midstream Holdings LLC	United States	Holding company	100
Black Bear Midstream LLC	United States	Oil and natural gas non-operated assets	100
Black Bear Liquids LLC	United States	Oil and natural gas non-operated assets	100
Black Bear Liquids Marketing LLC	United States	Oil and natural gas non-operated assets	100
DM Pennsylvania Holdco LLC	United States	Holding company	100
Diversified Energy Group LLC	United States	Holding company	100
Diversified Energy Company LLC	United States	Holding company	100
Next LVL Energy, LLC	United States	Plugging company	100
Splendid Land, LLC	United States	Oil and natural gas non-operated assets	55
Riverside Land, LLC	United States	Oil and natural gas non-operated assets	55
Old Faithful Land, LLC	United States	Oil and natural gas non-operated assets	55
Link Land, LLC	United States	Oil and natural gas non-operated assets	55
Giant Land, LLC	United States	Oil and natural gas non-operated assets	55

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D. Property, Plants and Equipment

Corporate Offices

Our principal executive offices are located at 1600 Corporate Drive, Birmingham, Alabama 35242.

Assets and Operations

We have historically operated within the Appalachian Basin, which covers an area of 185,500 square miles. While the area came to prominence following the discovery of significant shale gas reserves in 2009 in the Utica and Marcellus shales, it has been a major producer of natural gas, NGLs and oil from conventional vertical well development since the late 19th century, making it the oldest producing basin within the United States.

Our asset base is comprised of approximately 77,500 conventional and unconventional, mature, long-life, low decline natural gas and oil producing wells on a gross productive basis. These mature wells benefit from simple and low-cost maintenance operations and require low ongoing capital expenditures. Our well portfolio exhibits an average long-term decline rate of approximately 8.5% and contains certain wells that have an expected life of greater than 50 years. In addition to the upstream assets, our portfolio contains approximately 17,700 miles of natural gas gathering pipelines and a network of compression stations and processing facilities.

The map below shows the geographic locations of our assets as of December 31, 2022.

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Item 4A. Unresolved Staff Comments

Not applicable.

Item 5. Operating and Financial Review and Prospects

The following discussion of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements as of December 31, 2022 and 2021 and for each of the three years in the period ended December 31, 2022 and the Unaudited Condensed Consolidated Interim Financial Statements as of June 30, 2023 and for the six months ended June 30, 2023 and 2022 and related notes (together, the “historical financial information”). The historical financial information has been included in “Item 18. Financial Statements.” The following discussion should also be read in conjunction with other information relating to our business contained in this registration statement, including “Item 3.D. Risk Factors.”

The Historical Financial Information has been prepared in accordance with IFRS as issued by the International Accounting Standards Board.

The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and involves risks and uncertainties. Our actual results could differ materially from those discussed in these statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this registration statement, particularly in “Item 3.D. Risk Factors.”

A. Operating Results

Overview

We are an independent energy company engaged in the production, marketing and transportation of natural gas, as well as oil from our complementary onshore upstream and midstream assets, primarily located within the Appalachian and Central Regions of the United States. 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 flow. We acquire, optimize, produce, transport and retire natural gas from existing wells, seek to optimally steward the resource already developed by others within our industry, reduce the environmental footprint, and sustain important jobs and tax revenues for many local communities. While most companies in our sector are built to explore for 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.

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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 supplement our organic growth, 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 $1.4 billion during the six months ended June 30, 2023 and the years ended December 31, 2022, 2021 and 2020, comprised of:

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March 2023: The Tanos II Assets Acquisition, in which we acquired certain upstream assets and related infrastructure in the Central Region;

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September 2022: The ConocoPhillips Assets Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region

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July 2022: Certain plugging infrastructure in the Appalachian Region;

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May 2022: Certain plugging infrastructure in the Appalachian Region;

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April 2022:

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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;

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Certain midstream assets, inclusive of a processing facility, in the Central Region that was contiguous to our East Texas assets;

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February 2022: Certain plugging infrastructure in the Appalachian Region;

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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;

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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;

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July 2021: The Blackbeard Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region;

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May 2021: The Indigo Acquisition, in which we acquired certain upstream assets and related gathering infrastructure in the Central Region;

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May 2020: The Carbon Acquisition, in which we acquired certain upstream and midstream assets in the Appalachian Region; and

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May 2020: The EQT Acquisition, in which we acquired upstream assets and related gathering infrastructure in the Appalachian 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.

Commodity Price Volatility

Changes in commodity prices may affect the value of our natural gas and oil reserves, operating cash flow and Adjusted EBITDA, regardless of our operating performance. It is impossible to accurately predict