Diversified Energy DRS/A Draft registration statement (amended)

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As confidentially submitted to the Securities and Exchange Commission on October 6, 2022.

Registration No. 333-

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Confidential Submission No. 4
to

FORM F-1

REGISTRATION STATEMENT

UNDER
THE SECURITIES ACT OF 1933

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			1311			Not Applicable
	(State or Other Jurisdiction of Incorporation or Organization)			(Primary Standard Industrial Classification Code Number)			(I.R.S. Employer Identification No.)

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

(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

Benjamin Sullivan
Diversified Energy Company plc
1600 Corporate Drive
Birmingham, Alabama 35242
Tel: +1 205 408 0909

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

David J. Miller
Ryan J. Lynch
Latham & Watkins LLP
301 Congress Avenue, Suite 900
Austin, Texas 78701
+1 737 910 7300

James Inness
Latham & Watkins (London) LLP
99 Bishopsgate
London EC2M 3XF
United Kingdom
+44 20 7710 1000

Douglas V. Getten
Preston Bernhisel
Garrett H. Hughey
Baker Botts L.L.P.
910 Louisiana Street, Suite 3200
Houston, Texas 77002
+1 713 229 1234

Derek Jones
Baker Botts (UK) LLP
Level 30, 20 Fenchurch Street
London EC3M 3BY
United Kingdom
+44 20 7726 3636

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☐

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933. 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 7(a)(2)(B) of the Securities Act. ☐

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the U.S. Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

†

The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

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The information in this preliminary prospectus is not complete and may be changed. We may not sell the securities described herein until the registration statement filed with the Securities and Exchange Commission is declared effective. This preliminary prospectus is not an offer to sell such securities and it is not soliciting an offer to buy such securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED , 2022

P R E L I M I N A R Y P R O S P E C T U S

American Depositary Shares

[MISSING IMAGE: lg_diversifiedenergy-4clr.jpg]

Representing Ordinary Shares

$ per American Depository Share

This is the initial public offering of our American Depositary Shares (“ADSs”) in the United States. We are selling ADSs, which may be evidenced by American Depositary Receipts (“ADR”). Each ADS represents the right to receive ordinary shares. We currently expect the initial public offering price to be between $ and $ per ADS.

We intend to apply to list our ADSs on the (“ ”) under the symbol “DEC.” Our ordinary shares are admitted to the premium segment of the Official List of the Financial Conduct Authority and are admitted to trading on the Main Market of the London Stock Exchange (“LSE”), under the symbol “DEC.” On , 2022, the last reported sale price of our ordinary shares on the LSE was £ per ordinary share (equivalent to $ per ADS based on an assumed exchange rate of £1.00 to $ ). The initial public offering price for our ADSs will be determined through discussions between us and the representatives of the underwriters and will take into consideration, among other factors, the closing price of our ordinary shares on the LSE on the day of pricing.

We are both an “emerging growth company” and a “foreign private issuer” as defined under the U.S. federal securities laws and, as such, are subject to reduced public company disclosure requirements. See the subsections titled “Prospectus Summary—Implications of Being an Emerging Growth Company and a Foreign Private Issuer” on page 12 and “Risk Factors—Risks Relating to Our ADSs and This Offering—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.” on page 46 for additional information.

Investing in our ADSs involves risks. See the section titled “Risk Factors” beginning on page 22 of this prospectus.

Neither the U.S. Securities and Exchange Commission (the “SEC”) nor any U.S. state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Per ADS

Total

Public offering price

Underwriting discounts and commissions(1)

Proceeds to Diversified Energy Company plc (before expenses)

(1)

We have agreed to reimburse the underwriters for certain expenses incurred in this offering. See the section titled “Underwriting.”

The underwriters have the option to purchase up to an additional ADSs from us at the initial public offering price, less the underwriting discounts and commissions, for 30 days after the date of this prospectus.

The underwriters expect to deliver the ADSs to purchasers on or about , 2022 through the book-entry facilities of the Depository Trust Company.

Citigroup

, 2022

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	Page
COMMONLY USED DEFINED TERMS		ii
ABOUT THIS PROSPECTUS		vii
PRESENTATION OF FINANCIAL INFORMATION		viii
MARKET AND INDUSTRY DATA		x
PROSPECTUS SUMMARY		1
RISK FACTORS		22
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		55
USE OF PROCEEDS		57
DIVIDEND POLICY		58
CAPITALIZATION		59
DILUTION		60
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		62
BUSINESS		97
MANAGEMENT		113
PRINCIPAL SHAREHOLDERS		126
RELATED PARTY TRANSACTIONS		128
DESCRIPTION OF SHARE CAPITAL AND ARTICLES OF ASSOCIATION		129
DESCRIPTION OF AMERICAN DEPOSITARY SHARES		147
SHARES AND ADSS ELIGIBLE FOR FUTURE SALE		155
MATERIAL TAX CONSIDERATIONS		157
UNDERWRITING		165
EXPENSES OF THE OFFERING		172
LEGAL MATTERS		173
EXPERTS		174
SERVICE OF PROCESS AND ENFORCEMENT OF CIVIL LIABILITIES		175
WHERE YOU CAN FIND ADDITIONAL INFORMATION		177
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		F-1

For investors outside the United States: neither we nor the underwriters have done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction, other than the United States, where action for that purpose is required. Persons outside the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of our ADSs and the distribution of this prospectus outside the United States.

Neither we nor the underwriters have authorized anyone to provide you with any information or to make any representations other than those contained in this prospectus, any amendment or supplement to this prospectus, or in any free writing prospectus we have prepared, and neither we nor the underwriters take responsibility for, and can provide no assurance as to the reliability of, any other information others may give you. Neither we nor the underwriters are making an offer to sell, or seeking offers to buy, these securities in any jurisdiction where the offer or sale is not permitted. The information contained in this prospectus is accurate only as of the date on the cover page of this prospectus, regardless of the time of delivery of this prospectus or the sale of ADSs. Our business, financial condition, results of operations and prospects may have changed since the date on the cover page of this prospectus. We will update this prospectus as required by law, including with respect to any material change affecting us or our business prior to the completion of this offering.

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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.

(i)

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.

(ii)

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.

(iii)

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.

(iv)

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.

(v)

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.

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(vi)

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 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.

(i)

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.

(ii)

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.

(iii)

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:

(i)

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

(ii)

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.

(i)

The area of reservoir considered as proved includes:

(A)

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

(B)

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.

(ii)

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.

(iii)

Where direct observation from well penetrations has defined a highest known oil (“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.

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(iv)

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:

(A)

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

(B)

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

(v)

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.

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“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.

“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.

Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and reserve data presented in this prospectus is as of December 31, 2021.

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ABOUT THIS PROSPECTUS

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 prospectus, 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 , 2022. 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.

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PRESENTATION OF FINANCIAL INFORMATION

This prospectus includes our audited consolidated financial statements as of and for the years ended December 31, 2021 and 2020, as well as our unaudited interim condensed consolidated financial statements as of and for the six months ended June 30, 2022 and 2021, which have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”), which differ in certain significant respects from generally accepted accounting principles in the United States (“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 prospectus 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 prospectus 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 prospectus. 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 prospectus. 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 the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures” in this prospectus for reconciliations of such measures to the most directly comparable IFRS measures and reasons for the use of such non-IFRS measures.

Average Quarterly Dividend per Share. Average Quarterly Dividend per Share is reflective of the average of the dividends per share declared throughout the applicable fiscal year which gives consideration to changes in dividend rates and changes in the amount of shares outstanding. We use Average Quarterly Dividend per Share as we seek to pay a consistent and reliable dividend to shareholders.

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 Diversified Gas & Oil Corporation, 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 hedges, producing what we refer to as our

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Adjusted EBITDA Margin throughout this report. Please refer to the definitions of these added profitability metrics below for additional details.

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

As used herein, Net-Debt-to-Adjusted EBITDA, or “Leverage” or “Leverage Ratio,” is measured as Net Debt divided by Adjusted EBITDA. We believe that this metric is a key measure of DEC’s financial liquidity and flexibility and is used in the calculation of a key metric in one of the Credit Facility’s financial covenants. Our statutory auditor, PricewaterhouseCoopers LLP (“PwC”), has not audited, reviewed, examined, compiled, verified or performed any procedures with respect to the pro forma financial information.

Total Revenue, inclusive of hedges. As used herein, Total Revenue, inclusive of hedges, includes the impact of derivatives settled in cash. We believe that Total Revenue, inclusive of 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 hedges. Adjusted EBITDA Margin incudes 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 prospectus. 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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MARKET AND INDUSTRY DATA

We obtained the industry, market and competitive position data in this prospectus 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 prospectus. 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 prospectus. These and other factors could cause results to differ materially from those expressed in the forecasts or estimates from independent third parties and us.

TRADEMARKS AND TRADE NAMES

We have proprietary rights to trademarks used in this prospectus 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 prospectus 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 prospectus is the property of its respective holder.

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all the information that you should consider before deciding to invest in our American Depositary Shares (“ADSs”). You should read the entire prospectus carefully, including the sections titled “Risk Factors,” “Business,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes to those consolidated financial statements before making an investment decision. We have provided definitions for certain natural gas and oil terms used in this prospectus in the section titled “Commonly Used Defined Terms” beginning on page ii of this prospectus. Unless the context requires otherwise, references in this prospectus to “Diversified,” “DEC,” “the Company,” “we,” “us,” “our” or “ours” refer to Diversified Energy Company plc and its subsidiaries.

The information presented in this prospectus assumes, unless otherwise indicated, that the underwriters do not exercise their option to purchase additional ADSs.

Company Overview

Diversified Energy Company plc

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 Kingdom, and our predecessor business was co-founded in 2001 by our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., with an initial focus on primarily natural gas and 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, we have completed 20 acquisitions for a combined purchase price of approximately $2.4 billion. We had average daily production of 816 MMcfepd and 711 MMcfepd for the six months ended June 30, 2022 and for the year ended December 31, 2021, respectively.

Our strategy is to acquire and manage natural gas and oil properties and our associated midstream assets to generate cash flows and maximize shareholder returns, including through the payment of regular dividends. For the six months ended June 30, 2022 and for the year ended December 31, 2021, we distributed approximately 57% of our Free Cash Flow to our shareholders. We actively seek to acquire high-quality producing conventional and unconventional natural gas and oil assets from industry participants seeking to divest assets either due to a desire to reallocate capital to other assets or raise cash proceeds. We target long-life producing assets at what we view as attractive valuations, and in our commercial evaluation, we typically attribute value to only the proved developed producing (“PDP”) portion of proved reserves and attribute minimal, if any, value to the proved undeveloped (“PUD”) portion of proved reserves, and no value to probable or possible reserves. Our target assets are characterized by multi-decade production profiles and low decline rates, and we place a particular focus on assets whose value we believe can be enhanced by complementary midstream infrastructure or by our operational and marketing framework.

We seek to improve the performance and operations of our acquired assets, which often have not received significant attention or necessary investment from their former owners. This improvement is achieved through our deployment of rigorous field management programs and/or refreshing infrastructure on wells that may have been poorly maintained. Through operational efficiencies, we demonstrate our ability to maximize value by enhancing production while lowering costs and improving well productivity. These production enhancement techniques also enable us to reduce the methane emissions profile of our wells. We further enhance the value of our assets by leveraging our midstream gathering pipeline infrastructure, which allows us to further diversify and expand our third-party revenue, optimize pricing, increase flow assurance and eliminate third-party costs and inefficiencies.

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Our experienced management team has a track record of consistently delivering per share growth in profitability and cash flow. As a result of our competitive strengths, we believe that we are well positioned to continue to grow for our shareholders.

Our senior management team is comprised of experienced individuals with decades of combined experience in the natural gas and oil sector, including in the Appalachian Basin where our operations historically have been concentrated. In particular, we benefit from the experience of our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., who is highly experienced in sourcing accretive acquisitions and securing the related financing. The management team is complemented by a talented operational leadership team with significant operational experience in U.S. onshore natural gas and oil basins. We have also sought to bolster this experience with the operating expertise of long-standing field staff of any acquired operations. These experienced field-level employees have a relentless focus on execution and an in-depth understanding of, and extensive experience working with, our assets, which is enhanced under our management’s leadership and operating strategy.

Commitment to Operational Excellence and Our Environmental, Sustainability and Governance Goals

We adhere to stringent operating standards, with a strong focus on health, safety and the environment to ensure the safety of our employees and the local communities in which we operate. We believe that acting as a careful steward of our assets will improve revenue and margins through recaptured methane emissions while reducing operating costs, which benefits our profitability. This focus on operational excellence, including the reduction of emissions, also benefits the environment and communities in which we operate. We have consistently proven our ability to extend the lives of existing mature wells, generally not engaging in development activity and, through our state-monitored, safe and systematic asset retirement program, permanently retire end of life wells and eliminate any potential associated emissions by safely plugging and abandoning the retired wells. We believe that by deploying our proprietary asset retirement infrastructure rather than needing to engage contractors in such activities, we are able to more nimbly react to operating conditions as they develop, changes in asset performance and to relative changes in the emissions profiles of our producing wells, thereby reducing potential emissions while also increasing margins and cost efficiency.

Our operations team developed our proprietary Smarter Asset Management (“SAM”) program, which is focused on enhancing our operational results by slowing production declines and returning shut-in wells to production. The SAM program underpins our focus on efficient production and flow from our wells and midstream assets through consistent operating efforts and an environmentally-conscious focus, which results in improved production, thereby partially offsetting natural production declines, lowering operating costs and emissions and improving asset integrity, all with the goal of generating higher cash flow. Additionally, through the daily implementation of our SAM program, which includes wellhead compression management, fluid load reduction and pump-jack optimization, among other techniques, we have intentionally and continuously taken actions directed at reducing unintended natural gas emissions, while carefully managing our general and administrative expenses.

We have consistently driven our operations towards sustainability and efficiency, but we believe we are also at the forefront of U.S. natural gas and oil producers in our commitment to environmental, social and governance (“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. Natural gas, a clean, reliable, abundant and affordable energy source, is an environmentally superior alternative for addressing the rising energy demand relative to other fossil fuel alternatives. We believe this positions natural gas as an essential bridge during the transition to alternative fuels and renewable energy sources. The electrification of transportation and industry is a key component of energy transition, which we believe will continue to drive demand for electricity well in excess of electricity supply from renewable energy alternatives. Given our operational focus on efficient, environmentally sound natural gas production, we believe we are ideally positioned to help serve this demand and play a key role in the clean energy transition.

In 2021, we proactively pursued aggressive methane emissions reduction targets that met or exceeded regulatory requirements. In addition, we pledged $15 million in new investments in 2022 aimed at emissions reductions, equivalent to 30% of 2021 capital expenditures, reflecting our short-term goals of 30% and

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50% reductions in Scope 1 methane emissions intensity by 2026 and 2030, respectively, while simultaneously working toward long-term reductions in CO₂ and a net zero Scope 1 and Scope 2 greenhouse gas (“GHG”) position by 2040. To achieve these milestones, we intend to deploy approximately 600 hand-held methane emissions detection devices, which allow field personnel to identify and remediate emissions otherwise undetectable using traditional techniques. We also created a program to screen emissions of potential asset acquisitions and now perform aerial scans of our natural gas production and distribution assets, which can efficiently detect and estimate emissions to better inform our repair and maintenance activities. We intend to further bolster our existing emissions reduction efforts by installing air compression systems to eliminate the use of methane to power pneumatic devices or compression facilities and expanding internal asset retirement capabilities. We believe that we are at the forefront of the U.S. natural gas and oil industry in implementing technologies such as these to significantly reduce emissions. In 2021, we safely and permanently retired 70% more wells than our collective state-mandated minimums.

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. During 2021, the percentage of minorities that comprised our employee base increased to 2.7% from 0.6%. The percentage of women in our employee base at December 31, 2021 was 11%, with the majority serving in production support roles. We seek to generate a diverse candidate pool from which we can identify and hire the most qualified individuals, regardless of background, to the benefit of the Company and our stakeholders. Our board of directors consists of three females and five males, and our senior management, including our executive committee and its direct reports, but excluding the two executive directors, consisted of 82 employees, including 26 females (32%) and 56 males (68%). Our board of directors continues to demonstrate diversity in a wider sense, with directors from the United States as well as the UK, bringing a range of domestic and international experience to our board of directors. Our board of directors will continue to review and evaluate the Company’s board of directors and committee composition and intends to continue further progress with independence and diversity.

Finally, we invest in our people and the communities in which we operate. We have committed to spend $2.0 million in 2022 in community outreach to support three key focus areas: community enrichment, education and workforce, and the environment. We provide full-time, local jobs to approximately 1,500 individuals in these communities and offer scholarships and internship programs to source a portion of the next generation of our employees. We pay our employees nearly double the average salaries in the regions in which we operate and provide generous employee benefits, including matching employee contributions to 401(k) plans.

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, natural gas liquids (“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 77,530 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% taking into account our acquisitions completed in 2022 and contains certain wells that have an expected life of greater than 50 years. In addition to the upstream assets, our portfolio contains approximately 17,000 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, 2021.

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[MISSING IMAGE: tm2212142d1-map_appalac4clr.jpg]

[MISSING IMAGE: tm2212142d1-map_central4clr.jpg]

We have an established reputation in the marketplace as a consolidator of assets in the Appalachian Basin, and we believe we are one of the few operators in the United States with sufficient access to capital to make acquisitions at scale. Through a series of acquisitions in 2021 and 2022, we have quickly built scale in the Central Region, located in Oklahoma, Louisiana and portions of Texas, including the Cotton Valley, Bossier, Haynesville Shale, Barnett Shale Plays, as well as the Mid-Continent producing areas. Our goal is

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to replicate the success we have had in the Appalachian region to our new operations in the Central Region, which we believe presents considerable growth opportunities.

We focus on producing natural gas, NGLs and oil from established conventional and mature unconventional wells. As of December 31, 2021, 67% of our production was generated from conventional wells with the remaining 33% attributable to our portfolio of unconventional wells. Based on our operational experience with our assets, we believe that many of the wells in our inventory have low-risk, up-hole potential that has yet to be fully quantified. Additionally, most of our acreage is held by production, and due to the significant well control and geologic understanding of our portfolio, we believe there is also potential for significant, low-cost, low-risk developmental drilling opportunity within our assets.

The production profiles of the wells across these formations demonstrate similar characteristics. Most of these formations produce natural gas and/or oil on a hyperbolic curve with an initial rapid decline followed by gradual decline of production over a long period of time. This modest, later-life rate of decline enables us to predict and plan with a high level of confidence the future production profile of our producing assets.

Summary Reserve Data

Summary of Reserves as of December 31, 2021

The following table provides our reserves, PV-10 and the Standardized Measure. Our reserves, Standardized Measure and PV-10 are calculated using SEC rules regarding reserve reporting currently in effect, including the use of an average price, calculated as prices equal to the 12-month unweighted arithmetic average of the first day of the month prices for each of the preceding 12 months as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (“SEC Pricing”).

	SEC Pricing as of 12/31/2021(1)
Estimated Proved Reserves	Total
Natural gas (MMcf)			4,009,037
Natural gas liquids (MBbl)			89,080
Oil (MBbl)			14,252
Total (MBoe)(2)			771,505
PV-10(3)		$	4,037,016
Standardized measure of discounted future net cash flows		$	3,333,091
Estimated Proved Developed Reserves
Natural gas (MMcf)			4,008,160
Natural gas liquids (MBbl)			89,071
Oil (MBbl)			13,823
Total (MBoe)(2)			770,921
Estimated Proved Undeveloped Reserves
Natural gas (MMcf)			877
Natural gas liquids (MBbl)			9
Oil (MBbl)			429
Total (MBoe)(2)			584

(1)

Our historical SEC reserves, PV-10 and Standardized Measure were calculated using SEC Pricing. For natural gas volumes, the average Henry Hub spot price was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For oil and NGL volumes, the average WTI price per Bbl as of December 31, 2021, was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties.

(2)

Assumes a ratio of six Mcf of natural gas per Bbl.

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(3)

The PV-10 of our proved reserves as of December 31, 2021, was prepared without giving effect to taxes or hedges. PV-10 is a non-GAAP and non-IFRS financial measure and generally differs from the “standardized measure of future net cash flows,” 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 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. See the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures.”

STRATEGIES

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

Unlike many companies in the upstream sector, we are not primarily focused on capital-intensive drilling and development. Our stewardship model focuses on acquiring existing, long-life, low-decline producing wells and, occasionally, their associated midstream assets, and then efficiently managing the assets through our SAM program to improve or restore production, reduce unit-operating costs and generate consistent cash flow before safely and permanently retiring those assets at the end of their useful lives.

When we acquire new assets, we often seek to retain many of the experienced employees who have historically serviced those assets while integrating our SAM program into their day-to-day operations. While we are not primarily a midstream company, we strategically seek to maximize the value of our producing assets through complementary midstream systems that can be fully integrated into our upstream portfolio. These assets are typically located in areas where we are a large producer, allowing market access to higher prices and the opportunity to reroute production when adjoining, third-party systems are constrained or result in lower pricing for product sales. We also earn additional revenue for transporting third-party operators’ production through our system, effectively providing a subsidy to the operating costs of our midstream system and ultimately improving consolidated operating margins.

We intend to continue optimizing our operations in a manner that prioritizes the generation of cash flow and the payment of dividends to our shareholders. Our principal focus is on operating assets, not drilling new production wells, thereby allowing us to optimize PDP revenues and cost streams. For the six months ended June 30, 2022, we reported a net loss of $935 million. Excluding the mark-to-market loss on long-dated derivative valuations as well as other customary non-cash or non-recurring adjustments, we reported Adjusted EBITDA of $224 million for the six months ended June 30, 2022 compared to $151 million for the six months ended June 30, 2021, representing an increase of 48% driven by our growth through acquisitions. For the year ended December 31, 2021, we reported a net loss of $325 million, though, excluding the mark-to-market loss on long-dated derivative valuations, and other commonly excluded items we generated $343 million in Adjusted EBITDA, an increase of $43 million, or 14%, from December 31, 2020.

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

We intend to continue our strategy of delivering value to shareholders through a combination of paying dividends to our shareholders, reinvesting in accretive growth, repaying debt and investing in ESG initiatives. From time-to-time, we will also evaluate and engage share repurchase opportunities and engage in such returns of value to our shareholders. Since our initial public offering of ordinary shares on the London Stock Exchange in 2017 (the “LSE IPO”) and as of June 30, 2022, we have paid an aggregate of $420 million in dividends and have repurchased approximately $84 million of our outstanding shares. Since our LSE IPO, we successfully increased our dividend ten times, and have not decreased our dividend despite the substantial decline in commodity prices which followed our LSE IPO. Our most recent annual dividend of $0.17 per share during the year ended December 31, 2021 represents approximately an eightfold increase over our first declared dividend since our LSE IPO and a payout ratio among the highest among other publicly traded U.S. onshore E&P companies. The long-term dividend sustainability, as well as the ability to incur debt purposively structured to provide for amortization and thus decreasing leverage over time, is supported by a conservative hedging strategy to insulate cash flows from commodity price volatility and provide visibility over cash flows, leverage and the ability to declare dividends. As a result of this strategy,

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we have been successful in securing Adjusted EBITDA margins of approximately 50%. See the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures.”

We aim to maximize shareholder value by realizing operational efficiencies and the thorough implementation of vertical integration. To achieve this strategy, we utilize our SAM program to partially offset natural production declines and also leverage our scale and cost efficiencies to reduce unit operating costs and improve margins, particularly in respect of newly acquired assets. We proactively seek to manage our operating costs and believe that there is further room to optimize the operating cost base of the business given our scale and approach to vertical integration, particularly for recently acquired assets. Our midstream assets also help to support cost reduction by providing operational control over the transportation of our production, thereby allowing us to optimize pricing through a selection of delivery points and providing increased operational control. Our asset retirement infrastructure provides cost efficiency in our plugging and abandonment activities.

Disciplined growth through accretive acquisitions of producing assets

We intend to maintain our disciplined approach to acquisitions and, while we pursue opportunistic growth, we will also focus on assets that we believe will provide long-term accretive cash flow generation. We intend to continue pursuing this strategy as we believe we are well positioned to benefit from ongoing trends in the U.S. exploration and production industry where incumbent operators seek exit strategies to divest non-core assets to create the necessary capital to drill and develop their core leasehold positions. We have a track record as an established consolidator and we believe we are one of the few operators able to continue to make acquisitions at scale. While we have historically focused on the Appalachian Basin, the fragmented operator landscape across the U.S. has created significant opportunity to find accretive asset packages that meet the goals of our historical investment standards, primarily due to our ability to effectively apply SAM program techniques to new assets as well as leveraging favorable regional commodity pricing, ample takeaway capacity and opportunities to build accretive scale around the position. Through four acquisitions in 2021, we began to build scale across mature producing properties in the Central Region, which spans across Louisiana, Oklahoma and Texas. We continue to look for other opportunities that fit our investment criteria across the U.S. and will continue to expand our footprint in accordance with our stated strategy. We will not unduly burden our balance sheet with additional debt for non-accretive growth, and as a result, we intend to maintain disciplined target leverage ratios.

As a further measure to bolster the scale at which we acquire assets, in October 2020, we entered into a definitive participation agreement (the “Strategic Participation Agreement”) with funds managed by Oaktree Capital Management, L.P. (“Oaktree”) to jointly identify and fund future PDP acquisition opportunities that we identify from time-to-time (the “Oaktree Funding Commitment”). The Oaktree Funding Commitment provides for up to an aggregate of $1.0 billion over three years for mutually agreed upon PDP acquisitions, including approximately $573 million remaining under the initial commitment as of June 30, 2022.

In 2021, we announced our strategic entry into the prolific natural gas producing Central Region with four acquisitions. The four acquisitions were completed for an aggregate of $687 million in cash in combined purchase consideration, contributing approximately 40 MBoepd to December 2021 production. Oaktree participated in three of these transactions pursuant to the Strategic Participation Agreement. See the subsection titled “—Non-IFRS Financial Measures” for a reconciliation of Adjusted EBITDA to net income (loss).

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

We actively manage our balance sheet and seek to maintain a leverage ratio at or below 2.5 to 1.0 after giving effect to acquisitions and any related financing arrangements. At December 31, 2021, we had a Standardized Measure coverage ratio (defined as Standardized Measure divided by total debt) of 3.2 to 1.0, a PV-10 coverage ratio (defined as PV-10 divided by total debt) of 3.9 to 1.0 and $235 million in liquidity. During the six months ended June 30, 2022, we completed a series of ABS financing arrangements and bolstered our liquidity position to $469 million. See the subsection titled “—Non-IFRS Financial Measures” for a reconciliation of PV-10 to Standardized Measure. With the completion of these financings, all of our outstanding indebtedness has an amortizing structure. These low interest fixed-rate structures contain hedge protection for the collateralized assets ensuring strong margins that secure the structured borrowing

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repayments and the continuation of our dividend payments. Structures of this nature allow us to naturally deleverage over time in a resilient and disciplined manner that compliments the natural low decline nature of our asset base. We also maintain sufficient liquidity such that we can be well positioned in the market to capitalize on acquisition opportunities as they become available. We intend to ensure that future acquisitions are made at attractive valuations and conservatively capitalized in order to maintain a modest leverage ratio.

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

We believe that natural gas will play a key role in the clean energy transition, particularly in light of the continuing electrification of transportation and industry. In addition to consistently implementing our SAM program across our asset base, we believe we are at the leading edge of our industry with respect to the implementation of emissions-reducing technology as well as emissions reduction targets.

Additionally, we continue to strive for the highest standards of governance. The board of directors of the Company, of which three of the eight directors are female and a majority are independent, has a diverse set of experiences and knowledge base which provides for constructive dialogue between both directors and management with respect to ESG and other matters. Our board of directors oversees the development of our climate change strategy which aims to position the Company at the heart of the energy transition, based on responsible stewardship of existing assets, and is highly experienced and continuously educated in this strategic area. The Sustainability and Safety Committee evaluates all issues relating to climate change on behalf of the board of directors, including changes in regulation and policy and other external, macro-level developments relating to climate change. The Audit and Risk Committee oversees the Enterprise Risk Management (“ERM”) process, including assessing and managing climate risk, while the Remuneration Committee is responsible for developing a compensation structure for senior management linked, in part, to ESG- and climate-related metrics. Overseeing the size and composition of the board of directors, the Nomination Committee is responsible for ensuring the board of director’s collective skill set is positioned to adequately understand and strategically lead climate-related decisions and opportunities for the Company. Climate-related matters are also discussed regularly as part of our board of director’s meetings. We are proactive in social stewardship and have engaged global consultants and financial advisors to ensure high quality disclosures and regulatory compliance as well as ESG ratings agencies to ensure reported data and company actions are accurate and validated.

STRENGTHS

Low-risk and low-cost portfolio of assets

We benefit from a highly diversified portfolio of low-risk and low-cost assets. These assets include conventional and unconventional natural gas and oil producing wells located across the geologically and politically low-risk states of Tennessee, Kentucky, Virginia, West Virginia, Ohio, Pennsylvania, Texas, Oklahoma and Louisiana. As a result, our performance is not materially impacted by the performance of any individual well or well pad. In addition to these upstream assets, our portfolio contains approximately 17,000 miles of natural gas gathering pipelines and a network of compression and processing facilities that are complementary to our upstream assets and enhance margins by reducing third-party tariffs and optimize pricing through route selection. We also have agreements with third parties to gather and transport their produced natural gas, which effectively provides a subsidy to the operating costs of our midstream system and ultimately improves consolidated operating margins. We do not rely on exploration or development activity to increase reserves or drive production. As a result, we are not as exposed to the capital-intensive development and drilling risks that come with a more traditional development model. Our wells are mature and benefit from simple and low-cost maintenance operations, as illustrated by our low relative gathering and transportation (“G&T”) cost per Boe, requiring low ongoing capital expenditures for a highly cash generative asset base and which positions us to effectively manage the nature, timing and amount of capital expenditure invested in our assets. Our gathering and transportation cost per Bbl for the six months ended June 30, 2022 was $3.69 per Boe as compared with the average of what we view as our U.S. peers of $6.33 per Boe. This provides us with control and flexibility over future investment programs, which is a key competitive advantage in light of the historic volatility in natural gas and oil prices. For the six months ended June 30, 2022, excluding acquisitions, our total capital expenditures were 4.8% of total net loss, or 19.9% of total

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Adjusted EBITDA. See the subsection titled “—Non-IFRS Financial Measures” for a reconciliation of Adjusted EBITDA to net income (loss).

Long-life and low-decline production

We benefit from stable, long-life and low-decline production which provides a durable, highly visible source of cash flow. This cash generation profile allows us to maintain a prudent allocation of cash flows consisting of dividend payments, debt reduction and organic growth reinvestment, as well as investments in ESG initiatives. The vast majority of our wells are past their high decline phase and into their period of exponential decline, a later period in a well’s life, where decline rates are lower and generally demonstrate a more stable production profile. Our decline rate of approximately 8.5%, when taking into account our acquisitions completed in 2022, is lower than many public, development-focused gas-weighted exploration and production companies where decline rates in excess of 30% are not uncommon. Our portfolio performance is underpinned by our SAM program, which enhances production from producing wells and returns other non-producing wells to a productive state.

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

We benefit from consistent production with low decline rates from our high-quality assets and significant scale that, when paired with our relatively low average cost of production, gives rise to high profit margins and consistent cash flows. Corporate scale, enhanced by our acquisitions, allows us to leverage the extensive expertise of our work force and the experience accumulated by our employees from operating in gas-focused regions for many years, driving innovation and best practices. Our significant operational scale is enhanced by our vertically integrated operations, in particular our midstream infrastructure, which results in increased control of our production flow, increased operational efficiencies, and increased third-party revenue streams, as well as our asset retirement infrastructure and operations, which allow us to reduce costs in respect of plugging and abandonment obligations.

Highly experienced management and operational team

Our senior management team is comprised of experienced individuals with a combined over 100 years of experience in the natural gas and oil sector. In particular, we benefit from the knowledge of our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., who is highly experienced in sourcing accretive acquisitions and securing the related financing. The management team is complemented by a senior operational team with an exceptional understanding of U.S. onshore gas basins, spanning an average of over 30 years of operational experience. These experienced employees have a relentless focus on execution and an in-depth understanding of, and extensive experience working with, our assets. This operational experience culminates in our SAM program. Our management team remains focused on efficient and effective management of production and operations while carefully controlling general and administrative expenses.

Track record of successful consolidation and integration of acquired assets

Following the development of the U.S. onshore natural gas and oil industry through what is commonly referred to as the ‘shale revolution’, there has been a significant supply of conventional and unconventional assets that have become available as a result of a number of U.S. exploration and development companies selling producing acreage viewed as non-core to their operations, as well as distressed sellers looking to supplement low cash flow with asset sale proceeds. Simultaneously, this increase in supply of assets has been met by limited demand due to market uncertainty and relatively weak capital markets. We are well positioned to exploit these continued consolidation opportunities. Our management team has demonstrated our ability to source, fund and execute acquisitions that significantly enhance shareholder value. We have completed 20 acquisitions since 2017 with a combined purchase consideration of approximately $2.4 billion, while seeking to maintain a disciplined leverage position of 2.5 to 1.0 or less after giving effect to acquisitions and any related financing arrangements.

A proactive and innovative approach to asset retirement

We embrace our responsibilities to the United States, our local communities and our environment. With safety and environmental stewardship as top priorities, we designed our asset retirement program to

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permanently retire wells that have reached the end of their economic lives. Unlike the higher risk, complex and costly “decommissioning” of deep, offshore wells with large production platforms, the retirement of our predominantly shallow, onshore wells and their small land footprints is far less complex and costly. In fact, we retire most of our wells with low environmental and safety risk for approximately $20,000 to $30,000 per well.

In 2017, after the LSE IPO, we proactively began to meet regularly with state officials to develop a long-term plan to retire our growing portfolio of long-life wells. Collaborating with the appropriate regulators, we designed our retirement activities to be equitable for all stakeholders with an emphasis on the environment. During 2021, we permanently retired 136 wells, exceeding our state requirements of 80 wells, providing a highly visible step towards our goal of plugging 200 wells in 2023. During 2022, we made investments that allowed us to meaningfully expand our plugging capabilities through a series of acquisitions that we believe have provided us the operational capacity to achieve this goal.

Our asset retirement program reflects our solid commitment to a healthy environment, the surrounding community and its citizens and state regulatory authorities. We partner our highly skilled personnel with the necessary financial resources to responsibly manage our assets throughout their productive lives and retirement. We strive to meet or exceed our asset retirement obligations under state agreements and have a growing track record of demonstrating our ability to succeed.

Acquisitions and Consolidation

We continue to identify attractive acquisition and investment opportunities to purchase additional producing assets in or around our existing footprint, as well as outside of the states in which we currently operate. Each target acquisition is evaluated within strict criteria and our disciplined approach to evaluating opportunities ensures that we only pursue those acquisitions that possess a consistent asset profile, compelling upside, and have the potential to drive positive cash flow per share. In addition, we also consider the emissions profiles of target acquisitions in our evaluations. The higher commodity price environment creates market opportunities to build on our strategy of value-accretive acquisitions as other companies seek exit strategies to divest non-core assets creating the necessary capital to drill and develop their core leasehold positions. We continue to explore opportunities and anticipate being active in a strong M&A market consistent with our proven strategy and successful track record of integrating and optimizing newly acquired assets.

Our Capital Expenditure Program and Liquidity

Our strategy to acquire and operate producing assets that generate cash flow margins of approximately 50% allows us to continually invest capital back into our operations. In addition, we plan to achieve “net zero” Scope 1 and Scope 2 emissions by 2040 through new investments aimed at emissions reductions, such as investments in methane emissions detection devices and conducting aerial scans of our assets.

The majority of our capital expenditures are focused on our midstream operations, which includes pipelines and compression, while the remaining capital expenditures are focused on emissions reductions initiatives, plugging capacity expansion, fleet, technology, upstream operations, and when prudent, may include development activities targeted at replacing production. Given our operational focus to acquire and operate mature conventional wells and unconventional wells with a shallow decline rate, we do not incur the same level of large capital expenditures associated with drilling and completion activities that would typically be incurred by other development focused exploration and production companies.

In 2021, we achieved an industry-leading yield on the LSE by generating a dividend yield in excess of 10% and yielding a payout ratio of 57%, which is among the highest yield and payout ratios among other publicly traded U.S. onshore E&P companies. We paid an annual dividend of $0.17 per share in 2021, which represents an 8% increase against 2020, paying an aggregate total of approximately $130 million in dividends during 2021. We have consistently targeted a disciplined leverage profile at or under 2.5 to 1.0 after giving effect to acquisitions and any related financing arrangements. We believe this leverage range is supported by our differentiated business model, namely with long-life, low-decline production providing resilient cash flows, and a strategic financial framework that is bolstered by hedging and amortizing debt instruments. We further enhanced our ability to generate cash flow and our ability to pay dividends by taking advantage of

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improving commodity prices and raising our 2022 weighted average hedge floor on natural gas production from $2.97 per Mcf as of December 31, 2021 to $3.20 per Mcf as of June 30, 2022. Finally, we announced capital allocation dedicated to ESG and emissions initiatives for 2022 representing 30% of 2021 capital expenditures as well as a variety of operational initiatives.

Looking forward to 2022, we continue to seek to maximize cash flow and to maximize our ability to continue paying regular dividends. We also plan to maintain our hedging strategy to protect cash flow, and the ability to reduce debt to pay dividends, while also taking advantage of market opportunities to raise the floor price of our risk management program. We will seek to retain our strategic advantages in purposeful growth through a disciplined capital expenditure program that continues to secure low-cost financing that supports acquisitive growth while maintaining low leverage and ample liquidity. In addition, we intend to remain proactive in our ESG endeavors by prioritizing future capital allocation for ESG initiatives.

Recent Developments

Since the release of our mid-year 2022 results on August 8, 2022, we have achieved the following milestones:

•

On September 27, 2022, closed on our previously announced agreement to acquire certain upstream assets in the Central Region from ConocoPhillips Company for a gross purchase price of $240 million. Based solely on management’s estimates, we believe that the acquisition will add approximately 31 MMBoe (186 Bcfe) of net PDP reserves as of August 31, 2022. We currently estimate that these assets will produce approximately 9 MBoepd for the twelve months ending August 31, 2023 and will maintain our consolidated corporate decline rate of ~8.5%. Based on management’s estimates, the purchase price represents the present value of the estimated pretax and unhedged cashflows to be generated from PDP reserves when using NYMEX strip pricing, discounted at an approximate annual rate of 17%, a higher discount rate than is often used by industry participants when valuing upstream assets;

•

Entered into a series of trades for approximately $88 million to align the Company’s hedge portfolio with its financing entities. These trades elevate our floor price for certain hedging arrangements and eliminate the ceiling price on others. We believe these transactions will allow us to recoup the cost of the optimization of our hedge portfolio through future 2022 and 2023 hedge settlements and help elevate our weighted average hedge floor to $3.50 and $3.27 per Mcf for the remainder of 2022 and 2023 respectively;

•

Continued the expansion of our plugging operations with an additional acquisition in Appalachia, adding six more plugging rigs to our operations and bringing our total rig count to 15, further enhancing our ability to realize efficiencies and generate third-party revenues for a variety of inspection and retirement services at attractive margins;

•

In August 2022, we amended and restated the credit agreement governing our Credit Facility by entering into the Amended and Restated Revolving Credit Agreement, dated as of August 2, 2022 among DP RBL CO LLC, as borrower, Diversified Gas & Oil Corporation (“DGOC”), as existing borrower, KeyBank National Association, as administrative agent and issuing bank, Keybanc Capital Markets, as sole lead arranger and sole book runner and the lenders party thereto (the “A&R Revolving Credit Facility��). The amendment enhances the alignment with our stated ESG initiatives by including sustainability performance targets similar to those included in the ABS V Notes as described in this prospectus, extends the maturity of our Credit Facility to August 2026, removes DGOC as a credit party from the Credit Facility, reaffirms the borrowing base of $300 million and included no other material changes to pricing or terms. Further, as a result of the amendment, the covenant structure associated with the A&R Revolving Credit Facility will now be associated with solely DP RBL CO LLC, the borrower, a subsidiary of DGOC, the existing borrower. Please see the subsection titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility” for additional information regarding the A&R Revolving Credit Facility.

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course of our due diligence with respect to the pending acquisition and has not been independently verified or estimated. Our production estimates are based on, among other things, historical production and decline rate information provided by the seller. Achieving this production estimate will depend on actual well performance and operating conditions which may be outside of our control. For more detail on these risks and assumptions, see “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors—Risks Relating to Our Business, Operations and Industry”.

Summary of Risk Factors

Investing in our ADSs involves risks. You should carefully consider the risks described in the section titled “Risk Factors” immediately following this prospectus summary before making a decision to invest in our ADSs. These risks include, but are not limited to, the following:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

We may face unanticipated water and other waste disposal costs.

•

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

•

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

•

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

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•

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

•

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

•

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

•

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

•

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

•

Our operations are subject to the risk of litigation.

•

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

•

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

•

We have identified a material weakness in our internal control over financial reporting and we may identify additional material weaknesses in the future or otherwise fail to maintain effective internal control over financial reporting, which may result in material misstatements of our consolidated financial statements, cause us to fail to meet our periodic reporting obligations, or cause our access to the capital markets to be impaired.

•

If you purchase ADSs in this offering, you will suffer immediate dilution of your investment.

•

We are subject to certain tax risks and holders of our ADSs may be subject to U.S. federal withholding or income tax.

Corporate Information

Our registered office is located at 4th Floor Reading Bridge House, George Street, Reading, Berkshire United Kingdom, RG1 8LS. In February 2017, our shares were admitted to trading on the Alternative Investment Market (“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 prospectus. We have included our website address solely as an inactive textual reference.

Implications of Being an Emerging Growth Company and a Foreign Private Issuer

We qualify as an “emerging growth company” as defined in the U.S. Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As an emerging growth company, we may take advantage of specified reduced reporting and other requirements that are otherwise applicable generally to public companies in the United States. These provisions include:

•

an exemption from compliance with any requirement that the Public Company Accounting Oversight Board may adopt regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements;

•

reduced disclosure about our executive compensation arrangements;

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•

an exemption from the non-binding advisory votes on executive compensation, including golden parachute arrangements; and

•

an exemption from the auditor attestation requirement in the assessment of our internal control over financial reporting pursuant to the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”).

As a result, we do not know if some investors will find our ADSs or ordinary shares less attractive. The result may be a less active trading market for our ADSs and ordinary shares, and the price of our ADSs and ordinary shares may become more volatile. We may choose to take advantage of some or all these provisions until the last day of the fiscal year ending after the fifth anniversary of the offering or such earlier time that we are no longer an emerging growth company. We would cease to be an emerging growth company if we have more than $1.07 billion in total annual gross revenue, have more than $700 million in market value of our ordinary shares (including those represented by ADSs) held by non-affiliates or issue more than $1.0 billion of non-convertible debt over a three-year period.

Our status as a foreign private issuer also exempts us from compliance with certain laws and regulations of the SEC and certain regulations of the . Consequently, we are not subject to all of the disclosure requirements applicable to U.S. public companies. For example, we are exempt from certain rules under the U.S. Securities and Exchange Act of 1934, as amended (“Exchange Act”) that regulate disclosure obligations and procedural requirements related to the solicitation of proxies, consents or authorizations applicable to a security registered under the Exchange Act. In addition, our executive officers and directors are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and related rules with respect to their purchases and sales of our securities. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. public companies. Accordingly, there may be less publicly available information concerning our company than there is for U.S. public companies.

In addition, foreign private issuers are not required to file their annual report on Form 20-F until 120 days after the end of each fiscal year, while U.S. domestic issuers that are accelerated filers are required to file their annual report on Form 10-K within 75 days after the end of each fiscal year. Foreign private issuers are also exempt from Regulation FD (Fair Disclosure) of the Exchange Act, aimed at preventing issuers from making selective disclosures of material information.

We may take advantage of these exemptions until such time as we no longer qualify as a foreign private issuer. In order to maintain our current status as a foreign private issuer, either a majority of our outstanding voting securities must be directly or indirectly held of record by non-residents of the United States, or, if a majority of our outstanding voting securities are directly or indirectly held of record by residents of the United States, a majority of our executive officers or directors may not be United States citizens or residents, more than 50% of our assets cannot be located in the United States and our business must be administered principally outside the United States.

We have taken advantage of certain of these reduced reporting and other requirements in this prospectus. Accordingly, the information contained herein may be different from the information you receive from other public companies in the United States which you hold equity securities.

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THE OFFERING

ADSs offered by us

ADSs, each representing ordinary shares.

Option to purchase additional ADSs

We have granted the underwriters an option to purchase up to additional ADSs from us within 30 days of the date of this prospectus.

Ordinary shares to be outstanding immediately after this offering

ordinary shares (or ordinary shares if the underwriters exercise their option to purchase additional ADSs from us in full).

American Depositary Shares

Each ADS, which may be represented by an ADR, represents ordinary shares, with nominal value £0.01 per share.

As an ADS holder, you will not be treated as one of our shareholders. The depositary will be the holder of the ordinary shares underlying your ADSs. You will have rights as provided in the deposit agreement. You may surrender your ADSs and withdraw the underlying ordinary shares as provided, and pursuant to the limitations set forth in the deposit agreement. The depositary will charge you fees for, among other items, any such surrender for the purpose of withdrawal. As described in the deposit agreement, we may amend or terminate the deposit agreement without your consent. If you continue to hold your ADSs, you agree to be bound by the terms of the deposit agreement then in effect. To better understand the terms of the ADSs, you should carefully read the section titled “Description of American Depositary Shares.” You should also read the deposit agreement, which is an exhibit to the registration statement of which this prospectus forms a part.

Depositary

Custodian

Use of proceeds

The principal purposes of this offering are to create a public market for our ADSs, facilitate access to the public equity markets and increase our visibility in the marketplace. We intend to use the net proceeds from this offering for working capital, to fund incremental growth and other general corporate purposes, including possible acquisitions. See the section titled “Use of Proceeds.”

Risk factors

See the section titled “Risk Factors” and other information included in this prospectus for a discussion of factors you should carefully consider before deciding to invest in our ADSs.

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Proposed Listing

We intend to apply to list our ADSs on under the symbol “DEC.”

LSE trading symbol

Our ordinary shares are listed on the LSE under the symbol “DEC.”

The number of our ordinary shares to be outstanding immediately after this offering is based on ordinary shares outstanding as of June 30, 2022, and excludes:

•

ordinary shares issuable upon the exercise of options outstanding under our 2017 Equity Incentive Plan (as defined herein) as of June 30, 2022 at a weighted-average exercise price of $ per share; and

•

ordinary shares reserved for future issuance under our 2017 Equity Incentive Plan as of June 30, 2022, as further described in the subsection titled “Management—Equity Compensation Arrangements—2017 Equity Incentive Plan.”

Unless otherwise indicated, all information in this prospectus assumes or gives effect to:

•

an initial public offering price of $ per ADS, the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2022 (based on an assumed exchange rate of £1.00 to $1. );

•

no exercise of the outstanding options described above after June 30, 2022; and

•

no exercise by the underwriters of their option to purchase up to additional ADSs in this offering.

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SUMMARY CONSOLIDATED FINANCIAL AND OTHER DATA

We prepare our consolidated financial statements in accordance with IFRS as issued by the IASB. The following summary historical consolidated financial data as of June 30, 2022, December 31, 2021 and 2020 and for the six months ended June 30, 2022 and 2021 and for the years ended December 31, 2021 and 2020 has been derived from our unaudited interim condensed consolidated financial statements and our audited consolidated financial statements, which are included elsewhere in this prospectus. Our historical results for any prior period are not necessarily indicative of results expected in any future period.

The financial data set forth below should be read in conjunction with, and is qualified by reference to, the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our unaudited interim condensed consolidated financial statements and our audited consolidated financial statements and notes thereto included elsewhere in this prospectus.

Consolidated Statement of Comprehensive Income

	Six Months Ended						Year Ended
(In thousands, except per share and per unit data)	June 30, 2022			June 30, 2021			December 31, 2021			December 31, 2020
Revenue		$	933,528		$	323,316		$	1,007,561		$	408,693
Operating expense			(206,357)			(119,555)			(291,213)			(203,963)
Depreciation, depletion and amortization			(118,480)			(71,843)			(167,644)			(117,290)
Gross profit			608,691			131,918			548,704			87,440
General and administrative expense			(114,282)			(42,333)			(102,326)			(77,234)
Allowance for expected credit losses			—			(602)			4,265			(8,490)
Gain (loss) on natural gas and oil property and equipment			1,050			234			(901)			(2,059)
Gain (loss) on derivative financial instruments			(1,673,841)			(394,885)			(974,878)			(94,397)
Gains on bargain purchases			1,249			—			58,072			17,172
Operating profit (loss)			(1,177,133)			(305,668)			(467,064)			(77,568)
Finance costs			(39,162)			(22,512)			(50,628)			(43,327)
Accretion of asset retirement obligation			(14,003)			(10,216)			(24,396)			(15,424)
Loss on joint interest owner receivable			—			—			—			—
Loss on debt cancellation			—			—			—			—
Other income (expense)			171			(5,582)			(8,812)			(421)
Income (loss) before taxation			(1,230,127)			(343,978)			(550,900)			(136,740)
Income tax benefit (expense)			294,877			260,021			225,694			113,266
Net income (loss)			(935,250)			(83,957)			(325,206)			(23,474)
Other comprehensive income (loss)			132			51			51			(28)
Total comprehensive income (loss)		$	(935,118)		$	(83,906)		$	(325,155)		$	(23,502)
Earnings (loss) per share–basic and diluted		$	(1.10)		$	(0.11)		$	(0.41)		$	(0.03)
Weighted average shares outstanding–basic and diluted			849,621			736,559			793,542			685,170

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Consolidated Statement of Financial Position

	As of
(In thousands)	June 30, 2022			December 31, 2021			December 31, 2020
Assets
Total non-current assets		$	3,416,845		$	3,157,070		$	2,196,208
Cash and cash equivalents			187,342			12,558			1,379
Total current assets			429,194			324,581			93,095
Total assets		$	4,033,381		$	3,494,209		$	2,290,682
Equity and Liabilities
Total equity		$	(354,084)		$	663,950		$	886,658
Total non-current liabilities			2,822,450			2,056,659			1,207,518
Total current liabilities			1,565,015			773,600			196,506
Total liabilities			4,387,465			2,830,259			1,404,024
Total equity and liabilities		$	4,033,381		$	3,494,209		$	2,290,682

Consolidated Statement of Cash Flows

	Six Months Ended						Year Ended
(In thousands)	June 30, 2022			June 30, 2021			December 31, 2021			December 31, 2020
Statement of Cash Flows Data:
Capital expenditures(1)		$	(44,539)		$	(16,458)		$	(50,175)		$	(21,947)
Net cash provided by (used in):
Operating activities		$	204,987		$	108,121		$	320,182		$	241,710
Investing activities			(147,221)			(143,971)			(625,874)			(257,756)
Financings activities			117,018			38,145			316,871			15,764

(1)

Included within investing activities.

Other Financial Data and Key Ratios

Financial Metrics Summary

Certain key operating metrics that are not defined under IFRS (alternative performance measures) are presented below. 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. See the subsection titled “—Non-IFRS Financial Measures” for further information about such non-IFRS measures, definitions thereof and reconciliations to the most directly comparable IFRS measures.

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Non-IFRS Financial Measures

Average Quarterly Dividend per Share.

	Six Months Ended						Year Ended
	June 30, 2022			June 30, 2021			December 31, 2021			December 31, 2020
Declared on first quarter results 2022, 2021, 2021 and 2020 respectively		$	0.0425		$	0.0400		$	0.0400		$	0.0350
Declared on second quarter results 2022, 2021, 2021 and 2020 respectively			0.0425			0.0400			0.0400			0.0375
Declared on third quarter results 2021, 2020, 2021 and 2020 respectively			0.0425			0.0400			0.0425			0.0400
Declared on fourth quarter results 2021, 2020, 2021 and 2020 respectively			0.0425			0.0400			0.0425			0.0400
Trailing Twelve Months Average Quarterly Dividend per Share		$	0.0425		$	0.0400		$	0.0413		$	0.0381
Trailing Twelve Months Total Dividends per Share		$	0.1700		$	0.1600		$	0.1650		$	0.1525

Adjusted EBITDA.

The following table reconciles net income (loss) to Adjusted EBITDA for the periods presented.

	Six Months Ended						Year Ended
(In thousands)	June 30, 2022			June 30, 2021			December 31, 2021			December 31, 2020
Net income (loss)		$	(935,250)		$	(83,957)		$	(325,206)		$	(23,474)
Finance costs			39,162			22,512			50,628			43,327
Accretion of asset retirement obligations			14,003			10,216			24,396			15,424
Other (income) expense			(171)			5,582			8,812			421
Income tax (benefit) expense			(294,877)			(260,021)			(225,694)			(113,266)
Depreciation, depletion and amortization			118,480			71,843			167,644			117,290
Loss on joint and working interest owners receivable			—			—			—			6,931
Gains on bargain purchases			(1,249)			—			(58,072)			(17,172)
(Gain) loss on fair value adjustments of unsettled financial instruments			1,205,938			371,458			652,465			238,795
(Gain) loss on natural gas and oil property and equipment(1)			515			(234)			901			2,059
Costs associated with acquisitions			6,935			6,221			31,335			10,465
Other adjusting costs(2)			67,033			2,628			6,779			14,581
Non-cash equity compensation			4,069			3,588			7,400			5,007
(Gain) loss on foreign currency hedge			—			1,227			1,227			—
(Gain) loss on interest rate swap			(828)			251			530			202
Total adjustments			1,159,010			235,271			668,351			324,064
Adjusted EBITDA		$	223,760		$	151,314		$	343,145		$	300,590

(1)

Excludes $1.6 million in proceeds received for leasehold sales.

(2)

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sourcing costs for acquisitions. For the six months ended June 30, 2021, other adjusting costs are primarily associated with one-time projects and contemplated financing arrangements. Also included are expenses associated with an unused firm transportation agreement acquired as part of the Carbon Acquisition (as defined herein). Please see the subsection titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021—Expenses” for additional information regarding Other adjusting costs.

Other adjusting costs for 2021 are primarily associated with one-time projects and contemplated financing arrangements. Also included are expenses associated with an unused firm transportation agreement acquired as part of the Carbon Acquisition (as defined herein). For 2020, other adjusting costs are associated with legal and professional fees related to the up-list to the Premium Segment of the Main Market of the LSE.

Total Revenue, inclusive of hedges; Adjusted EBITDA Margin

The following table reconciles Total Revenue to Total Revenue, inclusive of hedges, to Adjusted EBITDA Margin for the periods presented.

	Six Months Ended						Year Ended
(Dollar amounts in thousands)	June 30, 2022			June 30, 2021			December 31, 2021			December 31, 2020
Total revenue		$	933,528		$	323,316		$	1,007,561		$	408,693
Net gain (loss) on commodity derivative settlements(1)			(468,731)			(21,949)			(320,656)			144,600
Total Revenue, inclusive of hedges		$	464,797		$	301,367		$	686,905		$	553,293
Adjusted EBITDA		$	223,760		$	151,314		$	343,145		$	300,590
Adjusted EBITDA Margin(2)			48%			50%			50%			54%

(1)

Net gain (loss) on commodity derivative settlements represents cash (paid) or received on commodity derivative contracts. This excludes settlements on foreign currency and interest rate derivatives as well as the gain (loss) on fair value adjustments for unsettled financial instruments for each of the periods presented.

(2)

Adjusted EBITDA Margin represents Adjusted EBITDA divided by Total Revenue, inclusive of hedges for each of the periods presented.

Free Cash Flow

	Six Months Ended						Year Ended
(Dollar amounts in thousands)	June 30, 2022			June 30, 2021			December 31, 2021			December 31, 2020
Net cash provided by operating activities		$	204,987		$	108,121		$	320,182		$	241,710
LESS: Expenditures on natural gas and oil properties and equipment			(44,539)			(16,458)			(50,175)			(21,947)
LESS: Cash paid for interest			(32,605)			(18,217)			(41,623)			(34,335)
Free Cash Flow		$	127,843		$	73,446		$	228,384		$	185,428

Adjusted Operating Cost Per Boe.

	Six Months Ended						Year Ended
(Dollar amounts in thousands, except per unit data)	June 30, 2022			June 30, 2021			December 31, 2021			December 31, 2020
Total production (MBoe)			24,620			19,133			43,257			36,538
Total operating expense		$	206,357		$	119,555		$	291,213		$	203,963
Employees, administrative costs and professional services			36,245			29,896			56,812			47,181
Recurring allowance for credit losses			—			602			(4,265)			1,559
Adjusted Operating Cost		$	242,602		$	150,053		$	343,760		$	252,703
Adjusted Operating Cost per Boe		$	9.85		$	7.84		$	7.95		$	6.92

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PV-10.

	As of December 31, 2021
	SEC Pricing(1)
	(in thousands)
PV-10
Pre-tax (Non-GAAP)(2)		$	4,037,016
PV of Taxes			(703,925)
Standardized Measure		$	3,333,091

(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 $3.60 per Mcf as of December 31, 2021 was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For NGLs and oil volumes, the average WTI price of $66.55 per Bbl as of December 31, 2021, was similarly adjusted for gravity, quality, local conditions, gathering, 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, 2021 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 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 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 Standardized Measure represents an estimate of the fair market value of our proved reserves.

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RISK FACTORS

An investment in our ADSs involves a high degree of risk. You should carefully consider the risks and uncertainty described below, together with all of the other information in this prospectus, including the sections titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Special Note Regarding Forward-Looking Statements” and our consolidated financial statements and the related notes thereto, before deciding to invest in our ADSs. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations. Our business, financial condition or results of operations could be materially and adversely affected by any of the following risks or additional risks and uncertainties that are currently immaterial or unknown. The trading price and value of our ADSs could decline due to any of these risks, and you may lose all or part of your investment.

Risks Relating 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;

•

geopolitical uncertainty;

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

•

weather conditions, natural disasters 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;

•

prices and availability of alternative fuels;

•

prices and availability of new technologies affecting energy consumption;

•

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;

•

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;

•

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

•

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

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It is impossible to accurately predict future gas, NGL and oil price movements. Historically, natural gas prices have been highly volatile and subject to large fluctuations in response to relatively minor changes in the demand for natural gas. The recent spike in U.S. Henry Hub natural gas prices to $8.783 per MMBtu in May 2022 as compared to a historically low price in June 2020 of $1.482 per MMBtu highlights 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:

•

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;

•

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

•

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

•

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

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

Our competitors also include those entities with greater technical, physical and financial resources than us. Finally, companies and certain private equity firms not previously investing in 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.

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The effects of operating in a competitive industry may include:

•

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

•

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

•

restrictions on the availability of equipment or services.

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

We may experience delays in production, 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.

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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.

The reserves data contained in this registration statement have been audited by Netherland, Sewell & Associates, Inc. (“NSAI”) unless stated otherwise. The standards utilized to prepare the reserves information that has been extracted in this document may be different from the standards of reporting adopted in other jurisdictions. Investors, therefore, should not assume that the data found in the reserves information set forth in this prospectus is directly comparable to similar information that has been prepared in accordance with the reserve reporting standards of other jurisdictions, such as the United Kingdom.

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

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

•

production history compared with production from other comparable producing areas;

•

quality and quantity of available data;

•

interpretation of the available geological and geophysical data;

•

effects of regulations adopted by governmental agencies;

•

future percentages of sales;

•

future natural gas, NGLs and oil prices;

•

capital investments;

•

effectiveness of the applied technologies and equipment;

•

effectiveness of our field operations employees to extract the reserves;

•

natural events or the negative impacts of natural disasters;

•

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

•

the judgment of the persons preparing the estimate.

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

•

the quantities and qualities that are ultimately recovered;

•

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

•

the production and operating costs incurred;

•

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

•

future hydrocarbon sales prices; and

•

decommissioning costs and changes to regulatory requirements for decommissioning.

Many of the factors in respect of which assumptions are made when estimating reserves are beyond our control and therefore these estimates may prove to be incorrect over time. Evaluations of reserves necessarily involve multiple uncertainties. The accuracy of any reserves evaluation depends on the quality of available information and natural gas, NGLs and oil engineering and geological interpretation. Furthermore,

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less historical well production data is available for unconventional wells because they have only become technologically viable in the past twenty years and the long-term production data is not always sufficient to determine terminal decline rates. In comparison, some conventional wells in our portfolio have been productive for a much longer time. As a result, there is a risk that estimates of our shale reserves are not as reliable as estimates of the conventional well reserves that have a longer historical profile to draw on. Interpretation, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserves and resources data. Moreover, different 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:

•

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

•

actual cost of development and production expenditures;

•

the amount and timing of actual production;

•

transportation and processing; and

•

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of our natural gas and oil properties will affect the timing and amount of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Actual future prices and costs may differ materially from those used in the present value estimate. 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, our four 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.

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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.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies, such as emissions controls and processing technologies. 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 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. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost or even at all given the personnel resources that are available to us. In addition to implementing new accounting and royalty management software, we are also implementing technology that aims to improve field data capture for our, as of December 31, 2021, approximately 77,530 gross productive wells so as to grant efficient access to information for decision-making. These efforts to upgrade our enterprise technology represent a significant undertaking and may have unforeseen adverse consequences. If one or more of the technologies used now or in the future were to become obsolete, our business, results of operations, financial condition, cash flows or prospects could be materially adversely affected if competitors gain a material competitive advantage.

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

The ongoing 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 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, 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 is changing rapidly, and additional impacts may arise 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:

•

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

•

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

•

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

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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;

•

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

•

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

•

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

In addition, the ongoing 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 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 and regional legislation, and regulatory measures to limit GHG emissions are currently in place or in various stages of discussion or implementation. In addition, the current U.S. administration has indicated that it is likely to attempt to enact more stringent methane pollution limits 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 and provinces.

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 again in Glasgow at the 26th Conference to the Parties on 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. 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 zero emission 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 greenhouse gas emission products could reduce the demand for the hydrocarbons that we produce.

In addition, 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

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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. Recently, President Biden signed an executive order calling for the development of a “climate finance plan,” and, separately, the Federal Reserve announced 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.

We currently report climate change risks applicable to our business consistent with the reporting practices adopted by The Task Force on Climate-Related Financial Disclosures (“TCFD”). Additionally, the SEC recently proposed new rules relating to the disclosure of a range of climate-related risks. 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 could incur increased costs related to the assessment and disclosure of climate-related risks. In addition, 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. The Company may also be subject to activism from groups campaigning against fossil fuel extraction or negative publicity from media alleging inadequate remedial actions by us to retire non-producing wells effectively, which could affect our reputation, disrupt our campaigns or programs, require us to incur significant, unplanned expense to respond or react to intentionally disruptive campaigns or media reports, create blockades to interfere with operations or otherwise negatively impact our business, results of operations, financial condition, cash flows or prospects. Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

Finally, our operations are subject to disruption from the physical effects that may be caused or aggravated as a result of 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 such as TC Energy (formerly TransCanada), Enbridge, CNX, Dominion Energy Transmission and MarkWest 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 MarkWest where approximately 33% of the NGLs we sold during the year ending December 31, 2021 were processed at MarkWest’s facility in Kentucky. Any material decrease in our ability to process or transport our natural gas through third-party infrastructure such as MarkWest’s 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

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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.

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

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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 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 disposal of fluids gathered from natural gas, oil and NGL producing operations in underground disposal wells has been pointed to by some groups and regulators as a potential cause of

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increased induced seismic events in certain areas of the country, including in the Appalachian Basin. States 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 incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. Any one or more 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 is the most recent federal legislation to amend 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. Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. Additionally, in May 2016, PHMSA proposed rules that would, if adopted, impose more stringent requirements for certain gas lines. Among other things, the proposed rulemaking would 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 would also require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”). Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use 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.

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More recently 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. The timing for implementation of this rule is uncertain at this time due to the recent change in presidential administrations.

Additional future regulatory action expanding PHMSA jurisdiction and imposing stricter integrity management requirements is likely. 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, of which approximately half remain to be completed. The mandates yet to be acted upon include requiring certain shut-off valves on transmission lines, mapping all HCAs and shortening the deadline for accident and incident notifications.

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, the 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day and also from $1 million to $2 million 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. Our business may be materially 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

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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.

We are actively monitoring the situation in Ukraine and assessing its 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 conflict in Ukraine or its impacts in Ukraine, Russia or Belarus as the conflict, and any resulting government reactions, are rapidly developing and beyond our control. The extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have substantial impact on the global economy and our business for an unknown period of time. Any of the aforementioned factors could affect our business, financial condition and results of operations. Any such disruptions may also magnify the impact of other risks described in this prospectus.

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 twelve months ended June 30, 2022, 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 the subsection titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt”) and as of June 30, 2022 we did not have amounts 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

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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”) and the acquisition of working interests in certain upstream assets and related facilities within the Central Region from a private seller, in conjunction with Oaktree (the “East Texas Assets 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, 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.

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

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

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

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

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, 2022, we have issued options under our equity incentive plans to employees and executive directors for a total of 16,143,324 new ordinary shares of the Company which are currently outstanding, and have also entered into restricted stock unit agreements and performance stock unit agreements with certain employees, of which 6,416,434 restricted stock units and 11,608,610 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 other 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 $300.0 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.

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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 and ABS V Notes (each as defined herein), there can be no assurance that we, through our SPVs, will be able to complete additional securitizations, particularly if the securitization markets become constrained. In addition, the value of any securities that our limited purpose, bankruptcy-remote, wholly owned subsidiaries retain in our securitizations, including securities retained to comply with applicable risk retention rules, might be reduced or, in some cases, eliminated as a result of an adverse change in economic conditions or the financial markets. In addition, our Term Loan I, ABS I Notes, ABS II Notes, ABS III Notes, ABS IV Notes and ABS V 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. While we did not have amounts outstanding on our Credit Facility as of June 30, 2022, increases in interest rates would increase the cost of servicing indebtedness under our Credit Facility or under future debt agreements subject to interest at variable rates, and materially reduce our profitability, decrease our liquidity and impact our solvency.

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

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

Our derivative contracts may result in substantial gains or losses. For example, we reported an operating loss of $467 million compared with an operating loss of $78 million for the years ended December 31, 2021 and 2020, respectively. This year-over-year increase in net loss was primarily attributable to an increase of $414 million in the mark-to-market loss on our derivative financial instrument valuations to $652 million in 2021 from $239 million in 2020. 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, water quality, the protection of threatened and endangered plant and animal species, and the safety of our assets. Although we believe that we have adequate procedures in place to mitigate operational risks and keep these under review, 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 or termination of licenses that are required to operate our sites or could result in other operational restrictions or obligations. Our health, safety and environmental policy is to observe local, state and national legal and regulatory requirements and to apply generally accepted industry best practices where legislation does not exist.

The terms of licenses, permits, regulatory orders, or permissions may include more stringent operational, environmental and/or health and safety requirements. Our operations have the potential to impact soil, air and water quality, biodiversity and ecosystems. Obtaining development or production licenses and permits may become more difficult or may be delayed due to governmental, regional or local environmental consultation, scientific studies, approvals or other considerations or requirements. Furthermore, third-parties such as environmental organizations may judicially contest licenses and permits already granted by relevant authorities 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 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 to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury

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or property damage. In addition, the risk of accidental spills or releases 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, new national executive orders, the imposition of more stringent requirements in licenses, increasingly strict enforcement of, or new interpretations of, existing laws, regulations 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 legal initiatives 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, safety or environmental damage caused by 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, safety or environmental regulations will be enacted or how current or future operational, health, safety or environmental regulations will be applied or enforced. We may have to incur significant expenditure for the installation and operation of systems and equipment for monitoring and remedial measures in the event that operational, health, safety and environmental regulations become more stringent or costly operational, health, safety and environmental 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 operational, health, 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.

In recent years, 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 energy saving building materials. These activities may result in demand shifts for oil and natural gas. In addition, a failure to comply with investor or customer expectations and standards, which are evolving, 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 industries, which could have a negative impact on our stock price and our access to and costs of capital.

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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 pledges made by some candidates now in political office. Further, new oil and gas leasing on public lands has been the subject of proposed reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases.

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. 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 licenses, contracts and field development plans.

Our operations must be carried out in accordance with the terms of licenses, operating agreements, annual work programs and budgets. Relevant legislation provides that fines may be imposed and a license may be suspended or terminated if a license holder, or party to a related agreement, fails to comply with its obligations under such license or agreement, or fails to make timely payments of levies and taxes for the licensed activity, 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 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 we will typically have a joint use agreement with the third party. This joint use agreement may stipulate that in consideration for permission to operate the conventional wells, we are to use reasonable efforts to maintain production so that the third party retains the shale licenses. If we fail to maintain production in the conventional wells, under the joint use agreement, we may be liable to the third party for replacing the lost land rights. The relevant authorities are typically authorized to, and do from time to time, inspect to verify compliance by us or our commercial partners, as applicable, with relevant laws and the licenses or the agreements pursuant to which we conduct our business. There can be no assurance that the views of the relevant government agencies regarding the development of the fields that we operate or the compliance with the terms of the licenses pursuant to which we conduct such operations will coincide with our views, which might lead to disagreements that may not be resolved.

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The suspension, revocation, withdrawal or termination of any of the 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 licenses or agreements pursuant to which we conduct business, whether inadvertent or otherwise, may lead to fines, penalties, restrictions, 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 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

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

Our domestic and international tax liabilities are subject to the allocation of expenses in differing jurisdictions. Our effective tax rate could be adversely affected by changes in the mix of earnings and losses

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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 which 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 ADSs depends on the individual circumstances of the holders of our ADSs. Holders of our ADSs are strongly advised to consult their professional tax advisers.

Risks Relating to Our ADSs and This Offering

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

The initial public offering price for the ADSs was determined through negotiations between the underwriters and us, and may vary from the market price of ADSs following this offering. If you purchase ADSs in this offering, you may not be able to resell those ADSs at or above the initial public offering price. The market price of our ADSs may fluctuate significantly due to a variety of factors, including:

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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 ADSs or ordinary shares by us, our executive officers and board members, holders of our ADSs 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 ADSs to fluctuate substantially, regardless of our actual operating performance, which may limit or prevent investors from readily selling their ADSs and may otherwise negatively affect the liquidity of our ADSs. 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 ADSs 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.

There has been no public market for our ADSs prior to this offering, and an active market may not develop in which investors can resell our ADSs.

Prior to this offering, there has been no public market for our ADSs, 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 ADSs will develop or be sustained or how the development of such a market might affect the market price for our ADSs. The initial public offering price of our ADSs will be agreed upon between us and the underwriters based on a number of factors, including market conditions in effect at the time of the offering, which may not be indicative of the price at which our ADSs will trade following completion of the offering. Investors may not be able to sell their ADSs at or above the initial public offering price.

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 ADSs. 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.

We have broad discretion in the use of the net proceeds from this offering and may not use them effectively.

We will have broad discretion in the application of the net proceeds from this offering and could spend the proceeds in ways that do not improve our results of operations or enhance the value of our ADSs. Our failure to apply these funds effectively could result in financial losses or cause the price of our ADSs to decline. Pending their use, we may invest the net proceeds from this offering in a manner that does not produce income or that loses value.

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

Following this offering and after our ADSs begin trading on the , our ordinary shares will continue to be admitted to the premium segment of the Official List of 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 ADSs and ordinary shares. However, the dual listing of our ADSs and 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 ADSs in the United States.

We are an “emerging growth company,” and we cannot be certain if the reduced reporting requirements applicable to “emerging growth companies” will make our ADSs less attractive to investors.

We are an “emerging growth company,” as defined in the JOBS Act. For as long as we continue to be an emerging growth company, we may take advantage of exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being

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required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. As an emerging growth company, we are required to report only two years of financial results and selected financial data in our initial public offering registration statement, as compared to three and five years, respectively, for comparable data reported by other public companies. We may take advantage of these exemptions until we are no longer an emerging growth company. We could be an emerging growth company for up to five years, although circumstances could cause us to lose that status earlier, including if the aggregate market value of our ADSs and ordinary shares held by non-affiliates exceeds $700 million as of any June 30 (the end of our second fiscal quarter) before that time, in which case we would no longer be an emerging growth company as of the following December 31 (our fiscal year-end). We cannot predict if investors will find our ADSs less attractive because we may rely on these exemptions. If some investors find our ADSs less attractive as a result, there may be a less active trading market for our ADSs and the price of our ADSs may be more volatile.

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.

Upon the closing of this offering, 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 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 ADSs less attractive, and there may be a less active trading market for the ADSs.

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 . These practices may afford less protection to shareholders than they would enjoy if we complied fully with the corporate governance listing standards of the .

As a foreign private issuer listed on the , we will be subject to corporate governance listing standards. However, rules permit a foreign private issuer like us to follow the corporate governance practices of its home country in lieu of certain corporate governance listing standards, provided that we disclose which requirements that we have not complied with in any year and confirm the U.K. corporate governance practices we have complied with. Certain corporate governance practices in the United Kingdom, which is our home country, may differ significantly from corporate governance listing standards. Although we voluntarily comply with the higher corporate governance standards of the U.K. 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 corporate governance listing standards applicable to U.S. domestic issuers. See the subsection titled “Management—Corporate Governance Practices and Foreign Private Issuer Status.”

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

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qualify as a foreign private issuer as of June 30, 2023 (the end of our second fiscal quarter in the fiscal year after this offering), 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, 2023. In order to maintain our current status as a foreign private issuer, either (a) a majority of our ADSs 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 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 , which could cause investors could lose confidence in our public reports and could have a material adverse effect on the trading price of our ADSs. We also expect that if we were required to comply with the rules and regulations applicable to U.S. domestic issuers, it would make it more difficult and expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These rules and regulations could also make it more difficult for us to attract and retain qualified members of our board of directors.

As a U.K. 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 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 offering. 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. While we remain an emerging growth company, we will not be required to include an audit report on internal control over financial reporting issued by our independent registered public accounting firm.

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 ADSs.

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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.

We are currently in the process of remediating the above material weakness, 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. Our current efforts to design and implement these new control activities may not be sufficient to remediate the material weakness described above or prevent future material weaknesses from occurring.

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

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

Future sales, or the possibility of future sales, of a substantial number of our ADSs could adversely affect the price of our ADSs.

Future sales of a substantial number of our ADSs, or the perception that such sales will occur, could cause a decline in the market price of our ADSs. Based upon the number of shares outstanding as of , 2022, after giving effect to this offering, we will have ordinary shares outstanding. ADSs sold in this offering may be resold in the public market immediately without restriction, unless purchased by our affiliates. Upon completion of this offering, we will have ordinary shares outstanding, approximately of which will be subject to day lock-up agreements entered into by our directors and officers and certain of our shareholders described in the sections titled “Shares and ADSs Eligible for Future Sale” and “Underwriting.” The representatives of the underwriters may, in their sole discretion, release all or any portion of the equity securities subject to the lock-up agreements prior to the expiration of the lock-up agreements. If, after the end of such lock-up agreements, these shareholders sell substantial amounts of ADSs in the public market, or the market perceives that such sales may occur, the market price of our ADSs and our ability to raise capital through an issue of equity securities in the future could be adversely affected.

If you purchase ADSs in this offering, you will suffer immediate dilution of your investment.

We expect the initial public offering price of our ADSs in this offering to be substantially higher than the net tangible book value per ADS prior to this offering. Therefore, if you purchase ADSs in this offering,

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you will pay a price per ADS that substantially exceeds our net tangible book value per ADS after this offering. To the extent outstanding options are exercised for ordinary shares, you may experience further dilution. Based on the assumed initial public offering price of $ per ADS, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on LSE of £ on , 2022 (based on an assumed exchange rate of £1.00 to $1. ), you will experience immediate dilution of $ per ADS, representing the difference between our net tangible book value per ADS and per ordinary share after giving effect to this and the assumed offering price. See the section titled “Dilution.”

Because we may not pay any cash dividends on our ADSs 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 consistently declared dividends on our ordinary shares, in the future, our board of directors may decide, in its discretion, not to declare and pay dividends. 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, capital appreciation, if any, on our ADSs may be your sole source of gains, and you will suffer a loss on your investment if you are unable to sell your ADSs at or above the offering price. See the section titled “Dividend Policy.”

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

Our dividend policy is dependent upon our financial condition, cash requirements, future prospects, compliance with the financial covenants and restricted payments covenant in the Company’s 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. While our dividend policy reflects our current and future expectation of future cash flow generation potential, there can be no guarantee that we will continue to pay dividends in the future on our ordinary shares.

You may not be able to exercise your right to vote the ordinary shares underlying your ADSs.

ADS holders may only exercise voting rights with respect to the ordinary shares underlying their respective ADSs in accordance with the provisions of the deposit agreement, which provides that a holder may vote the ordinary shares underlying any ADSs for any particular matter to be voted on by our shareholders either by withdrawing the ordinary shares underlying the ADSs or, to the extent permitted by applicable law and as permitted by the depositary, by requesting a temporary registration as shareholder and authorizing the depositary to act as proxy. However, you may not know about the meeting far enough in advance to withdraw those ordinary shares, and after such a withdrawal you would no longer hold ADSs, but rather you would directly hold the underlying ordinary shares. You also may not know about the meeting far enough in advance to request a temporary registration.

The depositary will try, as far as practical, to vote the ordinary shares underlying the ADSs as instructed by the ADS holders. In such an instance, if we ask for your instructions, the depositary, upon timely notice from us, will notify you of the upcoming vote and arrange to deliver our voting materials to you. We cannot guarantee that you will receive the voting materials in time to ensure that you can instruct the depositary to vote your ordinary shares or to withdraw your ordinary shares so that you can vote them yourself. If the depositary does not receive timely voting instructions from you, it may give a discretionary proxy to a person designated by us to vote the ordinary shares underlying your ADSs; provided, however, that no such discretionary proxy shall be given with respect to any matter to be voted upon as to which we inform the depositary that (i) we do not wish such proxy to be given, (ii) substantial opposition exists, or (iii) the rights of holders of ordinary shares may be adversely affected. Voting instructions may be given only in respect of a number of ADSs representing an integral number of ordinary shares or other deposited securities. In addition, the depositary and its agents are not responsible for failing to carry out voting instructions or for the manner of carrying out voting instructions. This means that you may not be able to exercise any right to vote that you may have with respect to the underlying ordinary shares, and there may be nothing you can do

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if the ordinary shares underlying your ADSs are not voted as you requested. In addition, the depositary is only required to notify you of any particular vote if it receives notice from us in advance of the scheduled meeting.

You will not be directly holding our ordinary shares. Holders of the ADSs will not be able to exercise the preemptive subscription rights related to the ordinary shares that they represent and may suffer dilution of their equity holding in the event of future issuances of our ordinary shares.

UK law generally provides shareholders with preemptive rights when new shares are issued for cash. Shareholders’ preemptive subscription rights, in the event of issuances of ordinary shares against cash payment, may be disapplied by a special resolution of the shareholders at a general meeting of our shareholders. The absence of preemptive rights for existing equity holders may cause dilution to such holders.

Furthermore, the ADS holders would not be entitled, even if such rights accrued to our shareholders in any given instance, to receive such preemptive subscription rights related to the ordinary shares that they represent. Rather, the depositary is required to endeavor to sell any such subscription rights that may accrue to the ordinary shares underlying the ADSs and to remit the net proceeds therefrom to the ADS holders pro rata. In addition, if the depositary is unable to sell rights, the depositary will allow the rights to lapse, in which case you will receive no value for these rights. Further, if we offer holders of our ordinary shares the option to receive dividends in either cash or ordinary shares, under the deposit agreement, ADS holders will not be permitted to elect to receive dividends in ordinary shares or cash, but will receive whichever option we provide as a default to shareholders who fail to make such an election.

Holders of our ADSs may be subject to U.S. federal withholding or income tax depending on their country of residence and their ownership percentages.

Pursuant to Section 7874 of the U.S. Internal Revenue Code (the “Code”), we believe we are and will continue to be treated as a U.S. corporation for all purposes under the Code. Since we will be treated as a U.S. corporation for all purposes under the Code, we will not be treated as a “passive foreign investment company,” as such rules apply only to non-U.S. corporations for U.S. federal income tax purposes.

As a U.S. corporation that is a U.S. real property holding corporation, distributions paid by us to Non-U.S. Holders (as defined below in “Material Tax Considerations—Material United States Federal Income Tax Considerations”) are generally subject to U.S. federal withholding taxes (at a rate of up to 30%, which may, in certain circumstances, be reduced by an applicable treaty) applied on the gross amount of such distributions. See the subsection titled “Material Tax Considerations—Material United States Federal Income Tax Considerations—Non-U.S. Holders—Distributions.” Furthermore, Sections 1471 through 1474 of the Code (commonly referred to as “FATCA”) generally impose a 30% withholding tax on dividends on, or gross proceeds from the sale or other disposition of, our ADSs paid to a “foreign financial institution” or a “non-financial foreign entity” unless certain conditions are met. However, proposed Treasury Regulations currently eliminate FATCA withholding on payments of gross proceeds from the sale or other disposition of stock, including our ADSs, on or after January 1, 2019. While taxpayers generally may rely on these proposed Treasury Regulations until final Treasury Regulations are issued, there can be no assurance that the final Treasury Regulations will continue to eliminate withholding on such payments of gross proceeds.

Due to the nature of our assets and operations, we believe we are (and will continue to be) a U.S. real property holding corporation under the Code and our ADSs constitute (and we expect our ADSs to continue to constitute) a U.S. real property interest (“USRPI”). Non-U.S. Holders generally are subject to a 15% withholding tax on the amount realized from a sale or other taxable disposition of a USRPI, such as our ADSs, which is required to be collected from any sale or disposition proceeds. Such Non-U.S. Holders are subject to U.S. federal income tax (at the regular rates) in respect of any gain on their sale or disposition of the ADSs and are required to file a U.S. tax return to report such gain and pay any tax liability that is not satisfied by such withholding. However, if the ADSs are considered “regularly traded on an established securities market” (within the meaning of the Treasury Regulations) then Non-U.S. Holders will not be subject to the 15% withholding tax on the disposition of the ADSs, even if such ADSs constitute USRPIs. Moreover, if the ADSs are considered “regularly traded on an established securities market” (within the meaning of the Treasury Regulations) and the Non-U.S. Holder satisfies the “5% test” (as defined in the

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subsection “Material Tax Considerations—Material United States Federal Income Tax Considerations”), such Non-U.S. Holder may treat their ownership of the ADSs as not constituting a USRPI and will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of the ADSs (in addition to not being subject to the 15% withholding tax described above) or U.S. tax return filing requirements. However, we make no representations as to whether the ADSs have been and will be treated as “regularly traded on an established securities market.”

For further details, see the subsection titled “Material Tax Considerations—Material United States Federal Income Tax Considerations.”

Purchasers of ADSs in this offering may not receive distributions on our ordinary shares in the form of ADSs or any value for them if it is illegal or impractical to make them available to holders of ADSs.

The depositary for our ADSs has agreed to pay to purchasers of ADSs in this offering the cash dividends or other distributions it or the custodian receives on our ordinary shares or other deposited securities after deducting its fees and expenses. Purchasers of our ADSs will receive these distributions in proportion to the number of our ordinary shares their ADSs represent. However, in accordance with the limitations set forth in the deposit agreement, it may be unlawful or impractical to make a distribution available to holders of ADSs. We have no obligation to take any other action to permit the distribution of our ADSs, ordinary shares, rights or anything else to holders of our ADSs. This means that purchasers of ADSs in this offering may not receive the distributions we make on our ordinary shares or any value from them if it is unlawful or impractical to make them available to them. These restrictions may have a material adverse effect on the value of a purchaser’s ADSs.

Purchasers of ADSs in this offering may be subject to limitations on transfer of their ADSs.

ADSs are transferable on the books of the depositary. However, the depositary may close its transfer books at any time or from time to time when it deems expedient in connection with the performance of its duties. In addition, the depositary may refuse to deliver, transfer or register transfers of ADSs generally when our books or the books of the depositary are closed, or at any time if we or the depositary deems it advisable to do so because of any requirement of law or of any government or governmental body, or under any provision of the deposit agreement, or for any other reason in accordance with the terms of the deposit agreement.

ADS holders may not be entitled to a jury trial with respect to claims arising under the deposit agreement, which could result in less favorable outcomes to the plaintiff(s) in any such action.

The deposit agreement governing the ADSs representing our ordinary shares provides that, to the fullest extent permitted by applicable law, holders and beneficial owners of ADSs, including purchasers of ADSs in secondary transactions, irrevocably waive the right to a jury trial of any claim that they may have against us or the depositary arising from or relating to our ordinary shares, our ADSs or the deposit agreement, including any claim under the U.S. federal securities laws. The waiver continues to apply to claims that arise during the period when a holder holds the ADSs, even if the ADS holder subsequently withdraws the underlying ordinary shares.

However, you will not be deemed, by agreeing to the terms of the deposit agreement, to have waived our or the depositary’s compliance with U.S. federal securities laws and the rules and regulations promulgated thereunder. In fact, you cannot waive our or the depositary’s compliance with U.S. federal securities laws and the rules and regulations promulgated thereunder. If we or the depositary opposed a demand for jury trial relying on above-mentioned jury trial waiver, it is up to the court to determine whether such waiver was enforceable considering the facts and circumstances of that case in accordance with the applicable state and federal law.

If this jury trial waiver provision is prohibited by applicable law, an action could nevertheless proceed under the terms of the deposit agreement with a jury trial. To our knowledge, the enforceability of a jury trial waiver under the federal securities laws has not been finally adjudicated by a federal court or by the United States Supreme Court. Nonetheless, we believe that a jury trial waiver provision is generally enforceable under the laws of the State of New York, which govern the deposit agreement, by a federal or state court

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in the city of New York. In determining whether to enforce a jury trial waiver provision, New York courts will consider whether the visibility of the jury trial waiver provision within the agreement is sufficiently prominent such that a party has knowingly waived any right to trial by jury. We believe that this is the case with respect to the deposit agreement and the ADSs. It is advisable that you consult legal counsel regarding the jury waiver provision before entering into the deposit agreement.

In addition, New York courts will not enforce a jury trial waiver provision in order to bar a viable setoff or counterclaim sounding in fraud or one which is based upon a creditor’s negligence in failing to liquidate collateral upon a guarantor’s demand, or in the case of an intentional tort claim, none of which we believe are applicable in the case of the deposit agreement or the ADSs. If you or any other holders or beneficial owners of ADSs, including purchasers of ADSs in secondary transactions, bring a claim against us or the depositary relating to the matters arising under the deposit agreement or our ADSs, including claims under federal securities laws, you or such other holder or beneficial owner may not have the right to a jury trial regarding such claims, which may limit and discourage lawsuits against us or the depositary. If a lawsuit is brought against us or the depositary according to the deposit agreement, it may be heard only by a judge or justice of the applicable trial court, which would be conducted according to different civil procedures and may have different outcomes compared to that of a jury trial, including results that could be less favorable to the plaintiff(s) in any such action.

Nevertheless, if this jury trial waiver provision is not enforced, to the extent a court action proceeds, it would proceed under the terms of the deposit agreement with a jury trial. Moreover, as the jury trial waiver relates to claims arising out of or relating to the ADSs or the deposit agreement, we believe that, as a matter of construction of the clause, the waiver would likely continue to apply to ADS holders who withdraw the ordinary shares from the ADS facility with respect to claims arising before the cancellation of the ADSs and the withdrawal of the ordinary shares, and the waiver would most likely not apply to ADS holders who subsequently withdraw the ordinary shares represented by ADSs from the ADS facility with respect to claims arising after the withdrawal. However, to our knowledge, there has been no case law on the applicability of the jury trial waiver to ADS holders who withdraw the ordinary shares represented by the ADSs from the ADS facility.

The waiver may limit an ADS holder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or the depositary. ADS holders seeking to bring a claim relating to our ADSs or the deposit agreement, including any claim under U.S. federal securities laws, may be subject to increased costs and suffer an imbalance of resources relative to us or the depositary than if such dispute was litigated in a jury trial. These factors may discourage such lawsuits against us and the depositary.

ADS holders have limited choice of forum, which could limit your ability to obtain a favorable judicial forum for complaints against us, the depositary or our respective directors, officers or employees.

The deposit agreement governing our ADSs provides that, (i) the deposit agreement and the ADSs will be interpreted in accordance with the laws of the State of New York, and (ii) as an owner of ADSs, you irrevocably agree that any legal action arising out of the deposit agreement and the ADSs involving us or the depositary may only be instituted in a state or federal court in the city of New York. Any person or entity purchasing or otherwise acquiring any our ADSs, whether by transfer, sale, operation of law or otherwise, shall be deemed to have notice of and have irrevocably agreed and consented to these provisions. This choice of forum provision may increase your cost and limit your ability to bring a claim in a judicial forum that you find favorable for disputes with us, the depositary or our and the depositary’s respective directors, officers or employees, which may discourage such lawsuits against us, the depositary and our and the depositary’s respective directors, officers or employees. However, it is possible that a court could find such choice of forum provisions to be inapplicable or unenforceable. The enforceability of similar choice of forum provisions has been challenged in legal proceedings. It is possible that a court could find this type of provisions to be inapplicable or unenforceable.

To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. Accordingly, actions by our

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ADS holders to enforce any duty or liability created by the Exchange Act, the Securities Act or the respective rules and regulations thereunder must be brought in a federal court in the city of New York. Our ADS holders will not be deemed to have waived our compliance with the federal securities laws and the regulations promulgated thereunder.

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 and, therefore, certain of the rights of holders of ADSs, 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 the subsection titled “Description of Share Capital and Articles of Association—Differences in Corporate Law” in this prospectus for a description of the principal differences between the provisions of the Companies Act 2006 applicable to us and, for example, the Delaware General Corporation Law relating to shareholders’ rights and protections.

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

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

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

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

The depositary for our ADSs is entitled to charge holders fees for various services, including annual service fees.

The depositary for our ADSs is entitled to charge holders fees for various services including for the issuance of ADSs upon deposit of ordinary shares, cancellation of ADSs, distributions of cash dividends or other cash distributions, distributions of ADSs pursuant to share dividends or other free share distributions, distributions of securities other than ADSs and annual service fees. In the case of ADSs issued by the depositary into The Depository Trust Company (“DTC”), the fees will be charged by the DTC participant to the account of the applicable beneficial owner in accordance with the procedures and practices of the DTC participant as in effect at the time. The depositary for our ADSs will not generally be responsible for any United Kingdom stamp duty or stamp duty reserve tax arising upon the issuance or transfer of ADSs.

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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 ADSs and our trading volume could decline.

The trading market for our ADSs 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 ADSs 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 ADSs or publish inaccurate or unfavorable research about our business, the price of our ADSs 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 ADSs could decrease, which might cause the price of our ADSs and trading volume to decline.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are based on our management’s beliefs and assumptions and on information currently available to our management. Some of the statements under the sections titled “Prospectus Summary,” “Risk Factors,” “Use of Proceeds,” “Dividend Policy,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” and elsewhere in this prospectus 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 prospectus 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 prospectus, 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 prospectus 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 prospectus are described under “Risk Factors” and in other sections of this prospectus. Such factors include, but are not limited to:

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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;

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

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

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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;

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

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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;

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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;

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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;

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

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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;

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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;

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

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uncertainties about our ability to replace reserves;

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our hedging strategy;

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

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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 the section titled “Risk Factors” of this prospectus 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 prospectus 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 prospectus, 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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USE OF PROCEEDS

We estimate that the net proceeds to us from this offering will be approximately $ million, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, based on an assumed initial public offering price of $ per ADS, the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE on , 2022 (based on an assumed exchange rate of £1.00 to $1. . If the underwriters exercise their option to purchase additional ADSs in full, we estimate that the net proceeds to be received by us will be approximately $ million, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

Each $1.00 increase (decrease) in the assumed initial public offering price of $ per ADS would increase (decrease) the net proceeds to us from this offering by approximately $ million, assuming the number of ADSs offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We may also increase or decrease the number of ADSs we are offering. Each increase (decrease) of 100,000 ADSs in the number of ADSs offered by us would increase (decrease) the net proceeds to us from this offering by approximately $ million, assuming that the assumed initial public offering price remains the same, and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us. We do not expect that a change in the initial public offering price or the number of ADSs by these amounts would have a material effect on our uses of the proceeds from this offering, although it may accelerate the timing of when we need to seek additional capital.

The amount of what, and timing of when, we actually spend for these purposes may vary significantly and will depend on a number of factors, including our future revenue and cash generated by operations and the other factors described in the section titled “Risk Factors.” Accordingly, we will have broad discretion in deploying the net proceeds of this offering.

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DIVIDEND POLICY

We have consistently declared dividends on our ordinary shares since the admission of our shares to listing on the premium segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE. During the six months ended June 30, 2022 and 2021 and during the years ended December 31, 2021 and 2020, we declared and paid dividends of an aggregate of approximately $72 million, $62 million, $130 million and $99 million, respectively.

Under UK law, among other things, we may only pay dividends if we have sufficient distributable reserves (on a non-consolidated basis), which are our accumulated realized profits that have not been previously distributed or capitalized less our accumulated realized losses, so far as such losses have not been previously written off in a reduction or reorganization of capital. In addition, our ability to pay dividends is limited by restrictions under the terms of our Credit Facility. Our Credit Facility contains a restricted payment covenant that limits our subsidiaries’ ability to make certain payments, based on the pro forma effect thereof on certain financial ratios. For example, our subsidiaries, from whom we derive all of our cash flow, are restricted from making certain dividends or distributions based on financial tests, giving pro forma effect to any such payment, relating to (a) Available Free Cash Flow (as defined in the Credit Facility) of greater than zero, (b) a total net leverage ratio of 2.5 to 1.0 for the trailing four quarter period, and (c) available Liquidity (as defined in the Credit Facility but in any event inclusive of borrowing capacity thereunder) of at least 20% of the Borrowing Base thereunder. Please see the subsection titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility” for additional information on our Credit Facility.

While we cannot assure you that we will be able to pay cash dividends on our ordinary shares in future periods, we intend to, consistent with our historical performance since the LSE IPO (but subject to the terms of our Credit Facility), use a portion of our cash flow to pay regular dividends on our ordinary shares, as well as, on a proportionate basis, our ADSs.

We have not adopted, and do not intend to adopt, a separate written Company dividend policy prior to the consummation of this offering.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and total capitalization as of December 31, 2021, as follows:

•

on an actual basis; and

•

on an as adjusted basis to reflect the issuance and sale of ADSs, representing ordinary shares with a nominal value of £0.01 per share in this offering at the assumed initial public offering price of $ per ADS, the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2022 (based on an assumed exchange rate of £1.00 to $1. ), after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

You should read this information in conjunction with our consolidated financial statements and the related notes appearing at the end of this prospectus and the sections titled “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other financial information contained in this prospectus.

	As of December 31, 2021
	Actual			As Adjusted(1)
	(in thousands)
Cash and cash equivalents		$	12,558		$
Total debt		$	1,041,665		$
Shareholders’ equity:
Ordinary shares, nominal value £0.01 per share: shares, actual; shares, as adjusted
Share capital			11,571
Share premium account			1,052,959
Share based payment and other reserves			14,156
Retained earnings (accumulated deficit)			(431,277)
Non-controlling interest			16,541
Total shareholders’ equity			663,950
Total capitalization		$	1,705,615		$

(1)

A $1.00 increase or decrease in the assumed initial public offering price of $ per ADS, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on, , 2022 (based on an assumed exchange rate of £1.00 to $1. ), would increase or decrease the as adjusted amount of each of cash and cash equivalents, share premium account, total equity and total capitalization by approximately $ million, assuming the number of ADSs offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us. An increase or decrease of 100,000 shares in the number of ADSs offered by us, as set forth on the cover page of this prospectus, would increase or decrease the as adjusted amount of each of cash and cash equivalents, share premium account, total equity and total capitalization by approximately $ million, assuming no change in the assumed initial public offering price of $ per ADS and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

As adjusted equity amounts shown in the table above exclude the impact of:

•

ordinary shares issuable upon the exercise of options outstanding under our 2017 Equity Incentive Plan as of December 31, 2021 at a weighted-average exercise price of $ per share; and

•

ordinary shares reserved for future issuance under our 2017 Equity Incentive Plan as described in the subsection titled “Management—Equity Compensation Arrangements—2017 Equity Incentive Plan.”

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DILUTION

If you invest in our ADSs in this offering, your ownership interest will be diluted to the extent of the difference between the initial public offering price per ADS and the as adjusted net tangible book value per share immediately following the consummation of this offering.

At December 31, 2021, we had a historical net tangible book value of $664 million, corresponding to a net tangible book value of $ per ordinary share, or $ per ADS, based on an ordinary share to ADS ratio of to 1. Net tangible book value per ordinary share represents the amount of our total assets less our total liabilities, excluding goodwill and other intangible assets, divided by the total number of our ordinary shares outstanding.

After giving effect to the sale by us of ADSs (representing an aggregate of ordinary shares) in this offering at the assumed initial public offering price of $ per ADS, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2022 (based on an assumed exchange rate of £1.00 to $1. ), after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, our as adjusted net tangible book value at December 31, 2021 would have been approximately $ million, representing $ per ordinary share or $ per ADS. This represents an immediate increase in net tangible book value of $ per ordinary share or $ per ADS to existing shareholders and an immediate dilution in net tangible book value of $ per ordinary share or $ per ADS to new investors purchasing ADSs in this offering at the assumed initial public offering price. Dilution in net tangible book value per ADS to new investors is determined by subtracting as adjusted net tangible book value per ADS after this offering from the assumed initial public offering price per ADS paid by new investors.

The following table illustrates this dilution to new investors purchasing ADSs in the offering.

Assumed initial public offering price per ADS

Historical net tangible book value per ADS as of December 31, 2021

Increase in net tangible book value per ADS attributable to this offering

As adjusted net tangible book value per ADS after this offering

Dilution per ADS to new investors in this offering

If the underwriters exercise their option to purchase additional ADSs from us in full, our as adjusted net tangible book value per ADS after this offering would be $ per ADS, representing an immediate increase in as adjusted net tangible book value of $ per ADS to existing shareholders and immediate dilution of $ per ADS in as adjusted net tangible book value to new investors purchasing ADSs in this offering, based on an assumed initial public offering price of $ per ADS, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2022 (based on an assumed exchange rate of £1.00 to $1. ).

Each $1.00 increase (decrease) in the assumed initial public offering price of $ per ADS, which reflects the U.S. dollar equivalent of the closing price of our ordinary shares on the LSE of £ on , 2022 (based on an assumed exchange rate of £1.00 to $1. ), respectively, would increase (decrease) the as adjusted net tangible book value after this offering by $ per ADS and the dilution to new investors participating in the offering by $ per ADS, assuming that the number of ADSs offered by us, as set forth on the cover page of this prospectus, remains the same, and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of ADSs we are offering.

Similarly, an increase of 100,000 in the number of ordinary shares, including ordinary shares represented by ADSs, offered by us, as set forth on the cover page of this prospectus, would increase the as adjusted net tangible book value after this offering by $ per ADS and decrease the dilution to new investors participating in this offering by $ per ADS, assuming no change in the assumed initial public offering price per ADS or the assumed offering price per ordinary share, as applicable, and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. A decrease of 100,000 in the number of ordinary shares, including ordinary shares represented by ADSs, offered by us, as

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set forth on the cover page of this prospectus, would decrease the as adjusted net tangible book value after this offering by $ per ADS and increase the dilution to new investors participating in this offering by $ per ADS, assuming no change in the assumed initial public offering price per ADS or the assumed offering price per ordinary share, as applicable, and after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

The following table summarizes, as of December 31, 2021, the total number of ordinary shares purchased from us, the total consideration paid to us and the average price per share paid by the existing shareholders and by new investors purchasing ADSs in this offering.

	ADSs Purchased			Ordinary Shares Purchased			Total Consideration				Average Price Per Share		Average Price Per ADS
	Number	Percent		Number	Percent		Amount		Percent		Average Price Per Share		Average Price Per ADS
Existing shareholders			%			%		$		%		$		$
New investors												$		$
Total			100.0%			100.0%		$		100.0%

To the extent any of our outstanding options is exercised, there will be further dilution to new investors.

If the underwriters exercise their option to purchase additional ADSs in full:

•

the percentage of ordinary shares held by existing shareholders will decrease to approximately % of the total number of our ordinary shares (including ordinary shares represented by ADSs) outstanding after this offering; and

•

the percentage of ordinary shares held by new investors will increase to approximately % of the total number of our ordinary shares (including ordinary shares represented by ADSs) outstanding after this offering.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion together with the consolidated financial statements and related notes included elsewhere in this prospectus. The statements in this discussion regarding industry outlook, our expectations regarding our future performance, liquidity and capital resources and other non-historical statements in this discussion are forward-looking statements. These forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described in the sections titled “Risk Factors” and “Special Note Regarding Forward-Looking Statements.” Our actual results may differ materially from those contained in or implied by any forward-looking statements. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

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 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 to optimally steward the resource already developed by others within our industry, reducing the environmental footprint, while sustaining important jobs and tax revenues for many local communities. While most companies in our sector are built to explore 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.

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 $993 million during the six months ended June 30, 2022 and the years ended December 31, 2021 and 2020, comprised of:

•

May 2022: Certain plugging infrastructure in the Appalachian Region;

•

April 2022:

•

The East Texas Assets Acquisition, in which we acquired working interests in certain upstream assets and related facilities within the Central Region from a private seller, in conjunction with Oaktree;

•

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

•

February 2022: Certain plugging infrastructure in the Appalachian Region;

•

December 2021: The Tapstone Acquisition, in which we acquired working interests in certain upstream assets, field infrastructure, equipment and facilities within the Central Region in conjunction with Oaktree;

•

August 2021: The Tanos Acquisition, in which we acquired working interests in certain upstream assets, field infrastructure, equipment and facilities in the Central Region in conjunction with Oaktree;

•

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

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•

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

•

December 2020: The Utica Acquisition, in which we acquired five gross unconventional horizontal wells in the state of Ohio; and

•

May 2020:

•

The Carbon Acquisition, in which we acquired certain upstream and midstream assets in Kentucky, West Virginia and Tennessee; and

•

The EQT Acquisition, in which we acquired upstream assets and related gathering infrastructure in Pennsylvania and West Virginia.

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 future natural gas, NGLs 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.

We employ a hedging strategy in which we opportunistically hedge a majority of our first two years of production and 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 commodity price volatility. As a result 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. The terms of our Credit Facility and ABS Notes (as defined herein) also require us to hedge our production.

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 higher 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, NGLs and oil revenues becoming more sensitive to commodity price fluctuations.

Although the current outlook on natural gas, NGLs and oil prices is generally favorable, and our operations have not been significantly impacted by material declines in commodity prices in the short-term, in the event future disruptions to pricing occur and continue for an extended period of time, the unhedged portion of our cash flows could be adversely impacted.

Recent Developments

Since the release of our mid-year 2022 results on August 8, 2022, we have achieved the following milestones:

•

On September 27, 2022, closed on our previously announced agreement to acquire certain upstream assets in the Central Region from ConocoPhillips Company for a gross purchase price

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of $240 million. Based solely on management’s estimates, we believe that the acquisition will add approximately 31 MMBoe (186 Bcfe) of net PDP reserves as of August 31, 2022. We currently estimate that these assets will produce approximately 9 MBoepd for the twelve months ending August 31, 2023 and will maintain our consolidated corporate decline rate of ~8.5%. Based on management’s estimates, the purchase price represents the annual present value of the estimated pretax and unhedged cashflows to be generated from PDP reserves when using NYMEX strip pricing, discounted at an approximate annual rate of 17%, a higher discount rate than is often used by industry participants when valuing upstream assets;

•

In August 2022, we amended and restated the credit agreement governing our Credit Facility by entering into the A&R Revolving Credit Facility. The amendment enhances the alignment with our stated ESG initiatives by including sustainability performance targets similar to those included in the ABS V Notes as described in this prospectus, extends the maturity of our Credit Facility to August 2026, removes DGOC as a credit party from the Credit Facility, reaffirms the borrowing base of $300 million and included no other material changes to pricing or terms. Further, as a result of the amendment, the covenant structure associated with the A&R Revolving Credit Facility will now be associated with solely DP RBL CO LLC, the borrower, a subsidiary of DGOC, the existing borrower. Please see the subsection titled “—Liquidity and Capital Resources—Credit Facility” for additional information regarding the A&R Revolving Credit Facility.

The reserve information presented above with respect to our pending acquisition is based solely on our internal evaluation and interpretation of reserve and other information provided to us by the seller in the course of our due diligence with respect to the pending acquisition and has not been independently verified or estimated. Our production estimates are based on, among other things, historical production and decline rate information provided by the seller. Achieving this production estimate will depend on actual well performance and operating conditions which may be outside of our control. For more detail on these risks and assumptions, see “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors—Risks Relating to Our Business, Operations and Industry”.

Continued inflationary pressures could impact our profitability. Though we believe that the rates of inflation in recent years, including the twelve months ended June 30, 2022, 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. With respect to our costs of capital, our ABS Notes are fixed-rate instruments (subject to adjustment pursuant to the sustainability-linked features described under the subsection titled “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt”) and as of June 30, 2022 we do not currently have amounts 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.

Segment Reporting

We are an independent owner and operator of producing natural gas and oil wells with properties located in the states of Tennessee, Kentucky, Virginia, West Virginia, Ohio, Pennsylvania, Oklahoma, Texas and Louisiana. Our strategy is to acquire long-life producing assets, efficiently operate those assets to generate cash flow to pay dividends to our shareholders, and then to retire assets safely and responsibly at

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the end of their useful life. Our assets consist of natural gas and oil wells, pipelines and a network of gathering lines and compression facilities that are complementary to our core assets. We acquire and manage these assets in a complementary fashion to vertically integrate and improve margins rather than managing them as separate operations. Accordingly, when determining operating segments under IFRS 8, we identified one operating segment that produces and transports natural gas, NGLs and oil in the United States. Refer to Note 2 in the Notes to the Consolidated Financial Statements for a description of our segment reporting.

Results of Operations

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

The following tables set forth our results of operations for the six months ended June 30, 2022 and 2021. See the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures” for a reconciliation of the Non-IFRS measures included in the table to the most directly comparable IFRS financial performance measure.

	Six Months Ended
	June 30, 2022			June 30, 2021			Change			% Change
Net production
Natural gas (MMcf)			127,398			104,888			22,510		21%
NGLs (MBbls)			2,601			1,410			1,191		84%
Oil (MBbls)			786			242			544		225%
Total production (MBoe)			24,620			19,133			5,487		29%
Average daily production (Boepd)			136,022			105,707			30,315		29%
% Natural gas (Boe basis)			86%			91%
Average realized sales price
(excluding impact of derivatives settled in cash)
Natural gas (Mcf)		$	5.71		$	2.46		$	3.25		132%
NGLs (Bbls)			41.46			24.86			16.60		67%
Oil (Bbls)			100.28			55.88			44.40		79%
Total (Boe)		$	37.12		$	16.05		$	21.07		131%
Average realized sales price
(including impact of derivatives settled in cash)
Natural gas (Mcf)		$	2.68		$	2.43		$	0.25		10%
NGLs (Bbls)			16.61			10.13			6.48		64%
Oil (Bbls)			76.24			64.38			11.86		18%
Total (Boe)		$	18.08		$	14.90		$	3.18		21%
Revenue (in thousands)
Natural gas		$	727,152		$	258,453		$	468,699		181%
NGLs			107,846			35,050			72,796		208%
Oil			78,817			13,523			65,294		483%
Total commodity revenue		$	913,815		$	307,026		$	606,789		198%
Midstream revenue			16,602			15,089			1,513		10%
Other revenue			3,111			1,201			1,910		159%
Total revenue		$	933,528		$	323,316		$	610,212		189%
Gain (loss) on derivative settlements
(in thousands)
Natural gas		$	(385,186)		$	(3,246)		$	(381,940)		11,766%

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	Six Months Ended
	June 30, 2022			June 30, 2021			Change			% Change
NGLs			(64,654)			(20,761)			(43,893)		211%
Oil			(18,891)			2,058			(20,949)		(1,018)%
Net gain (loss) on commodity derivative settlements(1)		$	(468,731)		$	(21,949)		$	(446,782)		2,036%
Total Revenue, inclusive of hedges		$	464,797		$	301,367		$	163,430		54%
Per Boe Metrics
Average realized sales price
(including impact of derivatives settled in cash)		$	18.08		$	14.90		$	3.18		21%
Other revenue			0.80			0.85			(0.05)		(6)%
LOE			(3.32)			(2.77)			(0.55)		20%
Midstream operating expense			(1.35)			(1.52)			0.17		(11)%
Employees, administrative costs and professional services			(1.47)			(1.56)			0.09		(6)%
Recurring allowance for credit losses			—			(0.03)			0.03		(100)%
Production taxes			(1.37)			(0.48)			(0.89)		185%
Transportation expense			(2.34)			(1.48)			(0.86)		58%
Adjusted EBITDA per Boe		$	9.03		$	7.91		$	1.12		14%
Adjusted EBITDA Margin			48%			50%
Other financial metrics (in thousands)
Adjusted EBITDA		$	223,760		$	151,314		$	72,446		48%
Operating profit (loss)		$	(1,177,133)		$	(305,668)		$	(871,465)		285%
Net income (loss)		$	(935,250)		$	(83,957)		$	(851,293)		1,014%

(1)

Production, Revenue and Hedging

Total revenue in the six months ended June 30, 2022 of $934 million increased 189% from $323 million reported for the six months ended June 30, 2021, primarily due to a 131% increase in the average realized sales price and 29% higher production. Including commodity hedge settlement losses of $469 million and $22 million in the six months ended June 30, 2022 and 2021, respectively, Total Revenue, inclusive of hedges, increased by 54% to $465 million in 2022 from $301 million in 2021.

While higher realized sales prices in the six months ended June 30, 2022 contributed $45 million in additional Total Revenue, inclusive of hedges, we will not realize the full impact of the higher commodity price environment until the second half of 2022 and into 2023 when the increase in our hedged floor price, the result of recent enhancements to our hedge portfolio, will be more impactful. The majority of the increase in Total Revenue, inclusive of hedges, or $115 million, was driven by added volumes. We produced approximately 24,620 MBoe in 2022 versus approximately 19,133 MBoe in 2021. The increase in volumes was primarily due to the full integration of the Central Region assets acquired in May, July, August, and December of 2021 in connection with the Indigo, Blackbeard, Tanos and Tapstone acquisitions, respectively, as well as approximately two months of production from the East Texas assets acquired in April 2022.

The following table summarizes average commodity prices for the periods presented with Henry Hub on a per Mcf basis and Mont Belvieu and WTI on a per Bbl basis:

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	Six Months Ended
	June 30, 2022			June 30, 2021			$ Change			% Change
Henry Hub		$	6.06		$	2.76		$	3.30		120%
Mont Belvieu			59.43			39.98			19.45		49%
WTI			99.00			61.96			37.04		60%

Refer to Note 4 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding acquisitions.

Commodity Revenue

The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) for the six months ended June 30, 2022 by reflecting the effect of changes in volume and in the underlying prices:

(In thousands)	Natural Gas			NGLs			Oil			Total
Commodity revenue for the six months ended June 30, 2021		$	258,453		$	35,050		$	13,523		$	307,026
Volume increase (decrease)			55,375			29,608			30,399			115,382
Price increase (decrease)			413,324			43,188			34,895			491,407
Net increase (decrease)			468,699			72,796			65,294			606,789
Commodity revenue for the six months ended June 30, 2022		$	727,152		$	107,846		$	78,817		$	913,815

To manage our cash flows in a volatile commodity price environment, we utilize derivative contracts that allow us to fix the per unit sales prices for approximately 90% of our production over the next twelve months. The tables below set forth the commodity hedge impact on commodity revenue, excluding and including cash received for commodity hedge settlements with natural gas on a per Mcf basis and NGLs and oil on a per Bbl basis:

(In thousands, except per unit data)	Six Months Ended June 30, 2022
	Natural Gas						NGLs						Oil						Total Commodity
	Revenue			Realized $			Revenue			Realized $			Revenue			Realized $			Revenue			Realized $
Excluding hedge impact		$	727,152		$	5.71		$	107,846		$	41.46		$	78,817		$	100.28		$	913,815		$	37.12
Commodity hedge impact			(385,186)			(3.03)			(64,654)			(24.85)			(18,891)			(24.04)			(468,731)			(19.04)
Including hedge impact		$	341,966		$	2.68		$	43,192		$	16.61		$	59,926		$	76.24		$	445,084		$	18.08

(In thousands, except per unit data)	Six Months Ended June 30, 2021
	Natural Gas						NGLs						Oil						Total Commodity
	Revenue			Realized $			Revenue			Realized $			Revenue			Realized $			Revenue			Realized $
Excluding hedge impact		$	258,453		$	2.46		$	35,050		$	24.86		$	13,523		$	55.88		$	307,026		$	16.05
Commodity hedge impact			(3,246)			(0.03)			(20,761)			(14.73)			2,058			8.50			(21,949)			(1.15)
Including hedge impact		$	255,207		$	2.43		$	14,289		$	10.13		$	15,581		$	64.38		$	285,077		$	14.90

Refer to Note 12 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding derivative financial instruments.

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Expenses

	Six Months Ended
(In thousands, except per unit data)	June 30, 2022			Per Boe			June 30, 2021			Per Boe			Total Change					Per Boe Change
(In thousands, except per unit data)	June 30, 2022			Per Boe			June 30, 2021			Per Boe			$			%		$			%
LOE(1)		$	81,776		$	3.32		$	52,836		$	2.77		$	28,940		55%		$	0.55		20%
Production taxes(2)			33,878			1.37			9,215			0.48			24,663		268%			0.89		185%
Midstream operating expense(3)			33,156			1.35			29,172			1.52			3,984		14%			(0.17)		(11)%
Transportation expense(4)			57,547			2.34			28,332			1.48			29,215		103%			0.86		58%
Total operating expense		$	206,357		$	8.38		$	119,555		$	6.25		$	86,802		73%		$	2.13		34%
Employees, administrative costs and professional services(5)			36,245			1.47			29,896			1.56			6,349		21%			(0.09)		(6)%
Costs associated with acquisitions(6)			6,935			0.28			6,221			0.32			714		11%			(0.04)		(13)%
Other adjusting costs(7)			67,033			2.72			2,628			0.14			64,405		2451%			2.58		1843%
Non-cash equity compensation(8)			4,069			0.17			3,588			0.19			481		13%			(0.02)		(11)%
Total operating and G&A expense		$	320,639		$	13.02		$	161,888		$	8.46		$	158,751		98%		$	4.56		54%
Depreciation, depletion and amortization			118,480			4.81			71,843			3.75			46,637		65%			1.06		28%
Allowance for credit losses(9)			—			—			602			0.03			(602)		(100)%			(0.03)		(100)%
Total expenses		$	439,119		$	17.83		$	234,333		$	12.24		$	204,786		87%		$	5.59		46%

(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.

(5)

Employees, administrative costs and professional services includes payroll and benefits for our administrative and corporate staff, costs of maintaining administrative and corporate offices, costs of managing our production operations, franchise taxes, public company costs, fees for audit and other professional services and legal compliance.

(6)

We generally incur costs related to the integration of acquisitions, which will vary for each acquisition. For acquisitions considered to be a business combination, these costs include transaction costs directly associated with a successful acquisition transaction. These costs also include costs associated with transition service arrangements where we pay the seller of the acquired entity a fee to handle various G&A functions until we have fully integrated the assets onto our systems. In addition, these costs include costs related to integrating IT systems and consulting and internal workforce costs directly related to integrating acquisitions into our systems.

(7)

Other adjusting costs for the six months ended June 30, 2022 primarily consist of $28 million in contract terminations which will allow the Company to obtain more favorable pricing in the future and $33 million in costs associated with deal breakage and/or sourcing costs for acquisitions. For the six months ended June 30, 2021, other adjusting costs are primarily associated with one-time projects and contemplated financing arrangements. Also included are expenses associated with an unused firm transportation agreement acquired as part of the Carbon Acquisition.

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(8)

Non-cash equity compensation for the six months ended June 30, 2022 and 2021 reflect the expense recognition related to share-based compensation provided to certain key members of the management team.

(9)

Allowance for credit losses consists of the recognition and reversal of credit losses. Refer to Note 13 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding credit losses.

Operating Expense

We experienced increases in per unit operating expense of 34%, or $2.13 per Boe, resulting from:

•

Higher per Boe LOE that rose 20%, or $0.55 per Boe, resulting from increases in costs from the assets acquired in connection with the Central Region and inflationary pressures;

•

Higher per Boe Production taxes that rose 185%, or $0.89 per Boe, primarily attributable to an increase in severance taxes as a result of an increase in unhedged revenue due to higher commodity prices and sold volumes and an increase in property taxes per Boe related to the assets acquired in connection with the Indigo, Blackbeard, Tanos and Tapstone acquisitions given the difference in regulatory environment;

•

Higher per Boe transportation expense related to increases in third-party midstream rates and midstream costs related to the assets acquired in the Central Region given they tend to carry a higher transportation expense profile.

Partially offsetting the per unit increases was a decrease due to:

•

Lower per Boe Midstream operating expense that declined 11%, or $0.17 per Boe. While costs increased due to the growth of our midstream workforce to service the additional midstream capabilities we gained as a result of the 2021 acquisitions, the midstream costs are spread across a larger base of producing assets, including production from the assets acquired in connection with the Indigo, Blackbeard, Tanos and Tapstone acquisitions.

General and Administrative Expense

G&A expense increased due to:

•

From time to time we incur costs associated with potential acquisitions. These costs include deposits, right of first refusals, option agreement costs and other acquisition related payments which can include hedging costs incurred in connection with the potential acquisitions. At times, due to changing macro-economic conditions, commodity price volatility and/or findings observed during our deal diligence efforts, we incur expenses of this nature as breakage and/or deal sourcing fees. In 2021, we paid $25 million in costs associated with a potential acquisition and, due to decisions we made in the first quarter of 2022, we terminated the transaction and wrote off this $25 million in certain acquisition related costs related to these items. During 2022, we also incurred an additional $8 million of costs of this nature. These transactions were classified as other adjusting costs.

•

In February 2022, we paid $28 million to terminate a fixed price purchase contract associated with certain Barnett volumes acquired during the Blackbeard Acquisition. The contract extended through March 2024 and as a result of the termination we will realize more favorable pricing over this period. This transaction also positioned us to refinance these assets as part of the ABS IV financing arrangement. The termination also enhanced our liquidity by eliminating the need for a $20 million letter of credit on our Credit Facility. This transaction was classified in other adjusting costs.

•

An increase in costs associated with acquisitions and other adjusting costs during 2022 when compared to June 30, 2021 was due to the comparatively limited acquisition and other transactional activity incurred in the first half of 2021. During 2022, costs consist of the continued integration of the Central Region, the East Texas Assets Acquisition, as well as other midstream and plugging related transactions and the related diligence for each of these transactions. Expenses incurred in the first half of 2021 are primarily attributable to the completion of the integration of the Carbon and EQT acquisitions which were acquired in May 2020.

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•

Employees, administrative costs and professional services and non-cash equity compensation increased due to investments made in staff and systems to support our enlarged operation. On a per Boe basis, these costs declined 17%, or $0.11 per Boe, as a result of efficiencies gained relative to our increasing production base.

Other Expenses

Depreciation, depletion and amortization (“DD&A”) increased due to:

•

Higher depreciation expense attributable to an increase of property, plant & equipment resulting from acquisitions and maintenance capital expenditures; and

•

Higher depletion expense due to a 29% increase in production attributable to an increased number of producing wells from acquisitions.

Allowance for credit losses decreased due to:

•

The impact on anticipated credit losses on joint interest owner receivables has a direct relationship with pricing and distributions to individual owners. As the pricing environment improved in 2022, the underlying well economics did as well, and as a result, in 2022, we were able to collect on receivables without the need to increase our existing reserves.

Refer to Notes 4, 9, 10 and 12 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding acquisitions, natural gas and oil properties, property, plant and equipment and derivative financial instruments, respectively.

Derivative Financial Instruments

We recorded the following gain (loss) on derivative financial instruments in the Consolidated Statement of Comprehensive Income for the periods presented:

	Six Months Ended
(In thousands)	June 30, 2022			June 30, 2021			$ Change			% Change
Net gain (loss) on commodity derivative settlements(1)		$	(468,731)		$	(21,949)		$	(446,782)		2,036%
Net gain (loss) on interest rate swap(1)			828			(251)			1,079		(100)%
Gain (loss) on foreign currency hedge(1)			—			(1,227)			1,227		(100)%
Total gain (loss) on settled derivative instruments		$	(467,903)		$	(23,427)		$	(444,476)		1,897%
Gain (loss) on fair value adjustments of unsettled financial instruments(2)			(1,205,938)			(371,458)			(834,480)		225%
Total gain (loss) on derivative financial instruments		$	(1,673,841)		$	(394,885)		$	(1,278,956)		324%

(1)

Represents the cash settlement of hedges that settled during the period.

(2)

Represents the change in fair value of financial instruments net of removing the carrying value of hedges that settled during the period.

For the six months ended June 30, 2022, the total loss on derivative financial instruments of $1,674 million increased by $1,279 million compared to a loss of $395 million in 2021. Adjusting our unsettled derivative contracts to their fair values drove a loss of $1,206 million in 2022, an increase of $834 million, as compared to a loss of $371 million in 2021. While this loss certainly reflects the increase in commodity markets in relation to our hedge floor, the magnitude of the loss is amplified due to the increase in the size of our long-dated hedge portfolio, which has increased meaningfully with the issuance of the ABS III, IV and V Notes. The percentage of our long-term future production hedged increases with each additional ABS transaction and can extend through the life of the note.

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While the change in fair value is significant and reflective of higher prices on the forward price curve, we use derivative contracts to insulate our cash flow from commodity price volatility and bolster our ability to pay dividends and scheduled debt repayments.

For the six months ended June 30, 2022, the total cash loss on settled derivative instruments was $468 million, an increase of $444 million when compared to 2021. The loss on settled derivative instruments relates to higher commodity market prices than we secured through our derivative contracts. With dividend payments and scheduled debt principal payments central to our strategy, to protect our downside risk, we routinely hedge at levels that, based on our operating and overhead costs, provide a significant Adjusted EBITDA Margin even if it means forgoing potential price upside.

Refer to Note 12 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding derivative financial instruments.

Gain on Bargain Purchase

We recorded the following gains on bargain purchase in the Consolidated Statement of Comprehensive Income for the periods presented:

	Six Months Ended
(In thousands)	June 30, 2022			June 30, 2021			$ Change			% Change
Gains on bargain purchases		$	1,249		$	—		$	1,249		100%

For the past few years, the E&P segment of the broader energy sector has been in a period of transition and rebalancing, thereby creating opportunities for healthy companies like ours to acquire high quality assets for less than their fair value. We have established a track record of being disciplined in our bidding to acquire assets that meet our strict asset profile and are accretive to our overall corporate value.

The $1.2 million of gains on bargain purchases in the six months ended June 30, 2022 were comprised of gains associated with a midstream acquisition we completed in the Central Region during the six months ended June 30, 2022. Gains on bargain purchases are not recorded for transactions that are accounted for as an acquisition of assets under IFRS 3, Business Combinations (“IFRS 3”). Rather, the consideration paid is allocated to the assets acquired on a relative fair value basis.

Refer to Note 4 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding acquisitions and bargain purchase gains.

Finance Costs

	Six Months Ended
(In thousands)	June 30, 2022			June 30, 2021			$ Change			% Change
Interest expense, net of capitalized and income amounts(1)		$	33,322		$	18,172		$	15,150		83%
Amortization of discount and deferred finance costs			5,797			4,304			1,493		35%
Other			43			36			7		19%
Total finance costs		$	39,162		$	22,512		$	16,650		74%

(1)

Includes payments related to borrowings and leases.

For the six months ended June 30, 2022, interest expense of $33 million increased $15 million compared to $18 million in 2021, primarily due to the increase in borrowings to fund our 2022 acquisitions as well as the incurrence of a full year of interest on borrowings associated with the 2021 acquisitions. Offsetting these increases was a decrease in interest expense for repaid principal of $59 million on the ABS Notes and Term Loan I as these borrowings are repaid monthly due to their amortizing structures.

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As of June 30, 2022 and 2021, total borrowings were $1,381 million and $655 million, respectively. For the period ended June 30, 2022, the weighted average interest rate on borrowings was 5.38% as compared to 4.77% as of June 30, 2021. This increase resulted from a change in the mix of our financing year-over-year attributable to 99% of our borrowings now being in fixed-rate, hedge-protected, amortizing ABS structures as compared to 2021 when we were in a drawn position on our Credit Facility. In May 2022, the Company reaffirmed its borrowing base on the Credit Facility at $300 million. The recent ABS III, ABS IV and ABS V Notes have interest rates of 4.875%, 4.950% and 5.780%, respectively.

Refer to Notes 4, 18 and 19 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding acquisitions, leases and borrowings, respectively.

Taxation

The effective tax rate is calculated on the face of the Statement of Comprehensive Income by dividing the amount of recorded income tax benefit (expense) by the income (loss) before taxation as follows:

	Six Months Ended
(In thousands)	June 30, 2022			June 30, 2021			$ Change			% Change
Income (loss) before taxation		$	(1,230,127)		$	(343,978)		$	(886,149)		258%
Income tax benefit (expense)			294,877			260,021			34,856		13%
Effective tax rate			24.0%			75.6%

The differences between the statutory US federal income tax rate and the effective tax rates are summarized as follows:

	Six Months Ended
	June 30, 2022		June 30, 2021
Expected tax at statutory US federal income tax rate		21.0%		21.0%
State income taxes, net of federal tax benefit		3.0%		5.3%
Federal credits		—%		50.3%
Other, net		—%		(1.0)%
Effective tax rate		24.0%		75.6%

For the six months ended June 30, 2022, we reported a tax benefit of $295 million, an increase of $35 million, compared to a benefit of $260 million in 2021, which was a result of the change in the loss before taxation and a change in the amount of tax credits recognized.

The resulting effective tax rates for the six months ended June 30, 2022 and 2021 were 24.0% and 75.6%, respectively. The effective tax rate for the six months ended June 30, 2021 was primarily impacted by the recognition of the marginal well tax credit available to qualified producers as compared to the six months ended June 30, 2022, where no additional marginal well credits have been recorded. The federal government provides these credits to encourage companies to continue operating lower-volume wells during periods of low prices to maintain the underlying jobs they create and the state and local tax revenues they generate for communities to support schools, social programs, law enforcement and other similar public services. Due to the higher prices experienced in 2022, we did not generate any new marginal well tax credits in the first six months of 2022, whereas we did generate new such credits in the same period of the prior year, which impacted our effective tax rate.

Refer to Note 7 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding taxation.

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Operating Profit, Net Income, EPS and Adjusted EBITDA

	Six Months Ended
(In thousands, except per share and per unit data)	June 30, 2022			June 30, 2021			$ Change			% Change
Operating profit (loss)		$	(1,177,133)		$	(305,668)		$	(871,465)		285%
Net income (loss)			(935,250)			(83,957)			(851,293)		1,014%
Adjusted EBITDA			223,760			151,314			72,446		48%
Earnings (loss) per share–basic and diluted		$	(1.10)		$	(0.11)		$	(0.99)		900%

For the six months ended June 30, 2022, we reported a net loss of $935 million and loss per share of $1.10 compared to a net loss of $84 million and loss per share of $0.11 in 2021, an increase of 1,014% and 900%, respectively. We also reported an operating loss of $1,177 million compared with an operating loss of $306 million for the six months ended June 30, 2022 and 2021, respectively. This year-over-year increase in net loss was primarily attributable to an increase of $834 million in the mark-to-market loss to $1,206 million in 2022 from $371 million in 2021 as discussed above.

Excluding the mark-to-market loss on long-dated derivative valuations, as well as other customary non-cash or non-recurring adjustments, we reported Adjusted EBITDA of $224 million for the six months ended June 30, 2022 compared to $151 million for the six months ended June 30, 2021, representing an increase of 48% driven by our growth through acquisitions.

Refer to Note 8 in the Notes to the Interim Condensed Consolidated Financial Statements for information regarding Adjusted EBITDA.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2021

The following tables set forth our results of operations for the years ended December 31, 2021 and 2020. See the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures” for a reconciliation of the Non-IFRS measures included in the table to the most directly comparable IFRS financial performance measure.

	Year Ended December 31,
	2021			2020			Change			% Change
Net production
Natural gas (MMcf)			234,643			199,667			34,976		18%
NGLs (MBbls)			3,558			2,843			715		25%
Oil (MBbls)			592			417			175		42%
Total production (MBoe)			43,257			36,538			6,719		18%
Average daily production (Boepd)			118,512			99,831			18,681		19%
% Natural gas (Boe basis)			90%			91%
Average realized sales price (excluding impact of derivatives settled in cash)
Natural gas (Mcf)		$	3.49		$	1.72		$	1.77		103%
NGLs (Bbls)			32.53			8.15			24.38		299%
Oil (Bbls)			65.26			36.12			29.14		81%
Total (Boe)		$	22.50		$	10.45		$	12.05		115%
Average realized sales price (including impact of derivatives settled in cash)
Natural gas (Mcf)		$	2.36		$	2.33		$	0.03		1%
NGLs (Bbls)			15.52			13.95			1.57		11%

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	Year Ended December 31,
	2021			2020			Change			% Change
Oil (Bbls)			71.68			52.97			18.71		35%
Total (Boe)		$	15.08		$	14.40		$	0.68		5%
Revenue (in thousands)
Natural gas		$	818,726		$	343,425		$	475,301		138%
NGLs			115,747			23,173			92,574		399%
Oil			38,634			15,064			23,570		156%
Total commodity revenue		$	973,107		$	381,662		$	591,445		155%
Midstream revenue			31,988			25,389			6,599		26%
Other revenue			2,466			1,642			824		50%
Total revenue		$	1,007,561		$	408,693		$	598,868		147%
Gain (loss) on derivative settlements (in thousands)
Natural gas		$	(263,929)		$	121,077		$	(385,006)		(318)%
NGLs			(60,530)			16,498			(77,028)		(467)%
Oil			3,803			7,025			(3,222)		(46)%
Net gain (loss) on commodity derivative settlements(1)		$	(320,656)		$	144,600		$	(465,256)		(322)%
Total Revenue, inclusive of hedges		$	686,905		$	553,293		$	133,612		24%
Per Boe Metrics
Average realized sales price
(including impact of derivatives settled in cash)		$	15.08		$	14.40		$	0.68		5%
Other revenue			0.80			0.74			0.06		8%
LOE			(2.76)			(2.53)			(0.23)		9%
Midstream operating expense			(1.40)			(1.45)			0.05		(3)%
Employees, administrative costs and professional services			(1.31)			(1.29)			(0.02)		9%
Recurring allowance for credit losses			0.10			(0.04)			0.14		(4)%
Production taxes			(0.71)			(0.38)			(0.33)		87%
Transportation expense			(1.86)			(1.24)			(0.62)		50%
Adjusted EBITDA per Boe		$	7.94		$	8.21		$	(0.27)		(3)%
Adjusted EBITDA Margin			50%			54%
Other financial metrics (in thousands)
Adjusted EBITDA		$	343,145		$	300,590		$	42,555		14%
Operating profit (loss)		$	(467,064)		$	(77,568)		$	(389,496)		502%
Net income (loss)		$	(325,206)		$	(23,474)		$	(301,732)		1,285%

(1)

Production, Revenue and Hedging

Total revenue in the year ended December 31, 2021 of $1,008 million increased 147% from $409 million reported for the year ended December 31, 2020, primarily due to a 115% increase in the average realized sales price of our production and 18% higher production volumes. Including commodity hedge settlement

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losses of $321 million and gains of $145 million in 2021 and 2020, respectively, Total Revenue, inclusive of hedges, increased by 24% to $687 million in 2021 from $553 million in 2020.

While higher average realized sales prices in 2021 contributed $25 million in additional Total Revenue, inclusive of hedges, for the year ended December 31, 2021, we will not realize the full impact of the higher commodity price environment until 2022 and 2023 when the increase in our hedged floor prices should begin to increase. The majority of the increase in Total Revenue, inclusive of hedges or $101 million, was driven by added production volumes. We produced approximately 43,257 MBoe in 2021 versus approximately 36,538 MBoe in 2020. The increase in volumes was primarily due to the full integration of the assets acquired in May 2020 in connection with the Carbon and EQT acquisitions and the assets acquired in May, July and August 2021, respectively, in connection with the Indigo, Blackbeard and Tanos acquisitions, as well as approximately one month of production from the assets acquired in December 2021 in connection with the Tapstone Acquisition.

The following table summarizes average commodity prices for the periods presented with Henry Hub on a per Mcf basis and Mont Belvieu and WTI on a per Bbl basis:

	Year Ended December 31,
	2021			2020			$ Change			% Change
Henry Hub		$	3.84		$	2.08		$	1.76		85%
Mont Belvieu			47.49			21.85			25.64		117%
WTI			68.26			39.61			28.65		72%

Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information regarding acquisitions.

Commodity Revenue

The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) for the year ended December 31, 2021 by reflecting the effect of changes in volume and in the underlying prices (in thousands):

(In thousands)	Natural Gas			NGLs			Oil			Total
Commodity revenue for the year ended December 31, 2020		$	343,425		$	23,173		$	15,064		$	381,662
Volume increase (decrease)			60,159			5,827			6,321			72,307
Price increase (decrease)			415,142			86,747			17,249			519,138
Net increase (decrease)			475,301			92,574			23,570			591,445
Commodity revenue for the year ended December 31, 2021		$	818,726		$	115,747		$	38,634		$	973,107

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	Year Ended December 31, 2021
	Natural Gas						��	NGLs						Oil						Total Commodity
	Revenue			Realized $				Revenue			Realized $			Revenue			Realized $			Revenue			Realized $
	(in thousands except per unit data)
Excluding hedge impact		$	818,726		$	3.49			$	115,747		$	32.53		$	38,634		$	65.26		$	973,107		$	22.50
Commodity hedge impact			(263,929)			(1.13)				(60,530)			(17.01)			3,803			6.42			(320,656)			(7.42)
Including hedge impact		$	554,797		$	2.36			$	55,217		$	15.52		$	42,437		$	71.68		$	652,451		$	15.08

	Year Ended December 31, 2020
	Natural Gas						NGLs						Oil						Total Commodity
	Revenue			Realized $			Revenue			Realized $			Revenue			Realized $			Revenue			Realized $
	(in thousands except per unit data)
Excluding hedge impact		$	343,425		$	1.72		$	23,173		$	8.15		$	15,064		$	36.12		$	381,662		$	10.45
Commodity hedge impact			121,077			0.61			16,498			5.80			7,025			16.85			144,600			3.95
Including hedge impact		$	464,502		$	2.33		$	39,671		$	13.95		$	22,089		$	52.97		$	526,262		$	14.40

Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional information regarding derivative financial instruments.

Expenses

(In thousands, except per unit data)	Year Ended December 31,
													Total Change					Per Boe Change
	2021			Per Boe			2020			Per Boe			$			%		$			%
LOE(1)		$	119,594		$	2.76		$	92,288		$	2.53		$	27,306		30%		$	0.23		9%
Production taxes(2)			30,518			0.71			13,705			0.38			16,813		123%			0.33		87%
Midstream operating expense(3)			60,481			1.40			52,815			1.45			7,666		15%			(0.05)		(3)%
Transportation expense(4)			80,620			1.86			45,155			1.24			35,465		79%			0.62		50%
Total operating expense		$	291,213		$	6.73		$	203,963		$	5.58		$	87,250		43%		$	1.15		21%
Employees, administrative costs and professional services(5)			56,812			1.31			47,181			1.29			9,631		20%			0.02		2%
Costs associated with acquisitions(6)			31,335			0.72			10,465			0.29			20,870		199%			0.43		148%
Other adjusting costs(7)			6,779			0.16			14,581			0.40			(7,802)		(54)%			(0.24)		(60)%
Non-cash equity compensation(8)			7,400			0.17			5,007			0.14			2,393		48%			0.03		21%
Total operating and G&A expense		$	393,539		$	9.09		$	281,197		$	7.70		$	112,342		40%		$	1.39		18%
Depreciation, depletion and amortization			167,644			3.88			117,290			3.21			50,354		43%			0.67		21%

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(In thousands, except per unit data)	Year Ended December 31,
													Total Change					Per Boe Change
	2021			Per Boe			2020			Per Boe			$			%		$			%
Allowance for credit losses(9)			(4,265)			(0.10)			8,490			0.24			(12,755)		(150)%			(0.34)		(142)%
Total expenses		$	556,918		$	12.87		$	406,977		$	11.14		$	149,941		37%		$	1.73		16%

(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.

(5)

(6)

We generally incur costs related to the integration of acquisitions, which will vary for each acquisition. For acquisitions considered to be a business combination, these costs include transaction costs directly associated with a successful acquisition transaction. These costs also include costs associated with transition service arrangements with acquired entities where we pay the acquired entity a fee to handle various G&A functions until we have fully integrated the assets onto our system. In addition, these costs include costs related to integrating IT systems and consulting and internal workforce costs directly related to integrating acquisitions into our systems.

(7)

Other adjusting costs for 2021 are primarily associated with one-time projects and contemplated financing arrangements. Also included are expenses associated with an unused firm transportation agreement acquired as part of the Carbon Acquisition. For 2020, other adjusting costs are associated with legal and professional fees related to the uplisting of our equity securities to the Premium Segment of the Main Market of the LSE.

(8)

Non-cash equity compensation in 2021 and 2020 reflect the expense recognition related to share-based compensation provided to certain key members of the management team.

(9)

Allowance for credit losses consists of the recognition and reversal of credit losses. Refer to Notes 14 and 25 in the Notes to the Consolidated Financial Statements for additional information regarding credit losses.

Operating Expense

We experienced increases in per unit operating expense of 21%, or $1.15 per Boe, during the year ended December 31, 2021 compared to 2020 primarily as a result of:

•

Higher per Boe LOE that increased 9%, or $0.23 per Boe, primarily as a result of increases in costs from the assets acquired in connection with the Indigo, Blackbeard, Tanos and Tapstone acquisitions;

•

Higher per Boe production taxes that increased 87%, or $0.33 per Boe, primarily attributable to an increase in severance taxes as a result of an increase in unhedged revenue due to higher commodity prices and sold volumes and an increase in property taxes related to the assets acquired in connection with the Indigo, Blackbeard, Tanos and Tapstone acquisitions; and

•

Higher per Boe transportation expense related to increases in third-party midstream rates and midstream costs related to the assets acquired in connection with the Indigo, Blackbeard, Tanos and Tapstone acquisitions.

Partially offsetting the per unit total operating expense increase was lower per Boe midstream operating expense that declined 3%, or $0.05 per Boe. While costs increased due to growth of our midstream workforce to service the additional midstream capabilities we gained as a result of the Carbon and EQT acquisitions in May 2020, the midstream costs are spread across a larger base of producing assets including production from the assets acquired in connection with the Indigo, Blackbeard, Tanos and Tapstone acquisitions.

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General and Administrative Expense

G&A expense increased due to:

•

Investments made in staff and systems to support our enlarged operations; and

•

An increase in acquisition cost as a result of increased activity when compared to the prior year. During 2021, we incurred costs related to the integration of the assets acquired in May, July, August and December 2021, respectively, in connection with the Indigo, Blackbeard, Tanos and Tapstone acquisitions.

Other Expenses

Depreciation, depletion and amortization (“DD&A”) increased due to:

•

Higher depreciation expense attributable to an increase in property, plant and equipment resulting from acquisitions and maintenance capital expenditures; and

•

Higher depletion expense due to an 18% increase in production attributable to an increased number of producing wells from acquisitions.

Allowance for credit losses decreased due to the impact on anticipated credit losses on joint interest owner receivables of pricing due to the direct relationship with distributions to individual owners. As the pricing environment improved in 2021, the underlying well economics did as well, and as a result, in 2021, we were able to collect on many of our previously anticipated credit losses and improve the outlook of future collection.

Refer to Notes 5, 10, 11 and 13 in the Notes to the Consolidated Financial Statements for additional information regarding acquisitions, natural gas and oil properties, property, plant and equipment and derivative financial instruments, respectively.

Derivative Financial Instruments

We recorded the following gain (loss) on derivative financial instruments in the Consolidated Statement of Comprehensive Income for the periods presented:

	Year Ended December 31,
	2021			2020			$ Change			% Change
	(in thousands)
Net gain (loss) on commodity derivatives settlements(1)		$	(320,656)		$	144,600		$	(465,256)		(322)%
Net gain (loss) on interest rate swap(1)			(530)			(202)			(328)		162%
Gain (loss) on foreign currency hedges(1)			(1,227)			—			(1,227)		(100)%
Total gain (loss) on settled derivative instruments		$	(322,413)		$	144,398		$	(466,811)		(323)%
Gain (loss) on fair value adjustments of unsettled financial instruments(2)			(652,465)			(238,795)			(413,670)		173%
Total gain (loss) on derivative financial instruments		$	(974,878)		$	(94,397)		$	(880,481)		933%

(1)

Represents the cash settlement of hedges that settled during the period.

(2)

Represents the change in fair value of financial instruments net of removing the carrying value of hedges that settled during the period.

For the year ended December 31, 2021, the total loss on derivative financial instruments of $975 million increased by $880 million compared to a loss of $94 million in 2020. Adjusting our unsettled derivative contracts to their fair values drove a loss of $652 million in 2021, an increase of $414 million, when compared to a loss of $239 million in 2020.

For the year ended December 31, 2021, the total cash loss on settled derivative instruments was $322 million, a decrease of $467 million when compared to 2020. The loss on settled derivative instruments

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relates to higher commodity market prices than we secured through our derivative contracts. With dividend payments and scheduled debt principal payments central to our strategy, to protect our downside risk we routinely hedge at levels that, based on our operating and overhead costs, provide a significant Adjusted EBITDA Margin even if it means forgoing potential price upside.

Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional information regarding derivative financial instruments.

Gains on Bargain Purchases

We recorded the following gains on bargain purchases in the Consolidated Statement of Comprehensive Income for the periods presented:

	Year Ended December 31,
	2021			2020			$ Change			% Change
	(in thousands)
Gains on bargain purchases		$	58,072		$	17,172		$	40,900		238%

For the past few years, the E&P segment of the broader energy sector has been in a period of transition and rebalancing, thereby creating opportunities for financially healthy companies like ours to acquire high quality assets for less than their fair value. We have established a track record of being disciplined in our bidding to acquire assets that meet our strict asset profile and are accretive to our overall corporate value.

The $58 million of gains on bargain purchases in 2021 were comprised of $32 million and $26 million of gains associated with the Tanos and Tapstone acquisitions, respectively. The $17 million of gains on bargain purchases in 2020 were associated with the Carbon Acquisition. Gains on bargain purchases are not recorded for transactions that are accounted for as an acquisition of assets under IFRS 3. Rather, the consideration paid is allocated to the assets acquired on a relative fair value basis.

Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information regarding acquisitions and bargain purchase gains.

Finance Costs

	Year Ended December 31,
	2021			2020			$ Change			% Change
	(in thousands)
Interest expense, net of capitalized and income amounts(1)		$	42,370		$	34,391		$	7,979		23%
Amortization of discount and deferred finance costs			8,191			8,334			(143)		(2)%
Other			67			602			(535)		(89)%
Total finance costs		$	50,628		$	43,327		$	7,301		17%

(1)

Includes payments related to borrowings and leases.

For the year ended December 31, 2021, interest expense of $42 million increased by $8 million compared to $34 million in 2020, primarily due to the increase in borrowings to fund our 2021 acquisitions as well as the incurrence of a full year of interest on borrowings associated with the 2020 acquisitions. Offsetting these increases was a decrease in interest expense for repaid principal of $62 million on the ABS Notes (as defined herein) and Term Loan as these borrowings are repaid monthly due to their amortizing structures.

As of December 31, 2021 and 2020, total borrowings were $1,042 million and $746 million, respectively. For the period ended December 31, 2021, the weighted average interest rate on borrowings was 4.33% as compared to 4.70% as of December 31, 2020. This decrease resulted from a change in the mix of our financing year-over-year attributable to a larger portion of our borrowings on the Credit Facility, which has a lower interest rate than our other debt sources, in 2021 compared to 2020. In February 2022, the Credit Facility

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borrowing base was downsized from $825 million to $500 million in connection with the issuance of the ABS III Notes and ABS IV Notes (each as defined herein), that have interest rates of 4.88% and 4.95%, respectively.

Refer to Notes 5, 20 and 21 in the Notes to the Consolidated Financial Statements for additional information regarding acquisitions, leases and borrowings, respectively.

Taxation

	Year Ended December 31,
	2021			2020			$ Change			% Change
	(in thousands)
Income (loss) before taxation		$	(550,900)		$	(136,740)		$	(414,160)		303%
Income tax benefit (expense)			225,694			113,266			112,428		99%
Effective tax rate			41.0%			82.8%

The differences between the statutory U.S. federal income tax rate and the effective tax rates are summarized as follows:

	Year Ended December 31,
	2021		2020
Expected tax at statutory U.S. federal income tax rate		21.0%		21.0%
State income taxes, net of federal tax benefit		4.4%		5.4%
Federal credits		15.4%		58.8%
Other, net		0.2%		(2.4)%
Effective tax rate		41.0%		82.8%

For the year ended December 31, 2021, we reported a tax benefit of $226 million, an increase of $112 million, compared to a benefit of $113 million in 2020, which was a result of the change in the loss before taxation and a change in the amount of tax credits generated relative to the pre-tax loss. The resulting effective tax rates for the years ended December 31, 2021 and 2020 were 41.0% and 82.8%, respectively. The effective tax rate is primarily impacted by recognition of the marginal well tax credit available to qualified producers. The federal government provides these credits to encourage companies to continue operating lower-volume wells during periods of low prices to maintain the underlying jobs they create and the state and local tax revenues they generate for communities to support schools, social programs, law enforcement and other similar public services. The impact of the marginal well credit on our effective rate is attributable to the larger pre-tax loss in 2021 as compared to 2020.

Refer to Note 8 in the Notes to the Consolidated Financial Statements for additional information regarding taxation.

Operating Profit, Net Income, EPS, and Adjusted EBITDA

	Year Ended December 31,
	2021			2020			$ Change			% Change
	(in thousands except per share and unit data)
Operating profit (loss)		$	(467,064)		$	(77,568)		$	(389,496)		502%
Net income (loss)			(325,206)			(23,474)			(301,732)		1,285%
Adjusted EBITDA			343,145			300,590			42,555		14%
Earnings (loss) per share−basic and diluted		$	(0.41)		$	(0.03)		$	(0.38)		1,267%

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For the year ended December 31, 2021, we reported a net loss of $325 million and loss per share (basic and diluted) of $0.41 compared to net loss of $23 million and loss per share (basic and diluted) of $0.03 in 2020, an increase of 1,285% and 1,267%, respectively. We also reported an operating loss of $467 million compared with an operating loss of $78 million for the years ended December 31, 2021 and 2020, respectively. This year-over-year increase in net loss was primarily attributable to an increase of $414 million in the mark-to-market loss to $652 million in 2021 from $239 million in 2020, discussed above.

Excluding the mark-to-market loss on long-dated derivative valuations, as well as other customary non-cash or non-recurring adjustments, we reported Adjusted EBITDA of $343 million compared to $301 million in 2020, representing an increase of 14% driven from our growth through acquisitions.

See the subsection titled “Prospectus Summary—Other Financial Data and Key Ratios—Non-IFRS Financial Measures” for a reconciliation of the Non-IFRS measures to the most directly comparable IFRS financial performance measure.

Liquidity and Capital Resources

Overview

Our principal sources of liquidity have historically been cash generated from operations and available borrowings under our Credit Facility. To minimize interest expense, we use our excess cash flow to reduce borrowings on our Credit Facility and as a result have historically carried little cash on our Consolidated Statement of Financial Position as evidenced by our $13 million and $1 million in cash and cash equivalents for the years ended December 31, 2021 and 2020, respectively. In 2022, however, we completed three ABS financing transactions and generated sufficient liquidity to repay previous borrowings on our Credit Facility and, as a result, we have $187 million in cash and cash equivalents as of June 30, 2022 and hold 99% of our debt in amortizing structures, with clear line of sight to its hedge-protected repayment by December 2030.

When we acquire assets to grow, we complement our Credit Facility with asset-backed debt securitized by certain natural gas and oil assets, which are long-term, fixed-rate, fully-amortizing debt structures that better match the long-life nature of our assets. These structures afford us low borrowing rates and also provide a visible path for reducing leverage as we make scheduled principal payments. For larger value-adding acquisitions, and to ensure we maintain a leverage profile that we believe is appropriate for the type of assets we acquire, we also raise proceeds through secondary equity offerings from time to time.

We monitor our working capital to ensure that the levels remain adequate to operate the business with excess cash primarily utilized for the repayment of debt or dividends to shareholders. In addition to working capital management, we have a disciplined approach to managing operating costs and allocating capital resources, ensuring that we are generating returns on our capital investments to support the strategic initiatives in our business operations. With respect to our current costs of capital, our ABS Notes are fixed-rate instruments (subject to adjustment pursuant to the sustainability-linked features described under the subsection titled “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt”) and as of June 30, 2022 we did not have amounts outstanding on our Credit Facility. Nevertheless, rising interest rates would increase the floating rate of interest applicable to future borrowings under our Credit Facility and may 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.

Capital expenditures were $45 million for the six months ended June 30, 2022 compared to $16 million for the six months ended June 30, 2021 and were $50 million for the year ended December 31, 2021 compared to $22 million for the year ended December 31, 2020. This increase in capital expenditures was primarily driven by our growth through acquisitions year-over-year and during 2022 the completion of wells that were under development by Tapstone at the time we closed the Tapstone Acquisition, respectively. There were no material commitments for capital expenditures as of or subsequent to June 30, 2022. We expect to meet our capital expenditure needs for the foreseeable future from our operating cash flow and our existing cash and cash equivalents. Our future capital requirements will depend on several factors, including our growth rate, future acquisitions and the expansion of our employee headcount, among other things.

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With respect to our other known current obligations, we believe that our sources of liquidity and capital resources will be sufficient to meet our existing business needs for at least the next 12 months. However, our ability to satisfy our working capital requirements, debt service obligations and planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the natural gas and oil industries and other financial and business factors, some of which are beyond our control. Refer to Note 13 in the Notes to the Consolidated Financial Statements, and Note 12 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding our hedging program to mitigate the risk associated with future cash flow generation.

The table below represents our liquidity position on a historical basis as of as of June 30, 2022, and the years ended December 31, 2021 and 2020.

(In thousands)	As of June 30, 2022			As of December 31, 2021			As of December 31, 2020
Cash		$	187,342		$	12,558		$	1,379
Available borrowings under the Credit Facility			281,982(1)			222,263(2)			201,556(3)
Liquidity		$	469,324		$	234,821		$	202,935

(1)

Represents available borrowings under the Credit Facility of $300 million as of June 30, 2022 less outstanding letters of credit of $18 million as of such date.

(2)

Represents available borrowings under the Credit Facility of $254 million as of December 31, 2021 less outstanding letters of credit of $32 million as of such date.

(3)

Represents available borrowings under the Credit Facility of $212 million as of December 31, 2020 less outstanding letters of credit of $10 million as of December 31, 2020.

Debt

Our net debt consisted of the following as of the periods and reporting dates presented:

	As of			Year Ended December 31,
(In thousands)	June 30, 2022			2021			2020
Credit Facility			—			(570,600)			(213,400)
ABS I Notes			(141,347)			(155,266)			(180,426)
ABS II Notes			(158,475)			(169,320)			(191,125)
ABS III Notes			(349,477)			—			—
ABS IV Notes			(149,900)			—			—
ABS V Notes			(445,000)			—			—
Term Loan I			(128,595)			(137,099)			(156,805
Other			(8,623)			(9,380)			(4,730)
Total Debt		$	(1,381,417)		$	(1,041,665)		$	(746,486)
Cash		$	187,342		$	12,558		$	1,379
Restricted cash			44,206			19,102			20,350
Net Debt		$	(1,149,869)		$	(1,010,005)		$	(724,757)

Credit Facility

We maintain the Credit Facility with a lending syndicate, the borrowing base for which is redetermined on a semi-annual or as needed basis. The borrowing base is primarily a function of the value of the natural gas and oil properties that collateralize the lending arrangement and will fluctuate with changes in collateral, which may occur as a result of acquisitions or through the establishment of ABS, term loan, or other lending structures that result in changes to the Credit Facility collateral base.

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In May 2022, the Company reaffirmed its borrowing base on the Credit Facility at $300 million and maintained the previous maturity date of August 2025. The Credit Facility has an interest rate of SOFR plus an additional spread that ranges from 2.75% to 3.75% based on utilization. Interest payments on the Credit Facility are paid on a monthly basis. The next redetermination is expected to occur in October 2022. Available borrowings under the Credit Facility were $282 million as of June 30, 2022 which considers the impact of $18 million in letters of credit issued to certain vendors.

The Credit Facility contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records; financial reporting and notification; compliance with laws; maintenance of properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, making certain debt payments and amendments, restrictive agreements, investments, restricted payments and hedging. It also requires the Company to maintain a ratio of total debt to EBITDAX of not more than 3.25 to 1.00 and a ratio of current assets (with certain adjustments) to current liabilities of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. The fair value of the Credit Facility approximates the carrying value as of June 30, 2022.

In August 2022, we amended and restated the credit agreement governing our Credit Facility by entering into the A&R Revolving Credit Facility. The amendment enhances the alignment with our stated ESG initiatives by including sustainability performance targets (“SPTs”) similar to those included in the ABS V Notes as described in this prospectus, extends the maturity of our Credit Facility to August 2026, removes DGOC as a credit party from the Credit Facility, reaffirms the borrowing base of $300 million and included no other material changes to pricing or terms. Further, as a result of the amendment, the covenant structure associated with the A&R Revolving Credit Facility will now be associated with solely DP RBL CO LLC, the borrower, a subsidiary of DGOC, the existing borrower.

The A&R Credit Facility contains three SPTs which, depending on our performance thereof, may result in adjustments to the applicable margin with respect to borrowings thereunder:

•

GHG Emissions Intensity: our consolidated Scope 1 emissions and Scope 2 emissions, each measured as MtCO2e per MMcfe;

•

Plugged Well Performance: the number of wells we successfully plug during any fiscal year;

•

TRIR Performance: the arithmetic average of the two preceding fiscal years and current period total recordable injury rate computed as the Total Number of Recordable Cases (as defined by the Occupational Safety and Health Administration) multiplied by 200,000 and then divided by total hours worked by all employees during any fiscal year.

The goals set by the A&R Credit Facility for each of these categories are aspirational and represent higher thresholds than we have publicly set for ourselves. The economic repercussions of achieving or failing to achieve these thresholds, however, are relatively minor, ranging from subtracting five basis points to adding five basis points to the applicable margin level in any given fiscal year.

An independent third party assurance provider will be required to certify our performance of the SPTs. Though we are not required to do so, we intend to disclose this certification on an annual basis in our semi-annual report or annual report, as determined by the timing of such certification, along with an overall ESG update.

Term Loan I

In May 2020, we acquired DP Bluegrass LLC, a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to enter into a securitized financing agreement for $160 million, which was structured as a secured term loan (the “Term Loan I”). We issued the Term Loan I at a 1% discount, and used the proceeds of $158 million to fund the Carbon and EQT acquisitions.

The Term Loan I is secured by certain producing assets acquired in connection with the Carbon and EQT acquisitions, discussed in Note 5 in the Notes to the Consolidated Financial Statements.

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ended June 30, 2022 and 2021 and during the years ended December 31, 2021 and 2020, we incurred $4 million, $5 million, $10 million and $6 million in interest related to the Term Loan I, respectively. The fair value of the Term Loan I approximates the carrying value as of June 30, 2022.

ABS I Notes

In November 2019, we formed Diversified ABS LLC (“ABS I”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to issue BBB- rated asset-backed securities in an aggregate principal amount of $200 million at par (the “ABS I Notes”). The ABS I Notes are secured by certain of our upstream producing Appalachian assets. Natural gas production associated with these assets was hedged at 85% at the close of the agreement with long-term derivative contracts.

Interest and principal payments on the ABS I Notes are payable on a monthly basis. During the six months ended June 30, 2022 and 2021 and during the years ended December 31, 2021 and 2020, we incurred $4 million, $4 million, $8 million and $10 million of interest related to the ABS I Notes, respectively. The legal final maturity date is January 2037 with an amortizing maturity of December 2029. The ABS I Notes accrue interest at a stated 5.00% rate per annum. The fair value of the ABS I Notes approximates the carrying value as of June 30, 2022. In the event that ABS I has cash flow in excess of the required payments, ABS I is required to pay between 25% and 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with the Company. In particular, (a) with respect to any payment date prior to March 1, 2030, (i) if the debt service coverage ratio (the “DSCR”) (as described in the Indenture, dated November 13, 2019, by and between Diversified ABS LLC, as issuer, and UMB Bank, N.A., as indenture trustee and securities intermediary, as amended by the First Amendment to Indenture, dated February 13, 2020, the “ABS I Indenture”) as of such payment date is greater than or equal to 1.25 to 1.00, then 25%, (ii) if the DSCR as of such payment date is less than 1.25 to 1.00 but greater than or equal to 1.15 to 1.00, then 50%, and (iii) if the DSCR as of such payment date is less than 1.15 to 1.00, the production tracking rate for ABS I (as described in the ABS I Indenture) is less than 80%, or the loan to value ratio is greater than 85%, then 100%, and (b) with respect to any payment date on or after March 1, 2030, 100%.

ABS II Notes

In April 2020, we formed Diversified ABS Phase II LLC (“ABS II”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to issue BBB- rated asset-backed securities in an aggregate principal amount of $200 million at par (the “ABS II Notes”). The ABS II Notes were issued at a 2.775% discount. The Company used the proceeds of $184 million, net of discount, capital reserve requirement and debt issuance costs to pay down its Credit Facility.

The ABS II Notes are secured by certain of our upstream producing Appalachian assets. Natural gas production associated with these assets was hedged at 85% at the close of the agreement with long-term derivative contracts.

The ABS II Notes accrue interest at a stated 5.25% rate per annum and have a maturity date of July 2037 with an amortizing maturity of September 2028. Interest and principal payments on the ABS II Notes are payable on a monthly basis. During the six months ended June 30, 2021 and 2021 and the years ended December 31, 2021 and 2020, we incurred $5 million, $5 million, $11 million and $8 million in interest related to the ABS II Notes, respectively, which is recognized under the effective interest rate method. The fair value of the ABS II Notes approximates the carrying value as of June 30, 2022. In the event that ABS II has cash flow in excess of the required payments, ABS II is required to pay between 50% and 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with the Company. In particular, (a) (i) if the DSCR (as described in the Indenture, dated April 9, 2020, by and between Diversified ABS Phase II LLC, as issuer, and UMB Bank, N.A., as indenture trustee and securities intermediary, the “ABS II Indenture”) as of any payment date is less than 1.15 to 1.00, then 100%, (ii) if the DSCR as of such payment date is greater than or equal to 1.15 to 1.00 and less than 1.25 to 1.00, then 50%, or (iii) if the DSCR as of such payment date is greater than or equal to 1.25 to 1.00, then 0%; (b) if the production tracking rate for ABS II (as described in the ABS II Indenture) is less than 80.0%, then 100%, else 0%; (c) if the loan-to-value ratio (“LTV”) as of such payment date is greater than 65.0%, then 100%, else 0%; (d) with respect to any payment date after July 1, 2024 and

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prior to July 1, 2025, if LTV is greater than 40.0% and ABS II has executed hedging agreements for a minimum period of 30 months starting July 2026 covering production volumes of at least 85% but no more than 95% (the “Extended Hedging Condition”), then 50%, else 0%; (e) with respect to any payment date after July 1, 2025 and prior to October 1, 2025, if LTV is greater than 40.0% or ABS II has not satisfied the Extended Hedging Condition, then 50%, else 0%; and (f) with respect to any payment date after October 1, 2025, if LTV is greater than 40.0% or ABS II has not satisfied the Extended Hedging Condition, then 100%, else 0%.

ABS III Notes

In February 2022, we formed Diversified ABS III LLC (“ABS III”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to issue BBB rated asset-backed securities in an aggregate principal amount of $365 million at par (the “ABS III Notes”). The ABS III Notes are secured by certain of our upstream producing, as well as certain midstream, Appalachian assets.

The ABS III Notes accrue interest at a stated 4.875% rate per annum and have a final maturity date of April 2039 with an amortizing maturity of November 2030. Interest and principal payments on the ABS III Notes are payable on a monthly basis. During the six months ended June 30, 2022, we incurred $7 million in interest related to the ABS III Notes, which is recognized under the effective interest rate method. In the event that ABS III has cash flow in excess of the required payments, ABS III is required to pay between 50% and 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with the Company. In particular, (a) (i) if the DSCR (as described in the Indenture, dated February 4, 2022, among Diversified ABS Phase III LLC, as issuer, the guarantors named therein and UMB Bank, N.A., as indenture trustee and securities intermediary, the “ABS III Indenture”) as of any payment date is greater than or equal to 1.25 to 1.00, then 0%, (ii) if the DSCR as of such payment date is less than 1.25 to 1.00 but greater than or equal to 1.15 to 1.00, then 50%, and (iii) if the DSCR as of such Payment Date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS III (as described in the ABS III Indenture) is less than 80%, then 100%, else 0%; and (c) if the LTV for ABS III is greater than 65%, then 100%, else 0%.

In addition, in connection with the issuance of the ABS III Notes, we retained an independent international provider of ESG research and services to provide and maintain a “sustainability score” with respect to Diversified Energy Company plc and to the extent such score is below a minimum threshold established at the time of issue of the ABS III Notes, the interest payable with respect to the subsequent interest accrual period will increase by five basis points. This score is not dependent on our meeting or exceeding any sustainability performance metrics but rather an overall assessment of our corporate ESG profile. Further, this score is not dependent on the use of proceeds of the ABS III Notes and there were no such restrictions on the use of proceeds other than pursuant to the terms of our Credit Facility. We inform the ABS III noteholders in monthly noteholder statements as to any change in interest rate payable on the ABS III Notes as a result of the change in this sustainability score. While we are not required to publicly release this score, we will provide the score as of the date of our semi-annual report or annual report, as determined by the timing of such updated score, along with the weighted average interest rate paid on the ABS III Notes as a result of any such five basis point change in interest rate.

ABS IV Notes

In February 2022, we formed Diversified ABS IV LLC (“ABS IV”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to issue BBB rated asset-backed securities in an aggregate principal amount of $160 million at par (the “ABS IV Notes”). The ABS IV Notes are secured by a portion of the upstream producing assets acquired in connection with the Blackbeard Acquisition.

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DSCR as of any payment date is greater than or equal to 1.25 to 1.00, then 0%, (ii) if the DSCR (as described in the Indenture, dated February 23, 2022, by and between Diversified ABS Phase IV LLC, as issuer, and UMB Bank, N.A., as indenture trustee and securities intermediary, the “ABS IV Indenture”) as of such payment date is less than 1.25 to 1.00 but greater than or equal to 1.15 to 1.00, then 50%, and (iii) if the DSCR as of such Payment Date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS IV (as described in the ABS IV Indenture) is less than 80%, then 100%, else 0%; and (c) if the LTV for ABS IV is greater than 65%, then 100%, else 0%.

In addition, in connection with the issuance of the ABS IV Notes, we retained an independent international provider of ESG research and services to provide and maintain a “sustainability score” with respect to Diversified Energy Company plc and to the extent such score is below a minimum threshold established at the time of issue of the ABS III Notes, the interest payable with respect to the subsequent interest accrual period will increase by five basis points. This score is not dependent on our meeting or exceeding any sustainability performance metrics but rather an overall assessment of our corporate ESG profile. Further, this score is not dependent on the use of proceeds of the ABS IV Notes and there were no such restrictions on the use of proceeds other than pursuant to the terms of our Credit Facility. We inform the ABS IV noteholders in monthly noteholder statements as to any change in interest rate payable on the ABS IV Notes as a result of the change in this sustainability score. While we are not required to publicly release this score, we will provide the score as of the date of our semi-annual report or annual report, as determined by the timing of such updated score, along with the weighted average interest rate paid on the ABS IV Notes as a result of any such five basis point change in interest rate.

ABS V Notes

In May 2022, the Company formed Diversified ABS V LLC (“ABS V”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to issue BBB rated asset-backed securities in an aggregate principal amount of $445 million at par (the “ABS V Notes” and, together with the ABS I Notes, the ABS II Notes, the ABS III Notes and the ABS IV Notes, the “ABS Notes”).The ABS V Notes are secured by a majority of the Company’s remaining upstream assets in Appalachia that were not securitized by previous ABS transactions.

The ABS V Notes accrue interest at a stated 5.78% rate per annum and have a final maturity date of May 2039 with an amortizing maturity of December 2030. Interest and principal payments on the ABS V Notes are payable on a monthly basis. During the six months ended June 30, 2022, we incurred $2 million in interest related to the ABS V Notes, which is recognized under the effective interest rate method. Based on whether certain performance metrics are achieved, ABS V could be required to apply 50% to 100% of any excess cash flow to make additional principal payments. In particular, (a) (i) if the DSCR as of any payment date is greater than or equal to 1.25 to 1.00, then 0%, (ii) if the DSCR as of such payment date is less than 1.25 to 1.00 but greater than or equal to 1.15 to 1.00, then 50%, and (iii) if the DSCR (as described in the Indenture, dated May 27, 2022, among Diversified ABS Phase V LLC, as issuer, Diversified ABS V Upstream LLC, as guarantor and UMB Bank, N.A., as indenture trustee and securities intermediary, the “ABS V Indenture”) as of such payment date is less than 1.15 to 1.00, then 100%; (b) if the production tracking rate for ABS V (as described in the ABS V Indenture) is less than 80%, then 100%, else 0%; and (c) if the LTV for ABS V is greater than 65%, then 100%, else 0%.

In addition, a “second party opinion provider” certified the terms of the ABS V Notes as being aligned with the framework for sustainability-linked bonds of the International Capital Markets Association (“ICMA”), applicable to bond instruments for which the financial and/or structural characteristics vary depending on whether predefined ESG objectives—or SPTs—are achieved. The framework has five key components (1) the selection of key performance indicators (“KPIs”), (2) the calibration of SPTs, (3) variation of bond characteristics depending on whether the KPIs meet the SPTs, (4) regular reporting of the status of the KPIs and whether SPTs have been met and (5) independent verification of SPT performance by an external reviewer such as an auditor or environmental consultant. Unlike the ICMA’s framework for green bonds, its framework for sustainability-linked bonds do not require a specific use of proceeds.

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Scope 1 methane emissions intensity to 1.12 MT CO2e/MMcfe. For each of these SPTs that we fail to meet, or have certified by an external verifier that we have met, by April 28, 2027, the interest rate payable with respect to the ABS V Notes will be increased by 25 basis points. In each case, an independent third party assurance provider will be required to certify our performance of the above SPTs by the applicable deadlines. Though we are not required to do so, we intend to disclose this certification on an annual basis in our semi-annual report or annual report, as determined by the timing of such certification, along with an overall ESG update.

Asset Retirement Obligations

We continue to be proactive and innovative with respect to asset retirement. In 2017, after our LSE IPO, we began to meet with state officials to develop a long-term plan to retire our growing portfolio of long-life wells. Collaborating with the appropriate regulators, we designed our retirement activities to be equitable for all stakeholders with an emphasis on the environment.

During the six months ended June 30, 2022 we continued to engage in an active dialogue with our states’ legislative and regulatory bodies to collaborate on best practices for the natural gas and oil industry. In doing so we accomplished the following:

•

Expanded plugging operations to nine rigs through the successful acquisitions of two plugging companies. These acquisitions enhance our ability to comfortably achieve our goal of plugging 200 wells per year by 2023;

•

Retired 90 wells at an average cost of approximately $21 thousand per well as compared to the calendar year 2021 average annual cost of approximately $23 thousand per well; and

•

Subsequent to June 30, 2022, we further enhanced our plugging operations through the successful acquisition of an additional plugging company, increasing our rig count to 15.

This growth in our plugging operations provides us with the ability to further integrate our plugging operations and generate cost efficiencies across a broader footprint. It will also provide us with the ability to generate additional third-party revenues by providing a suite of services to other production companies which can be utilized to help fund the cost associated with our asset retirement programme. As a result, we aim to obtain a prudent mix of both cost reduction and third-party revenues to maximize the benefits of our internal plugging program.

During 2021, we accomplished the following with respect to our asset retirement program:

•

Established an internal asset retirement team to generate operating efficiencies and increase responsiveness to operating conditions and asset performance by bringing the plugging program in-house and reducing the reliance on third parties.

•

Retired 136 wells, exceeding our 92 retirements in 2020 and our collective state commitments to retire 80 wells in our primary states of operation for which we have agreements with applicable regulators. These include 10-year plans in Kentucky and Ohio and 15-year plans in Pennsylvania and West Virginia. We completed these retirements at an average cost of approximately $23 thousand per well.

•

Created a pilot program in West Virginia utilizing new plugging techniques that maintain the environmental safety of our existing techniques at a reduced time and cost of existing plugging processes.

Our asset retirement program reflects our solid commitment to a healthy environment, the surrounding community and its citizens and state regulatory authorities and we anticipate continued investment in this area as evidenced by the recent expansion to our plugging operations. During the second half of 2022, we continue our work to realize the vertical integration benefits of having expanded internal asset retirement capacity to reduce reliance on third-party contractors, reduce outsource risk, improve process quality and responsiveness and increase control over environmental remediation and costs.

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The composition of the provision for asset retirement obligations at the reporting date was as follows for the periods presented:

	Six Months Ended June 30			Year Ended December 31,
(In thousands)	2022			2021			2020
Balance at beginning of period		$	525,589		$	346,124		$	199,521
Additions(1)			7,015			96,292			26,995
Accretion			14,003			24,396			15,424
Plugging costs			(1,582)			(2,879)			(2,442)
Divestitures(2)			(16,890)			(16,500)			(3,838)
Revisions to estimate(3)(4)(5)			(62,819)			78,156			110,464
Balance at end of period		$	465,316		$	525,589		$	346,124
Less: Current asset retirement obligations			3,151			3,399			1,882
Non-current asset retirement obligations		$	462,165		$	522,190		$	344,242

(1)

Refer to Note 5 to the Company’s consolidated financial statement included elsewhere in this prospectus for additional information regarding the Company’s acquisitions and divestitures. Refer to Note 4 to the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding acquisitions and divestitures.

(2)

Associated with the divestiture of natural gas and oil properties in the normal course of business. Refer to Notes 5 and 10 in the Notes to the Consolidated Financial Statements and Notes 4 and 9 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information.

(3)

As of June 30, 2022, the Company performed normal revisions to its asset retirement obligations, which resulted in a $63 million decrease in the liability. This decrease was comprised of a $74 million decrease attributable to a higher discount rate and $10 million in cost revisions for efficiencies gained. The higher discount rate was a result of macroeconomic factors spurred by the increase in bond yields which have elevated with US treasuries to combat the current inflationary environment. Partially offsetting this decrease was a $21 million timing revision for the acceleration in our plugging efforts made possible by the recent plugging acquisitions that improve our plugging capacity and help extend our operational capabilities.

(4)

As of December 31, 2021, we performed normal revisions to our asset retirement obligations, which resulted in a $78 million increase in the liability. This increase was comprised of a $109 million increase attributable to the lower discount rate which was then offset by a $27 million reduction in anticipated ARO cost. The remaining change was attributable to timing. The lower discount rate was a result of macroeconomic factors spurred by the COVID-19 recovery, which reduced bond yields and increased inflation. Cost reductions are a result of the expansion of the Company’s internal plugging program and efficiencies gained.

(5)

At December 31, 2020, the Company performed normal revisions to its asset retirement obligations which resulted in a $110 million adjustment, of which $103 million relates to macroeconomic factors stemming largely from the COVID-19 pandemic that reduced bond yields and resulted in a lower discount rate applied to our asset retirement obligations liability. The remaining $8 million relates to pricing-related adjustments based on historical costs incurred to retire wells.

The anticipated future cash outflows for our asset retirement obligations on an undiscounted and discounted basis was as set forth in the tables below as of June 30, 2022 and December 31, 2021. The Company applies a contingency allowance for annual inflationary cost increases to its current cost expectations and then discounts the resulting cash flows using a credit adjusted risk free discount rate resulting in a net discount rate of 3.2% and 2.9%, for the periods indicated, respectively. While the rate is comparatively small to the commonly utilized PV-10 metric in our industry, the impact is significant due to the long-life low-decline nature of our portfolio. Although productive life varies within the Company’s well portfolio, presently the Company expects all of its existing wells to have reached the end of their economic lives and be retired by approximately 2095, consistent with our reserve calculations which were independently evaluated by our independent engineers.

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As of June 30, 2022

(In thousands)	Not Later Than One Year		Later Than One Year and Not Later Than Five Years		Later Than Five Years		Total
Asset retirement obligations (undiscounted)		3,151		15,898		1,543,032		1,562,081
Asset retirement obligations (discounted)		3,151		14,123		448,042		465,316

As of December 31, 2021

(In thousands)	Not Later Than One Year		Later Than One Year and Not Later Than Five Years		Later Than Five Years		Total
Asset retirement obligation (undiscounted)		3,399		17,210		1,594,853		1,615,462
Asset retirement obligation (discounted)		3,399		13,675		508,515		525,589

Cash Flows

The components of our cash flows were as follows during the periods presented:

(In thousands)	Six Months Ended
(In thousands)	June 30, 2022			June 30, 2021			$ Change			% Change
Net cash provided by operating activities		$	204,987		$	108,121		$	96,866		90%
Net cash used in investing activities			(147,221)			(143,971)			(3,250)		2%
Net cash provided by financing activities			117,018			38,145			78,873		207%
Net change in cash and cash equivalents		$	174,784		$	2,295		$	172,489		7,516%

	Year Ended December 31,
(In thousands)	2021			2020			$ Change			% Change
Net cash provided by operating activities		$	320,182		$	241,710		$	78,472		32%
Net cash used in investing activities			(625,874)			(257,756)			(368,118)		143%
Net cash provided by financing activities			316,871			15,764			301,107		1,910%
Net change in cash and cash equivalents		$	11,179		$	(282)		$	11,461		(4,064)%

Net Cash Provided by Operating Activities

For the six months ended June 30, 2022, net cash provided by operating activities of $205 million increased $97 million, or 90%, when compared to $108 million in 2021. The increase in net cash provided by operating activities was predominantly attributable to the following:

•

An increase in Total Revenue, inclusive of hedges, which was marginally offset by the increases in expenses described above. This net increase in Adjusted EBITDA was then offset by the increases in costs associated with acquisitions and other adjusting costs described above; and

•

An increase in working capital inflows, driven by the increasing accounts payable, accrued liability, and distribution in suspense balances. These increases are a function of our period-over-period growth through acquisitions and an increase in hedge settlement payments, discussed above.

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For the year ended December 31, 2021, net cash provided by operating activities of $320 million increased by $78 million, or 32%, as compared to $242 million in 2020. The increase in net cash provided by operating activities was predominantly attributable to the following:

•

An increase in Total Revenues, inclusive of hedges, which marginally offset the increases in expenses described above. This increase was then offset by the increases in costs associated with acquisitions described above as well as by increases in hedge modification payments that were made to take advantage of the higher commodity price environment; and

•

A meaningful increase in working capital inflows, driven by increasing accounts payable balances. This increase in accounts payable was a function of the increase in hedge settlement payments, as discussed above, and of increases that resulted from our growth through acquisitions.

Production, realized prices, operating expenses and G&A are discussed above.

Net Cash Used in Investing Activities

For the six months ended June 30, 2022, net cash used in investing activities of $147 million increased $3 million, or 2%, from outflows of $144 million in 2021. The change in net cash used in investing activities was primarily attributable to the following:

•

A decrease in cash outflows of $65 million for acquisition and divestiture activity resulted in cash outflows associated with acquisitions and divestitures of $64 million during the during the six months ended June 30, 2022, compared to $129 million for six months ended June 30, 2021. Refer to Note 4 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding acquisitions;

•

An increase in capital expenditures period-over-period. Capital expenditures were $45 million for the six months ended June 30, 2022 compared to $16 million for the six months ended June 30, 2021. This increase in capital expenditures was primarily driven by our growth through acquisitions year-over-year and the additional capital expenditures for the development of the Tapstone wells in progress at the time of the acquisition;

•

An increase in restricted cash outflows of $26 million year-over-year as a result of the establishment of the interest expense reserve required by the ABS Notes. These reserves naturally decline over time with the amortizing nature of the financing structure; and

•

An increase in contingent consideration outflows of $19 million year-over-year, primarily associated with the Carbon Acquisition contingent payment which was settled in the current period.

For the year ended December 31, 2021, net cash used in investing activities of $626 million increased by $368 million, or 143%, as compared to $258 million in 2020. The change in net cash used in investing activities was primarily attributable to the following:

•

An increase in cash outflows of $356 million for acquisition and divestiture activity resulted in cash outflows associated with acquisitions and divestitures of $580 million during the year ended December 31, 2021, compared to $224 million for the year ended December 31, 2020. Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information regarding acquisitions and divestitures;

•

Capital expenditures were $50 million for the year ended December 31, 2021 compared to $22 million for the year ended December 31, 2020. This increase in capital expenditures was primarily driven by our growth through acquisitions year-over-year. As of and subsequent to December 31, 2021, we have not incurred any material capital commitments; and

•

A decrease in restricted cash outflows of $14 million year-over-year as a result of the establishment of the interest reserve required by our long-term financing agreements for the ABS II Notes and Term Loan I in the prior year. These reserves naturally decline over time with the amortizing nature of the financing structure.

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Net Cash Provided by Financing Activities

For the six months ended June 30, 2022, net cash provided by financing activities of $117 million increased $79 million, or 207%, as compared to $38 million in 2021. This change in net cash provided by financing activities was primarily attributable to the following:

•

Our Credit Facility activity resulted in net repayments of $571 million during the six months ended June 30, 2022 versus net repayments of $57 million during the six months ended June 30, 2021, with much of the decrease in our Credit Facility borrowings being attributable to the proceeds generated by the ABS Notes;

•

Our other borrowing structures generated net proceeds of $908 million during the six months ended June 30, 2022, as compared to net repayments of $34 million during the six months ended June 30, 2021. This is primarily a result of the ABS III, IV, and V Notes issuances during the six months ended June 30, 2022 with no corresponding debt issuance during the six months ended June 30, 2021. These proceeds were offset, in part, by increases in interest, debt issuance costs and hedge modification payments of $98 million;

•

A decrease of $214 million in proceeds from equity issuances as there were no issuances during the six months ended June 30, 2022 compared to $214 million raised during the six months ended June 30, 2021;

•

An increase of $10 million in dividends paid during the six months ended June 30, 2022 as compared to the six months ended June 30, 2021; and

•

During the six months ended June 30, 2022, we utilized our EBT to repurchase approximately $10 million of the Company’s outstanding shares for use in non-cash compensation programs for certain key managers.

Refer to Notes 16, 17 and 20 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding share capital, dividends and borrowings, respectively.

For the year ended December 31, 2021, net cash provided by financing activities of $317 million increased by $301 million, or 1,910%, as compared to $16 million in 2020. This change in net cash provided by financing activities was primarily attributable to the following:

•

Credit Facility activity resulted in net proceeds of $357 million in 2021 versus net repayments of $223 million in 2020, with much of the increase attributable to the expanded borrowing base for acquisition activity;

•

Structured debt facilities resulted in repayments of $62 million in 2021, as compared to net proceeds of $318 million (proceeds of $353 million and repayments of $35 million) in 2020. The increase in repayments is a result of the May 2020 issuance of the ABS II Notes and Term Loan I and a partial year of amortizing principal repayments in 2020;

•

An increase of $132 million in proceeds from equity issuances that raised $214 million in 2021 as compared to equity issuances that raised $81 million in 2020. The additional proceeds were used to finance acquisition activity;

•

An increase of $32 million in dividends paid in 2021 as compared to 2020; and

•

A decrease of $16 million in the repurchase of shares as we did not repurchase any shares in 2021.

Refer to Notes 16, 18 and 21 in the Notes to the Consolidated Financial Statements for additional information regarding share capital, dividends and borrowings, respectively.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that give rise to material off-balance sheet obligations. As of June 30, 2022 and December 31, 2021, our material off-balance sheet arrangements and transactions include operating service arrangements and $18 million and $32 million in letters of credit outstanding against our Credit Facility, respectively. There are no other transactions,

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arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of capital resources.

Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual obligations as of the periods presented were as follows:

(In thousands)	Not Later Than One Year			Later Than One Year and Not Later Than Five Years			Later Than Five Years			Total
Recorded contractual obligations
Trade and other payables		$	36,931		$	—		$	—		$	36,931
Borrowings			263,942			642,421			475,054			1,381,417
Leases			10,039			18,893			—			28,932
Asset retirement obligation(1)			3,151			15,898			1,543,032			1,562,081
Other liabilities(2)			432,332			3,329			—			435,661
Off-Balance Sheet contractual obligations
Firm Transportation			39,730			65,941			178,147			283,818
Total		$	786,125		$	746,482		$	2,196,233		$	3,728,840

(1)

Represents our asset retirement obligation on an undiscounted basis. On a discounted basis the liability is $465 million as of June 30, 2022 as presented on the Consolidated Statement of Financial Position.

(2)

Excludes taxes payable, asset retirement obligations, revenue to be distributed and the long-term portion of the value associated with the upfront promote received from Oaktree. Refer to Note 22 in the Notes to the Interim Condensed Consolidated Financial Statements for information.

We believe that our cash flows from operations will be sufficient to meet our existing contractual obligations and commitments for at least the next twelve months. Cash flows from operations were $205 million for the six months ended June 30, 2022, which includes only a partial year of contributions from our acquisitions in 2022 and were $320 million for the year ended December 31, 2021, which includes only a partial year of contributions from our Central Region acquisitions in 2021. As of June 30, 2022 and for the year ended December 31, 2021, we also had current assets of $617 million and $337 million, respectively and available borrowings on our Credit Facility of $300 million and $254 million, respectively (excluding $18 million and $32 million in outstanding letters of credit, respectively), which could also be used to service our contractual obligations and commitments over the next twelve months.

Litigation and Regulatory Proceedings

From time to time, we may be involved in legal proceedings in the ordinary course of business. We are not currently a party to any material litigation proceedings, the outcome of which, if determined adversely to us, would, individually or in the aggregate, be reasonably expected to have a material and adverse effect on our business, financial position or results of operations. In addition, we are not aware of any material legal or administrative proceedings contemplated to be brought against us.

We have no other contingent liabilities that would have a material impact on our financial position, results of operations or cash flows.

Environmental Matters

Our operations are subject to environmental regulation in all the jurisdictions in which it operates. We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would adversely affect our operations. We can offer no assurance regarding the significance or cost of compliance associated with any such new environmental legislation once implemented.

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In May 2022, we joined the Oil and Gas Methane Partnership 2.0 (the “OGMP”), a multi-stakeholder initiative launched by the United Nations Environment Programme and Climate and Clean Air Coalition in partnership with the European Commission, the UK Government, Environmental Defense Fund and other leading oil and gas companies, to further advance our commitment to reducing emissions.

The OGMP is a voluntary commitment which includes establishment of a credible pathway to attaining the “Gold Standard Compliance” designation for the natural gas produced by the Company. We have attained “Gold Standard Pathway” for our implementation plan whereby we improve our current measurement processes for methane emissions. We expect total cost impacts to be less than $5 million for improved measurement techniques in the three of ten categories of methane emissions where we do not already meet Gold Standard Compliance. The expected impact to operations is improved efficiency and reduced emissions.

Recently Issued Accounting Pronouncements

Refer to Note 3 in the Notes to the Consolidated Financial Statements for information regarding recent accounting pronouncements applicable to our Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Refer to Notes 3 and 4 in the Notes to the Consolidated Financial Statements for information regarding our significant accounting policies, judgements and estimates.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to a variety of financial risks such as market risk, credit risk, liquidity risk, capital risk and collateral risk. We manage these risks by monitoring the unpredictability of financial markets and seeking to minimize potential adverse effects on our financial performance on a continuous basis.

Our principal financial liabilities are comprised of borrowings, leases and trade and other payables, used primarily to finance and financially guarantee our operations. Our principal financial assets include cash and cash equivalents and trade and other receivables derived from our operations.

We also enter into derivative financial instruments which, depending on market dynamics, are recorded as assets or liabilities. To assist with the design and composition of our hedging program, we engage a specialist firm with the appropriate skills and experience to manage our risk management derivative-related activities.

Market Risk

Market risk is the possibility that the fair value of future cash flows of a financial instrument will fluctuate due to changes in market prices. Market risk is comprised of two types of risk: interest rate risk and commodity price risk. Financial instruments affected by market risk include borrowings and derivative financial instruments. Derivative and non-derivative financial instruments are used to manage market price risks resulting from changes in commodity prices and foreign exchange rates, which could have a negative effect on assets, liabilities or future expected cash flows.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our variable-rate Credit Facility. The remainder of our outstanding indebtedness is fixed-rate. As of June 30, 2022 we were undrawn on our Credit Facility, due to our fixed-rate ABS Notes issuance, and as of December 31, 2021 and 2020, we had $571 million and $437 million, respectively, outstanding under our Credit Facility that maintained an average interest rate of 4.25%, 3.36% and 2.96%, respectively. Refer to Note 21 in the Notes to the Consolidated Financial Statements and Note 19 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding our Credit Facility.

As evidenced through the ABS Notes issuances, we principally manage interest rate risk by entering into fixed-rate borrowing obligations with amortizing structures. Given 100% of our borrowings are currently under fixed-rate structures and our undrawn Credit Facility position as of June 30, 2022, presently adjustments in interest rates would not result in an increase or decrease to our financing costs on our

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existing borrowings. To mitigate residual interest rate risk, specifically during periods when we are drawn on our Credit Facility, we enter into derivative financial instruments. The total principal hedged through the use of derivative financial instruments varies from period to period. See Note 13 in the Notes to the Consolidated Financial Statements for additional information regarding our derivative financial instruments.

As of June 30, 2022, we had an interest rate swap (“IR swap”) that fixed $400 million of variable SOFR interest rate risk, at 1.73% which will mitigate interest rate risk on future borrowings under the Credit Facility. Refer to Note 13 in the Notes to the Consolidated Financial Statements and Note 12 in the Notes to the Interim Condensed Consolidated Financial Statements for additional information regarding derivative financial instruments.

During the six months ended June 30, 2022, our Credit Facility transitioned from LIBOR to SOFR during our regular redetermination. We have not experienced a material impact from the transition.

Commodity Price Risk

Our revenues are primarily derived from the sale of our natural gas, NGLs and oil production, and as such, we are subject to commodity price risk. Commodity prices for natural gas, NGLs and oil can be volatile and can experience fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. For the six months ended June 30, 2022 and for the years ended December 31, 2021 and 2020, our commodity revenue was $914 million, $973 million and $382 million, respectively.

We enter into derivative financial instruments to mitigate the risk of fluctuations in commodity prices. The total volumes hedged through the use of derivative financial instruments varies from period to period, but generally our objective is to hedge at least 65% for the next 12 months, at least 50% in months 13 to 24, and a minimum of 30% to 40% in months 25 to 36, of its anticipated production volumes for the next 36 months. Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional information regarding derivative financial instruments.

By removing price volatility from a significant portion of our expected production through 2032, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. For further detail regarding the risks to our business resulting from commodity price volatility, see “Risk Factors—Risks Relating 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.”

Credit and Counterparty Risk

We are exposed to credit and counterparty risk from the sale of our natural gas, NGLs and oil. Trade receivables from customers are amounts due for the purchase of natural gas, NGLs and oil. Collectability is dependent on the financial condition of each customer. We review the financial condition of customers prior to extending credit and generally do not require collateral in support of their trade receivables. We had one customer that constituted 12%, 13% and 11%, respectively, of our total trade receivables from customers as of June 30, 2022, December 31, 2021 and 2020, respectively. As of June 30, 2022, December 31, 2021 and 2020, our trade receivables from customers were $365 million, $268 million and $67 million, respectively.

We are also exposed to credit risk from joint interest owners, entities that own a working interest in the properties we operate. Joint interest receivables are classified in trade receivables, net in our Consolidated Statement of Financial Position. We have the ability to withhold future revenue payments to recover any non-payment of joint interest receivables. Given the historically low commodity pricing environment in 2020, however, we recorded a non-recurring increase in the reserve of joint interest owner receivables for the allowance for credit losses of $7 million as of December 31, 2020. During 2021, commodity markets improved and with them so did our ability to withhold receivables from revenue distributions. As a result, in 2021 our allowance for credit losses from joint interest decreased by 45%. During the six months ended June 30,

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2022 prices were volatile but remained at elevated levels leading to minimal changes in reserve level. As of June 30, 2022, December 31, 2021 and 2020, our joint interest receivables were $18 million, $15 million and $0.1 million, respectively.

The majority of trade receivables are current and we believe these receivables are collectible.

Liquidity Risk

Liquidity risk is the possibility that we will not be able to meet our financial obligations as they are due. We manage this risk by maintaining adequate cash reserves through the use of cash from operations and borrowing capacity on the Credit Facility. We also continuously monitor our forecasted and actual cash flows to ensure we maintain an appropriate amount of liquidity.

Capital Risk

We define capital as the total of equity shareholders’ funds and long-term borrowings net of available cash balances. Our objectives when managing capital are to provide returns for shareholders and safeguard the ability to continue as a going concern while pursuing opportunities for growth through identifying and evaluating potential acquisitions and constructing new infrastructure on existing proved leaseholds. Our board of directors does not establish a quantitative return on capital criteria, but rather promotes year-over-year Adjusted EBITDA growth. We seek to maintain a leverage target at or under 2.5 to 1.0 after giving effect to acquisitions and any related financing arrangements.

Collateral Risk

We have pledged approximately 100% of our upstream natural gas and oil properties in Appalachia and the upstream natural gas and oil properties in the Barnett Shale (excluding those in the Alliance, Texas area, which have been pledged under our Credit Facility) as of June 30, 2022 to fulfill the collateral requirements for borrowings under the ABS Notes and Term Loan I. Our remaining natural gas and oil properties collateralize our Credit Facility. The fair value of the borrowings collateral is based on a third-party engineering reserve calculation using a 10% cumulative discounted cash flow and a commodities futures price schedule. Refer to Notes 5 and 21 to the Consolidated Financial Statements for additional information regarding acquisitions and borrowings, respectively.

Internal Control Over Financial Reporting

We have identified a material weakness that existed as of December 31, 2021 that pertains to the completeness and accuracy of data provided to specialists used in the evaluation of fair value of natural gas and oil properties acquired in business combinations. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis. See “Risk Factors—Risks Related to this Offering—Failure to comply with requirements to design, implement and maintain effective internal control over financial reporting could have a material adverse effect on our business.” We have identified a material weakness in our internal control over financial reporting.

Implications of Being an Emerging Growth Company

We qualify as an emerging growth company as defined in the JOBS Act. As an emerging growth company, we may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies in the United States. These provisions include:

•

An exemption from compliance with any requirement that the Public Company Accounting Oversight Board may adopt regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements;

•

Reduced disclosure about our executive compensation arrangements;

•

An exemption from the non-binding advisory votes on executive compensation, including golden parachute arrangements; and

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An exemption from the auditor attestation requirement in the assessment of our internal control over financial reporting pursuant to the Sarbanes-Oxley Act.

Implications of Being a Foreign Private Issuer

Our status as a foreign private issuer also exempts us from compliance with certain laws and regulations of the SEC and certain regulations of the . Consequently, we are not subject to all of the disclosure requirements applicable to U.S. public companies. For example, we are exempt from certain rules under the Exchange Act that regulate disclosure obligations and procedural requirements related to the solicitation of proxies, consents or authorizations applicable to a security registered under the Exchange Act. In addition, our executive officers and directors are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and related rules with respect to their purchases and sales of our securities. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. public companies. Accordingly, there may be less publicly available information concerning our company than there is for U.S. public companies.

In addition, foreign private issuers are not required to file their annual report on Form 20-F until 120 days after the end of each fiscal year, while U.S. domestic issuers that are accelerated filers are required to file their annual report on Form 10-K within 75 days after the end of each fiscal year. Foreign private issuers are also exempt from the Regulation FD (Fair Disclosure), aimed at preventing issuers from making selective disclosures of material information.

As both an emerging growth company and foreign private issuer, we have taken advantage of certain reduced disclosure and other requirements in this prospectus and may elect to take advantage of other reduced reporting requirements in future filings up and until we cease to be either an emerging growth company or foreign private issuer. Accordingly, the information contained herein or that we provide shareholders may be different than the information you receive from other public companies in which you hold equity securities that are not emerging growth companies or foreign private issuers.

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BUSINESS

Overview

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 Kingdom, and our predecessor business was co-founded in 2001 by our Chief Executive Officer, Robert Russell (“Rusty”) Hutson, Jr., with an initial focus on primarily natural gas and 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, we have completed 20 acquisitions for a combined purchase price of approximately $2.4 billion. We had average daily production of 816 MMcfepd and 711 MMcfepd for the six months ended June 30, 2022 and for the year ended December 31, 2021, respectively.

Our strategy is primarily to acquire and manage natural gas and oil properties while leveraging our associated midstream assets to generate cash flows and maximize shareholder returns, including through the payment of regular dividends. We seek to improve the performance and operations of our acquired assets through our deployment of rigorous field management programs and/or refreshing infrastructure. Through operational efficiencies, we demonstrate our ability to maximize value by enhancing production while lowering costs and improving well productivity. We adhere to stringent operating standards, with a strong focus on health, safety and the environment to ensure the safety of our employees and the local communities in which we operate. We believe that acting as a careful steward of our assets will improve revenue and margins through recaptured methane emissions while reducing operating costs, which benefits our profitability. This focus on operational excellence, including the reduction of emissions, also benefits the environment and communities in which we operate.

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.

Our Business Strategy

•

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

•

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

•

Disciplined growth through accretive acquisitions of producing assets

•

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

•

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

Our Strengths

•

Low-risk and low-cost portfolio of assets

•

Long-life and low-decline production

•

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

•

Highly experienced management and operational team

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Track record of successful consolidation and integration of acquired assets

Outlook for 2022

Looking forward to 2022, we continue to seek to maximize cash flow and to maximize our ability to pay regular dividends. We also plan to maintain our hedging strategy to protect cash flow, and the ability to reduce debt and to pay dividends, while also taking advantage of market opportunities to raise the floor price of our risk management program. We will seek to retain our strategic advantages in purposeful growth through a disciplined capital expenditure program that continues to secure low-cost financing that supports acquisitive growth while maintaining low leverage and ample liquidity. In addition, we intend to remain proactive in our ESG endeavors by securing 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, 2021, 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 prospectus forms a part. See the 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.

	As of December 31, 2021
	SEC Pricing(1)
Proved developed reserves
Natural gas (MMcf)			4,008,160
NGLs (MBbls)			89,071
Oil (MBbls)			13,823
Total proved developed reserves (MBoe)			770,921
Proved undeveloped reserves
Natural gas (MMcf)			877
NGLs (MBbls)			9
Oil (MBbls)			429
Total proved undeveloped reserves (MBoe)			584
Total proved reserves
Natural gas (MMcf)			4,009,037
NGLs (MBbls)			89,080
Oil (MBbls)			14,252
Total proved reserves (MBoe)			771,505
Prices used
Natural gas (Mcf)		$	3.60
Oil and NGLs (Bbls)		$	66.55
PV-10 (thousands)
Pre-tax (Non-GAAP)(2)		$	4,037,016
PV of Taxes			(703,925)
Standardized Measure		$	3,333,091
Percent of estimated proved reserves that are:
Natural gas			86.6%
Proved developed			99.9%
Proved undeveloped			0.1%

(1)

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2021 was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For NGLs and oil volumes, the average WTI price of $66.55 per Bbl as of December 31, 2021, was similarly adjusted for gravity, quality, local conditions, gathering, 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, 2021 was prepared without giving effect to taxes or hedges. PV-10 is a non-GAAP and non-IFRS financial measure and generally differs from Standardized Measure, the most directly comparable GAAP measure, because it does not include the effects of income taxes on future net cash flows. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the Standardized Measure because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. While the Standardized Measure is free cash dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. Investors should be cautioned that neither PV-10 nor the Standardized Measure represents an estimate of the fair market value of our proved reserves.

Proved Reserves

As of December 31, 2021, our estimated proved reserves totaled 772 MMBoe, an increase of 42.4% from the prior year-end with a Standardized Measure of $3.3 billion. Natural gas constituted approximately 86.6% of our total estimated proved reserves and 86.7% of our total estimated proved developed reserves. The following table provides a summary of the changes in our proved reserves for the year ended December 31, 2021.

	Total (MBoe)
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

Consistent with our business model of having an operator focus rather than a development focus, we had no exploratory or development wells drilled in 2021 or 2020 for properties in which we held an operating or non-operating interest.

Revisions to Previous Estimates

The 90,251 MBoe in revisions to previous estimates is primarily associated with changes in the 12-month average realized Henry Hub spot price, which increased approximately 81% as compared to December 31, 2020.

Purchase of Reserves in Place

The 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 for additional information about acquisitions.

Sales of Reserves in Place

The 27,340 MBoe of sales of reserves in place is 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.

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,

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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, 2021.

	As of December 31, 2021
Total gross productive wells		77,530
Natural gas wells		74,237
Oil wells		3,293
Total net productive wells		64,036
Natural gas wells		62,313
Oil wells		1,723

	As of December 31, 2021(1)
Total gross in progress wells		5
Total net in progress wells		2

(1)

Comprised of wells in the Central Region.

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 and change in control. 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, 2021, 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 2021:

	Total (MBoe)
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		—
Proved undeveloped reserves as of December 31, 2021		584

Purchase of Reserves in Place

The 584 MBoe of purchase of reserves in place is associated with the Tapstone Acquisition and relates to five wells that were under development by Tapstone at closing. We have engaged third parties to complete this development activity. Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information about acquisitions.

We incurred costs of approximately $1 million in 2021 on development activities for drilling and completion activities related to the in-progress wells we acquired with the Tapstone Acquisition. No other development activities were performed.

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, 2021. Developed acres are acres spaced or

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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, 2021.

Developed Acreage

Undeveloped Acreage

Total Acreage

Gross(1)

Net(2)

Gross(1)

Net(2)

Gross(1)

Net(2)

Acreage

4,837,566

2,768,072

8,737,126

5,960,527

13,574,692

8,728,599

(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.

(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, 2021 that will expire in 2022, 2023 and 2024 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
2022		46,203		5,810
2023		677,405		677,405
2024		—		—

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, 2021, we had no development plans other than the Tapstone 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, 2021 included in this prospectus 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 6 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

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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 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 the section titled “Risk Factors” for additional information.

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Production Volumes, Average Sales Prices and Operating Costs

	Year Ended December 31,
	2021			2020
Production
Natural Gas (MMcf)			234,643			199,667
NGLs (MBbls)			3,558			2,843
Oil (MBbls)			592			417
Total production (MBoe)			43,257			36,538
Average realized sales price (excluding impact of derivatives settled in cash)
Natural gas (Mcf)		$	3.49		$	1.72
NGLs (Bbls)			32.53			8.15
Oil (Bbls)			65.26			36.12
Total (Boe)		$	22.50		$	10.45
Average realized sales price (including impact of derivatives settled in cash)
Natural gas (Mcf)		$	2.36		$	2.33
NGLs (Bbls)			15.52			13.95
Oil (Bbls)			71.68			52.97
Total (Boe)		$	15.08		$	14.40
Operating costs per Boe
LOE(1)		$	2.76		$	2.53
Production taxes(2)			0.71			0.38
Midstream operating expense(3)			1.40			1.45
Transportation expense(4)			1.86			1.24
Total operating expense per Boe		$	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, which consists of the stacked Cotton Valley, Haynesville, and Bossier shales, (iii) the Barnett Shale and (iv) the Midcontinent region, including in Louisiana, 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 2021		Appalachia 2020
Production
Natural Gas (MMcf)		201,635		199,667
NGLs (MBbls)		2,690		2,843
Oil (MBbls)		446		417
Total production (MBoe)		36,743		36,538

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Customers

Our production is generally sold on month-to-month contracts at prevailing market prices. During each of the years ended December 31, 2021 and 2020, two customers individually comprised more than 10% of our total revenues, together representing 22% of our consolidated revenues.

Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security.

Delivery Commitments

We have contractually agreed to deliver firm quantities of natural gas to various customers, which we expect to fulfill with production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet these commitments. The following table summarizes our total gross commitments as of December 31, 2021.

	Natural gas (MMcf)
2022		64,597
2023		46,486
2024		1,023
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. 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

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producers and affiliates of companies with extensive pipeline systems that are used for transportation from producers to end users. Other factors affecting competition are the cost and availability of alternative fuels, the level of consumer demand and the cost of and proximity to pipelines and other transportation facilities. We believe that our ability to compete effectively within the marketing segment in the future depends upon establishing and maintaining strong relationships with customers.

Seasonality

Demand for natural gas and oil generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies and consumers procurement initiatives can also lessen seasonal demand fluctuations. Seasonal anomalies can increase competition for equipment, supplies and personnel and can lead to shortages and increase costs or delay our operations.

Title to Properties

We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring producing wells, we endeavor to perform a title investigation on an appropriate portion of the properties that is thorough and is consistent with standard practice in the natural gas and oil industry. Generally, we conduct a title examination and perform curative work with respect to significant defects that we identify on properties that we operate. We believe that we have performed reasonable and protective title reviews with respect to an appropriate cross-section of our operated natural gas and oil wells.

Environmental, Health and Safety (“EHS”)

Overview

EHS management remains a top priority as we demonstrate our commitment to exercise 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 take a rigorous approach to managing the potential impacts of production fluid spills, which may include natural gas liquids, oil or produced water. Waste management and 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 be good and trusted stewards of the environment, to ensure that our operations meet or exceed all environmental standards, and to achieve health and safety excellence. Signed by our CEO and overseen by our board of directors’ Sustainability and Safety Committee, our EHS Policy is guided by the principles of corporate accountability and leadership, risk preparedness, collaboration and transparency.

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 prescreen contractors with high safety performance records and then to continuously monitor their 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 underscores our operating

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performance, as evidenced by our daily operational goals promoting “Safety—No Compromises.” Our Total Recordable Incident Rate (“TRIR”), defined as the number of work-related injuries per 100 full-time employees during a one-year period, in 2021 of 1.55 exceeded both our target for the year of 1.33 and our 2020 results of 1.35 driven by a higher frequency of minor incidents. While we remain encouraged by interim steps taken throughout 2021 to improve this metric, we also recognize that our growing company and employee base as a result of our acquisitions in 2021 means that we still have work to do to educate our teams to drive improvements. 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 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

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 material 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 2021 at 0.72. With more than 1,000 employees on the road each day, road safety awareness and safe driving are of paramount importance to us. We are proud of this accomplishment given the 18.1 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 2021 Central Region 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.

Our 2021 Central Region acquisitions significantly increased the 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 our prior years of operations, which excluded Central Region operations. Our spill intensity rate, however remained negligible for the year at .10 per MBBL. Although we reported a favorable intensity metric with the inclusion of a region that holds more water we aim for zero spills and continue to seek to 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 90% dry natural gas. Nonetheless, we 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.

As stated in our Corporate Responsibility Policy, we are committed to balancing our business needs with the needs of the communities in which we and our employees operate. In 2021, we took steps to develop company-wide programs to enhance our community outreach, including formalizing a community relations

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program, an employee volunteer program and a charitable donation match program. In response to our community outreach work, beginning in 2022, we have committed to invest up to $2 million per year for community and higher education related outreach and support programs.

Our Approach to ESG

Our approach to ESG management encompasses consideration of our environmental and social impact as well as our responsibility to conduct business in accordance with the highest standards of governance. Our commitment to sound ESG business practices is underpinned by our values, which guide our daily actions, annual plans, investments, relationships and business strategies.

In addition to our guiding values for ESG management, we also utilize the United Nations’ (“UN”) Sustainable Development Goals (“SDG”), which calls on individuals, corporations and governments to work together towards the ultimate, unified goal of creating a better and more sustainable future for all citizens globally. We challenge ourselves to consider these topics and more when we effectuate our business model, corporate strategy, daily operations and risk management practices. We believe our business model supports a material contribution to SDG 7—Affordable and Clean Energy, SDG 8—Decent Work and Economic Growth and SDG 9—Industry, Innovation and Infrastructure, and we’ve identified other SDGs to which our business model aligns yet also provides added opportunities for us to make continuous improvement and contribution.

In the spirit of continuous improvement and transparency, we are committed to providing additional information on our climate goals, including updates on our baseline emissions work and our longer-term GHG emissions reductions. In addition, we periodically conduct a stakeholder materiality assessment to gain a better understanding of both internal and external views on the ESG topics that matter most to our business and corporate strategy. We last conducted this assessment in 2020 and continue to direct our sustainability and stewardship efforts to those identified issues as summarized in our 2020 reporting.

During 2021, we launched Project Fresh, a comprehensive process designed to enhance the understanding of our baseline emissions data, including improved data collection and accuracy. Strong governance and collaborative participation in this project are key. Under the oversight of our Chief Operating Officer, Brad Gray, and the functional leadership of our Vice President of EHS, Paul Espenan, the project included several cross-functional teams, including both upstream and midstream Field Operations, IT and Finance, sharing best practices and seeking additional ways to improve our processes aimed at reducing absolute emissions.

Equipped with a growing list of potential emissions abatement projects as a result of our collaborative and comprehensive efforts, we enter 2022 focused primarily on achieving our stated short-term goals of 30% and 50% reductions in Scope 1 methane intensity by 2026 and 2030, respectively, while simultaneously working toward long-term reductions in CO₂ and a net zero Scope 1 and 2 GHG position by 2040. In late 2021, we announced our intention to invest $15 million in 2022 to fund the initial projects of our emissions reduction goals. Importantly, our strategic and opportunistic hedging practices provide protection of our cash flows, including these 2022 capital commitments and those that will follow every year thereafter.

In 2021, we expanded our ESG resources by appointing a Vice President of ESG & Sustainability while also increasing our internal expertise within the EHS team.

Human Capital Management

As of December 31, 2021, we had 1,426 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 300 new employees in 2021. 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.

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footprint in support of driving diversity within the Company. During 2021, the percentage of minorities that made up our employee base increased to 2.7% from 0.6%. The percentage of women in our employee base at December 31, 2021 was 11%, with the majority serving in production support roles. 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 less than 10%, 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 background, to the benefit of the Company and our stakeholders.

Our board of directors consists of three females and five males, and our senior management, including our executive committee and its direct reports but excluding the two executive directors, consisted of 82 employees, including 26 females (32%) and 56 males (68%). Although our board of directors does not currently have any ethnically diverse members, it acknowledges the guidelines and recommendations set forth by the Parker Review Committee. The Parker Review committee believes that ethnic and cultural diversity on boards enhances long-term profitability and sustainability for organizations and promotes equal opportunities for participation and success at the highest level within those companies. To encourage this diversity, the Parker Review Committee recommends that Financial Times Stock Exchange 250 companies target to have a person from a minority ethnic group on their boards by December 2024. Our 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 our board of directors. Our board of directors will continue to review and evaluate the Company’s board of directors and committee composition and intends to continue further progress with independence and diversity per the requirements set forth in the Parker Review.

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; 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; endangered 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, permit violations during operations can occur. Certain of such violations may be expected to result in fines or penalties, but could also result in 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. However, our operations are also

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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 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, some states and the federal government have proposed that emissions from certain proximate and related sources should 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. The EPA hopes to finalize the standards by the end of 2022. 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 regulations protect plant and animal species that are threatened or endangered. The Migratory Bird Treaty Act provides similar protections to migratory birds. 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 are known to exist. Laws and regulations intended to protect threatened and endangered species or migratory birds could have a seasonal impact on our construction activities and operations. New or additional species that may be identified as requiring protection or consideration could also lead to delays in obtaining permits and/or other restrictions, including operational restrictions.

Safety of Gas Transmission and Gathering Pipelines

Natural gas pipelines serving our operations are subject to regulation by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968, (“NGPSA”), as amended by the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002 (“PSIA”), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”). The NGPSA

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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 published the first of three rules that, collectively, are referred to as the natural gas “mega rule.” The first rule imposes additional safety requirements on natural gas transmission pipelines. PHMSA has also taken steps to expand the regulation of rural gathering lines and impose a number of reporting and inspection requirements on regulated pipelines, and additional requirements are expected in the future. In November 2021, for instance, PHMSA released a final rule that expands the definition of regulated gathering pipelines and imposes safety measures on certain currently unregulated gathering pipelines. The final rule also imposes reporting requirements on all gathering pipelines, and specifically requires operators to report safety information to PHMSA. 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 loss of 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 certain 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

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threat of discharge. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

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

The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil and refined products and certain other liquids be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.

Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from regulation by FERC. However, the distinction between federally unregulated gathering facilities and FERC regulated transmission facilities is a fact-based determination, and the classification of facilities is the subject of ongoing litigation. We own certain natural gas pipeline facilities that we believe meet the traditional tests FERC has used to establish a pipeline’s primary function as “gathering,” thus exempting it from the jurisdiction of FERC under the Natural Gas Act.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. FERC regulates the transportation of oil and NGLs on interstate pipelines under the provisions of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate transportation of oil, NGLs and other products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

Natural gas, NGLs and crude oil prices are currently unregulated, but Congress historically has been active in the area of natural gas, NGLs and crude oil regulation. We cannot predict whether new legislation to regulate sales might be enacted in the future or what effect, if any, any such legislation might have on our operations.

Health and Safety Laws

Our natural gas 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 natural gas 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 gas 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 final laws and regulations at the international, federal, state, regional and local level that seek to limit greenhouse gas emissions, and regulations that restrict emissions could increase our costs should the requirements necessitate the installation of new equipment or the purchase of emission allowances. These laws and regulations could also impact our customers, including the electric generation industry, making alternative sources of energy more competitive and thereby decreasing demand for the natural gas and oil we

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produce. Additional regulation could also lead to permitting delays and additional monitoring and administrative requirements, as well as to impacts on electricity generating operations.

At the international level, there is an agreement, 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. 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 again in Glasgow at the 26th Conference to the Parties on 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. 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 reduce emissions of greenhouse gases 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 warming 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 recently proposed new rules relating to the disclosure of a range of climate-related risks. 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.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040, and that natural gas and oil will continue to represent a substantial percentage of global energy use over that time. 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.

Legal Proceedings

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MANAGEMENT

Executive Officers and Directors

The following table sets forth the name and position of each of our executive officers and directors as of the completion of this offering, including their ages as of March 31, 2022:

Name	Age		Position
Executive Officers
Robert Russell (“Rusty”) Hutson, Jr.		52	Co-Founder, Chief Executive Officer and Director
Bradley G. Gray(4)		53	Executive Vice President, Chief Operating Officer and Director
Eric Williams		44	Executive Vice President, Chief Financial Officer
James P. Rode		67	Executive Vice President, Chief Commercial Officer
Benjamin Sullivan		43	Executive Vice President, General Counsel and Corporate Secretary
Non-Executive Directors
David E. Johnson(2)(3)(4)		61	Independent Chairman of the Board
Martin K. Thomas(3)		57	Vice Chairman of the Board
Sylvia J. Kerrigan(2)(3)		56	Independent Director
Melanie A. Little(1)(2)(4)		52	Independent Director
Sandra M. Stash(1)(2)(4)		62	Independent Director
David J. Turner, Jr.(1)(3)		58	Independent Director

(1)

Audit and Risk Committee member

(2)

Remuneration Committee member

(3)

Nomination Committee member

(4)

Sustainability and Safety Committee member

The current business addresses for our executive officers and directors is c/o Diversified Energy Company plc, 1600 Corporate Drive, Birmingham, Alabama 35242.

Executive Officers

The following is a brief summary of the business experience of our executive officers.

Robert Russell (“Rusty”) Hutson, Jr. is our co-founder and has served as our Chief Executive Officer since the founding of our predecessor entity in 2001. Mr. Hutson also serves on our board of directors. Prior to founding the Company, Mr. Hutson held finance and accounting roles for 13 years at Bank One (Columbus, Ohio) and Compass Bank (Birmingham, Alabama). Mr. Hutson has a B.S. degree in Accounting from Fairmont State College—West Virginia and received a CPA license (Ohio).

Bradley G. Gray has served as our Executive Vice President, Chief Operating Officer since October 2016. Mr. Gray also serves on our board of directors. Prior to joining us, Mr. Gray served as the Senior Vice President and Chief Financial Officer for Royal Cup, Inc. from August 2014 to October 2016. Prior to that, from 2006 to 2014, Mr. Gray served in various roles at The McPherson Companies, Inc., most recently as Executive Vice President and Chief Financial Officer from September 2006 to December 2013. Mr. Gray previously worked in various financial and operational roles at Saks Incorporated from 1997 to 2006. Mr. Gray has a B.S. degree in Accounting from the University of Alabama and was formerly a licensed CPA (Alabama).

Eric Williams has served as our Executive Vice President, Chief Financial Officer since July 2017. Prior to joining us, Mr. Williams served in various roles at Callon Petroleum Company since March 2010, most recently as Director of Investor Relations & Finance from December 2013 to July 2017. Prior to that, Mr. Williams served as the Assistant Controller/Director of Financial Reporting at Pinnacle Airlines, Corp.

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from 2006 to 2010. Mr. Williams began his career as an associate at PricewaterhouseCoopers in 2001. Mr. Williams has since served in various roles including internal audit and compliance, investor relations and financial reporting. Mr. Williams has a B.S. degree in Accounting from Samford University, a M.S. degree in Accounting from the University of Alabama and is a licensed CPA (Alabama).

James P. Rode has served as our Executive Vice President, Chief Commercial Officer since October 2018. Prior to joining us, Mr. Rode was the co-founder and served as the Chief Executive Officer and Chairman for Core Appalachia Holding Co LLC, which was acquired by us in 2018. Prior executive experience included roles as President and Chief Executive Officer of Core Minerals Operating Co., Inc., Vice President and General Counsel of Hercules Petroleum; General Counsel of EnTrade Corporation; co-founder and Executive Vice President, General Counsel and Director of InterEnergy Corporation and Business Development Consultant of MDU Resources. In addition to his executive tenure, Mr. Rode has served on the board of directors of the Kentucky Oil and Gas Association and the West Virginia Independent Oil and Gas Association and is a member of the Kentucky Bar Association. He received his J.D. from Gonzaga University School of Law and his B.B.A from the University of Kentucky.

Benjamin Sullivan has served as our Executive Vice President, General Counsel since 2019. Prior to joining us, Mr. Sullivan worked with Greylock Energy, LLC (an ArcLight Capital Partners portfolio company) and its predecessor, Energy Corporation of America, from 2012 to 2017, most recently as Executive Vice President, General Counsel and Corporate Secretary from 2017 to 2019. Prior to that, Mr. Sullivan served as counsel for EQT Corporation from 2006 to 2012. He is a member of the leadership and board of directors of several commerce, legal and industry groups, and has considerable experience in corporate governance and reporting/ESG, complex commercial transactions, land/real estate, acquisitions & divestitures, financing, government investigations and corporate workouts and restructurings. Mr. Sullivan received a B.A. from University of Kentucky and a J.D. degree from the West Virginia University College of Law. He holds licenses to practice law in Pennsylvania and West Virginia.

Non-Executive Directors

The following is a brief summary of the business experience of our non-executive directors.

David E. Johnson has served on our board of directors since April 2019. He has worked at a number of leading investment firms, as both an investment analyst and a manager, and more recently in equity sales and investment management. Mr. Johnson currently serves on the board of Chelverton Equity Partners, an AIM-listed holding company, where he serves as a member of the Remuneration, Audit and Nomination committees. Previously, Mr. Johnson was a consultant at Chelverton Asset Management from August 2016 to February 2019. Prior to that, he worked as a fund manager for the investment department a large insurance company. Mr. Johnson is a Fellow of the Chartered Institute for Securities and Investment, and earned a Bachelor of Arts in Economics from the University of Reading.

Martin K. Thomas has served on our board of directors since January 2015. Since January 2022, Mr. Thomas has served as a consultant at the law firm Wedlake Bell LLP, from where he was previously a Partner from January 2018 to December 2021. During his more than 30-year legal career, Mr. Thomas has also served as Partner of Watson Farley & Williams LLP from February 2015 to April 2017 and as consultant of the same firm from May 2017 to May 2018. Mr. Thomas earned a Bachelor of Laws from the University of Reading and completed his Law Society Final Examinations at The College of Law in the U.K.

David J. Turner, Jr. has served on our board of directors since May 2019. Mr. Turner has served as Chief Financial Officer of Regions Financial Corporation (NYSE: RF) since 2010 where he leads all finance operations, including mergers and acquisitions, financial systems, investor relations, corporate treasury, corporate tax, management planning and reporting and accounting. Prior to his appointment as Chief Financial Officer, Mr. Turner oversaw the Internal Audit Division for AmSouth Bank (which merged with Regions Financial Corporation in 2006) from April 2005 to March 2010 . He earned a Bachelor of Science in Accounting from the University of Alabama and attended Tulane University in Louisiana.

Sandra M. Stash has served on our board of directors since October 2019. Ms. Stash joined Tullow Oil in October 2013 serving as Executive Vice President of Safety, Operations and Engineering, and External Affairs where she served until March 2020. Ms. Stash is a Certified Director of the National Association of

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Corporate Directors and currently serves on the boards of Lucid Energy, Chaarat Gold Holdings Limited (AIM: CGH), Trans Mountain Company, Warriors and Quiet Water, International Women’s Forum, Colorado School of Mines Board of Governors, First Montana Bank and African Gifted Foundation. Ms. Stash earned a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines and is a Registered Professional Engineer.

Melanie A. Little has served on our board of directors since December 2019. Ms. Little currently serves as Senior Vice President, Operations and Environmental, Health, Safety and Security for Magellan Midstream Partners, L.P., and has served in this capacity since mid-2017. Prior to joining Magellan in 2004, she worked for The Williams Companies Inc. as Manager of Environmental Compliance. Ms. Little holds a Bachelor of Science in Environmental Engineering from the United States Military Academy and a Master of Science in Civil Engineering from the Georgia Institute of Technology. She also serves on two nonprofit boards: The Discovery Lab and the International Liquid Terminals Association.

Sylvia Kerrigan has served on our board of directors since October 2021. Currently, she is the Chief Legal Officer and Corporate Secretary at Occidental Petroleum Corporation (NYSE: OXY). She also serves as the Executive Director of the Kay Bailey Hutchinson Center for Energy, Law and Business at the University of Texas. In Ms. Kerrigan’s more than 20 years with Marathon Oil Corporation, she served in a number of roles overseeing public policy, legal and compliance, corporate positioning and external communications before retiring in 2017 after eight years as the Executive Vice President, General Counsel and Corporate Secretary. Ms. Kerrigan holds a Directorship Certification through the National Association of Corporate Directors. Ms. Kerrigan earned a Bachelor of Arts from Southwestern University and a Doctor of Jurisprudence from the University of Texas at Austin School of Law.

Board Diversity

The following matrix presents the diverse composition of our board of directors as of December 31, 2021:

	Country of Principal Executive Offices:			United States
	Foreign Private Issuer:			Yes
	Disclosure Prohibited under Home Country Law:			No
	Total Number of Directors:			8

Part I: Gender Identity

			Female						Male						Non-Binary						Did Not Disclose Gender
Directors					3						5						0						0

	Part II: Demographic Background
	Underrepresented Individual in Home Country Jurisdiction			—
	LGBTQ+			—
	Did Not Disclose Demographic Background			8

Family Relationships

There are no family relationships among any of our executive officers or directors.

Corporate Governance Practices and Foreign Private Issuer Status

Companies listed on the must comply with the corporate governance standards provided under of the . As a “foreign private issuer,” as defined by the SEC, we will be permitted to follow home country corporate governance practices, instead of certain corporate governance practices required by the for U.S. domestic issuers, except that we are required to comply with of the . Under , we must have an audit committee that meets the

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independence requirements of Rule 10A-3 under the Exchange Act. Under , we must disclose any significant ways in which their corporate governance practices differ from those followed by domestic companies under . Finally, under , we must promptly notify the in writing after becoming aware of any non-compliance with any applicable provisions of and must annually make a written affirmation to the . Further, a listed company must disclose in its annual financial report a statement of how the listed company has applied the principles set out in the UK Corporate Governance Code, in a manner that would enable shareholders to evaluate how the principles have been applied, and a statement as to whether the listed company has (a) complied throughout the accounting period with all relevant provisions set out in the UK Corporate Governance Code; or (b) not complied throughout the accounting period with all relevant provisions set out in the UK Corporate Governance Code and if so, setting out: (i) those provisions, if any it has not complied with; (ii) in the case of provisions whose requirements are of a continuing nature, the period within which, if any, it did not comply with some or all of those provisions; and (iii) the company’s reasons for non-compliance.

The table below briefly describes the significant differences between our UK corporate governance practices and the corporate governance rules.

Section	Corporate Governance Rules	UK Corporate Governance Practices
	A listed company must have a majority of independent directors.	At least half the board of a listed company, excluding the chair, should be non-executive directors whom the board considers to be independent.
	No director qualifies as “independent” unless the board of directors affirmatively determines that the director has no material relationship with the listed company (whether directly or as a partner, shareholder or officer of an organization that has a relationship with the company).	The board of a listed company should identify in the annual report each non-executive director it considers to be independent. Circumstances which are likely to impair, or could appear to impair, a non-executive director’s independence include, but are not limited to, whether a director: • is or has been an employee of the company or group within the last five years; • has, or has had within the last three years, a material business relationship with the company, either directly or as a partner, shareholder, director or senior employee of a body that has such a relationship with the company; • has received or receives additional remuneration from the company apart from a director’s fee, participates in the company’s share option or a performance-related pay scheme, or is a member of the company’s pension scheme; • has close family ties with any of the company’s advisers, directors or senior employees; • holds cross-directorships or has significant links with other directors through involvement in other companies or bodies; • represents a significant shareholder; or • has served on the board for more than

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Section	Corporate Governance Rules	UK Corporate Governance Practices
		nine years from the date of their first appointment. Where any of these or other relevant circumstances apply, and the board nonetheless considers that the non-executive director is independent, a clear explanation should be provided.
	The non-management directors of a listed company must meet at regularly scheduled executive sessions without management. If a listed company chooses to hold regular meetings of all non-management directors, such listed company should hold an executive session including only independent directors at least once a year.	The chair of the board of a listed company should hold meetings with the non-executive directors without the executive directors present and the annual report should set out the number of meetings of the board and its committees, and the individual attendance by directors. Further, the board should appoint one of the independent non-executive directors to be the senior independent director to provide a sounding board for the chair and serve as an intermediary for the other directors and shareholders. Led by the senior independent director, the non-executive directors should meet without the chair present at least annually to appraise the chair’s performance, and on other occasions as necessary.
	A listed company must have a nominating/corporate governance committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties.	A listed company should establish a nomination committee. A majority of members of the committee should be independent non-executive directors. The chair of the board should not chair the committee when it is dealing with the appointment of their successor.
	A listed company must have a compensation committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties.	A listed company should establish a remuneration committee of independent non-executive directors, with a minimum membership of three. In addition, the chair of the board can only be a member if they were independent on appointment and cannot chair the committee. Before appointment as chair of the remuneration committee, the appointee should have served on a remuneration committee for at least 12 months.
	A listed company must have an audit committee with a minimum of three independent directors who satisfy the independence requirements of Exchange Act Rule 10A-3, with a written charter that covers certain minimum specified duties. As a foreign private issuer, we are required to comply with , where we must have an audit committee that satisfies the requirements of Exchange Act Rule 10A-3. However, does not mandate a	A listed company should establish an audit committee of independent non-executive directors, with a minimum membership of three. The chair of the board should not be a member. The board should satisfy itself that at least one member has recent and relevant financial experience. The committee as a whole shall have competence relevant to the sector in which the company operates.

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Section	Corporate Governance Rules	UK Corporate Governance Practices
	minimum number of audit committee members for foreign private issuers.
	Shareholders must be given the opportunity to vote on all equity-compensation plans and material revisions thereto, with limited exemptions set forth in the rules.	A listed company must obtain approval for it, or any of its major subsidiary undertakings (whether or not incorporated in the UK), to implement an employees’ share scheme that involves or may involve the issue of new shares or the transfer of treasury shares or a long term incentive scheme in which one or more directors of the listed company is eligible to participate.
	A listed company must adopt and disclose corporate governance guidelines that cover certain minimum specified subjects.	The UK Corporate Governance Code applies to all companies with a premium listing, whether they are incorporated in the UK or elsewhere and it provides that a company must disclose specified information in its annual financial report to comply with certain provisions of the UK Corporate Governance Code.
	A listed company must adopt and disclose a code of business conduct and ethics for directors, officers and employees, and promptly disclose any waivers of the code for directors or executive officers. To the extent that a listed company’s board or a board committee determines to grant any waiver of the code of business conduct and ethics for an executive officer or director, the waiver must be disclosed to shareholders within four business days of such determination. We may choose not to disclose the waiver in the manner set forth in the corporate governance listing standards.	There is no requirement under UK law for a listed company to adopt a code of business conduct and ethics; we do not currently have a code of business conduct and ethics although may in the future chose to adopt one.
	(a) Each listed company CEO must certify to the each year that he or she is not aware of any violation by the company of corporate governance listing standards. (b) Each listed company CEO must promptly notify the in writing after any executive officer of the listed company becomes aware of any non-compliance with any applicable provisions of . (c) Each listed company must submit an executed Written Affirmation annually to the . In addition, each listed company must submit an interim Written Affirmation as and when required by the interim Written Affirmation form specified by the .

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Section			Corporate Governance Rules			UK Corporate Governance Practices
			As a foreign private issuer, we are required to comply with .

Further, we do not intend to follow of the , which requires shareholder approval in order to enter into any transaction, other than a public offering for cash or any other financing in which the Company is selling securities for cash, if such financing involves a sale of common stock, or securities convertible into or exercisable for common stock, at a price at least as great as the common stock’s official closing price or the average official closing price for the five trading days immediately preceding entry into the binding agreement (the “Minimum Price”); provided that if the securities in such financing are issued in connection with an acquisition of the stock or assets of another company, shareholder approval will be required if the issuance of such securities alone or when combined with any other present or potential issuance of common stock, or securities convertible into common stock in connection with such acquisition, is equal to or exceeds either 20% of the number of shares of common stock or 20% of the voting outstanding before the issuance. We will follow UK law with respect to any requirement to obtain shareholder approval in connection with any private placements of equity securities.

We intend to take all actions necessary for us to maintain compliance as a foreign private issuer under the applicable corporate governance requirements of the SEC and the listing standards of the . We may in the future decide to use other foreign private issuer exemptions with respect to some or all of the other corporate governance rules.

Because we are a foreign private issuer, our directors and senior management are not subject to short-swing profit and insider trading reporting obligations under Section 16 of the Exchange Act. They will, however, be subject to the obligations to report changes in share ownership under Section 13 of the Exchange Act and related SEC rules.

Composition of our Board of Directors

Our board of directors is composed of eight members, and upon the closing of this offering will continue to be composed of eight members. As a foreign private issuer, under the listing requirements and rules of the , we are not required to have independent directors on our board of directors, except that our audit committee is required to consist fully of independent directors, subject to certain phase-in schedules. Our board of directors currently consists of eight members. Our board of directors has determined that five of our eight directors do not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of director and that each of these directors is “independent” as that term is defined under the rules of the .

Committees of our Board of Directors

Our board of directors has four standing committees: an Audit and Risk Committee, a Remuneration Committee, a Nomination Committee and a Sustainability and Safety Committee. Each of these committees will be governed by a charter that is consistent with applicable UK law, as well as SEC and corporate governance rules, effective upon the effectiveness of the registration statement of which this prospectus forms a part, and which will be available on the “About Us” section of our website at www.div.energy. Information contained on, or that can be accessed through, our website is not incorporated by reference into this prospectus, and you should not consider information on our website to be part of this prospectus.

Audit and Risk Committee

Under corporate governance rules, we are required to maintain an audit committee consisting of all independent directors, each of whom is financially literate and one of whom is designated as the audit and risk committee financial expert.

Our Audit and Risk Committee consists of Melanie A. Little, Sandra M. Stash and David J. Turner, Jr. Mr. Turner serves as the Chair of the Audit and Risk Committee. All members of our Audit and Risk Committee meet the requirements for financial literacy under the applicable rules and regulations of the SEC

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and the corporate governance rules. Our board of directors has determined that Mr. Turner is an “audit committee financial expert” as defined by the SEC rules and has the requisite financial experience as defined by the corporate governance rules.

Our board of directors has determined that each member of our audit committee is “independent” as such term is defined in Rule 10A-3(b)(1) under the Exchange Act, which is different from the general test for independence of board and committee members.

The Audit and Risk Committee charter will set forth the responsibilities of the Audit and Risk Committee consistent with UK law, the SEC rules and the corporate governance rules.

Upon completion of this offering, the Audit and Risk Committee will be responsible for, among other things:

•

reviewing accounting policies and the integrity and content of the financial statements;

•

monitoring disclosure controls and procedures and the adequacy and effectiveness of our internal financial control and risk management systems, including establishing procedures for the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls or auditing matters and the confidential submission by employees of concerns regarding questionable accounting or auditing matters;

•

monitoring, reviewing and discussing with the executive officers, the board and the independent auditor our financial statements and our financial reporting process;

•

reviewing and approving the statements to be included in annual reports on internal control and risk management;

•

the appointment, compensation, retention and oversight of any registered public accounting firm engaged for the purpose of preparing or issuing an audit report or performing other audit services;

•

pre-approving the audit services and non-audit services to be provided by our independent auditor before the auditor is engaged to render such services;

•

recommending the appointment of the independent auditor to the general meeting of shareholders;

•

evaluating the independent auditor’s qualifications, performance and independence, and presenting its conclusions to the full board on at least an annual basis;

•

engaging independent counsel and other advisors;

•

obtaining sufficient funding to pay external advisors; and

•

approving or ratifying any related person transaction (as defined in our related person transaction policy) in accordance with our related person transaction policy.

The Audit and Risk Committee will meet at least three times per year and at such other times as one or more members of the Audit and Risk Committee deem necessary and will meet at least once per year with our independent accountant, without our executive officers being present.

Remuneration Committee

Our Remuneration Committee consists of David E. Johnson, Melanie A. Little, Sandra M. Stash and Sylvia J. Kerrigan. Ms. Little serves as Chair of the Remuneration Committee. Under SEC and rules, there are heightened independence standards for members of the Remuneration Committee, including a prohibition against the receipt of any compensation from us other than standard board member and committee chair fees. Although foreign private issuers are not required to meet this heightened standard with respect to all members, as of the date of this prospectus, we have determined that all members meet this heightened standard.

The Remuneration Committee charter will set forth the responsibilities of the Remuneration Committee consistent with UK law, the SEC rules and the corporate governance rules.

Upon completion of this offering, the Remuneration Committee will be responsible for, among other things:

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•

identifying, reviewing, proposing and determining policies relevant to director compensation;

•

evaluating each executive officer’s performance in light of such policies and reporting to the board;

•

analyzing the possible outcomes of the variable remuneration components and how they may affect the remuneration of the executive officers;

•

recommending any equity long-term incentive component of each executive officer’s compensation in line with the remuneration policy and reviewing our executive officer compensation and benefits policies generally; and

•

reviewing and assessing risks arising from our compensation policies and practices.

The Remuneration Committee will meet at least two times per year and at such other times as deemed necessary.

Nomination Committee

Our Nomination Committee consists of David E. Johnson, Sylvia Kerrigan, David J. Turner, Jr. and Martin K. Thomas. Mr. Thomas serves as the Chair of the Nomination Committee.

The Nomination Committee charter will set forth the responsibilities of the Nomination Committee consistent with UK law, the SEC rules and the corporate governance rules.

Upon completion of this offering, the Nomination Committee will be responsible for, among other things:

•

drawing up selection criteria and appointment procedures for directors;

•

reviewing and evaluating the size and composition of our board of directors and making a proposal for a composition profile of the board of directors;

•

recommending nominees for election to our board of directors and its corresponding committees;

•

succession planning for directors;

•

assessing the functioning of individual members of board of directors and executive officers and reporting the results of such assessment to the board; and

•

developing and recommending to the board of directors rules governing the board, reviewing and reassessing the adequacy of such rules governing the board and recommending any proposed changes to the board of directors.

The Nomination Committee will meet at least two times per year and at such other times as deemed necessary.

Sustainability and Safety Committee

Our Sustainability and Safety Committee consists of David E. Johnson, Bradley G. Gray, Melanie A. Little and Sandra M. Stash. Ms. Stash serves as the Chair of the Sustainability and Safety Committee. Our board of directors has adopted a Sustainability and Safety Committee charter setting forth the responsibilities, which include:

•

overseeing the development and implementation by management of policies, compliance systems and monitoring processes to ensure compliance with applicable legislation, rules and regulations;

•

establishing with management long-term climate, environmental and social sustainability, EHS goals and evaluating our progress against those goals;

•

considering and advising management of emerging environmental and social sustainability issues;

•

monitoring our risk management processes related to environmental and social sustainability; and

•

reviewing handling of incident reports, results of investigations into material events, findings from environmental and social sustainability EHS audits and the action plans proposed pursuant to those findings.

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The Sustainability and Safety Committee will meet at least two times per year and at such other times as deemed necessary.

Share Dealing Code

The Company has adopted a code of securities dealings in relation to the ordinary shares which complies with the UK version of Market Abuse Regulation (No 2014/596/EC) as it forms part of UK law by virtue of the European Union (Withdrawal) Act 2018, as amended from time to time. Such code applies to the directors and other relevant employees of the Company.

Code of Business Conduct and Ethics

In connection with this offering, we plan to adopt a Code of Business Conduct and Ethics (“Code of Ethics”), applicable to our and our subsidiaries’ employees, independent contractors, executive officers and directors, including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. Following the effectiveness of the registration statement of which this prospectus forms a part, a current copy of the Code of Ethics will be posted on our website, which is located at www.div.energy. Information contained on, or that can be accessed through, our website does not constitute a part of this prospectus and is not incorporated by reference herein.

Compensation of Executive Directors

For the year ended December 31, 2021, the aggregate compensation paid to the members of our board of directors and our executive officers for services in all capacities was approximately $4 million. This amount includes the following compensation paid to our executive directors:

Name	Base Salary			Annual Bonus			Non-Equity Incentive Plan Compensation			All Other Compensation			Total
	(Amounts rounded to the nearest thousand)
Executive Directors
Robert Russell (“Rusty”) Hutson, Jr.		$	693,000		$	884,000		$	45,000		$	573,000		$	2,195,000
Bradley G. Gray		$	426,000		$	543,000		$	49,000		$	262,000		$	1,280,000

Executive Director Employment Agreements

We have entered into written service agreements with each of our executive officers. Each of these agreements contains provisions regarding non-competition, non-solicitation, confidentiality of information and intellectual property.

Robert Russell (“Rusty”) Hutson, Jr.

We entered into a service agreement with Mr. Hutson on January 30, 2017. This agreement entitles Mr. Hutson to receive an initial annual base salary of $720,954 and an opportunity to earn an annual discretionary performance-based bonus of up to 175% of base salary, subject to the achievement of performance goals determined in accordance with our annual bonus plan. Mr. Hutson is also entitled to automobile benefits and to participate in all our employee benefit plans, programs or arrangements in which other employees located in the United States are eligible to participate in, which includes a matching contribution under our 401(k) plan.

Either party may terminate the employment agreement by giving the other party at least 6 months’ written notice, unless Mr. Hutson is terminated for cause (as described in Mr. Hutson’s service agreement) or we instead terminate Mr. Hutson with immediate effectiveness and make a payment in lieu of notice equal to his basic salary that he would otherwise be entitled to for the whole or any remaining notice period. Mr. Hutson can also be placed on garden leave for all or part of the remaining period of his employment once notice to terminate employment has been served. Mr. Hutson’s service agreement also contains restrictive covenants pursuant to which he has agreed to refrain from the following: (i) soliciting business from our

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key customers; (ii) carrying out business with our key customers; (iii) interfering with any of our key suppliers; (iv) soliciting any of our key employees; (v) employing or engaging any of our key employees; and (vi) competing with us, for a period of twelve months following termination of his employment.

Bradley G. Gray

We entered into a service agreement with Mr. Gray on January 30, 2017. This agreement entitles Mr. Gray to receive an initial annual base salary of $437,713 and an opportunity to earn an annual discretionary performance-based bonus of up to 150% of base salary, subject to the achievement of performance goals determined in accordance with our annual bonus plan. Mr. Gray is also entitled to automobile benefits and to participate in all our employee benefit plans, programs or arrangements in which other employees located in the United States are eligible to participate in,, which includes a matching contribution under our 401(k) plan.

Either party may terminate the employment agreement by giving the other party at least 6 months’ written notice, unless Mr. Gray is terminated for cause (as described in Mr. Gray’s service agreement) or we instead terminate Mr. Gray with immediate effectiveness and make a payment in lieu of notice equal to his basic salary that he would otherwise be entitled to for the whole or any remaining notice period. Mr. Gray can also be placed on garden leave for all or part of the remaining period of his employment once notice to terminate employment has been served. Mr. Gray is also entitled to a severance payment equal to 6 months’ salary in equal monthly instalments if he is terminated in certain circumstances, subject to Mr. Gray entering into a general release. Mr. Gray’s service agreement also contains restrictive covenants pursuant to which he has agreed to refrain from the following: (i) soliciting business from our key customers; (ii) carrying out business with our key customers; (iii) interfering with any of our key suppliers; (iv) soliciting any of our key employees; (v) employing or engaging any of our key employees; and (vi) competing with us, for a period of twelve months following termination of his employment.

Equity Compensation Arrangements

2017 Equity Incentive Plan

Our board of directors adopted the Diversified Gas & Oil plc 2017 Equity Incentive Plan on January 30, 2017, which was amended and restated on March 29, 2021 (as amended, the “2017 Equity Incentive Plan”). Under the 2017 Equity Incentive Plan the Company offers incentives to employees and executive directors. Awards granted under the 2017 Equity Incentive Plan are administered by the board of directors (or duly constituted committee thereof), which are also responsible for, among other things, construing and interpreting the 2017 Equity Incentive Plan. Subject to certain conditions, a total of up to 65,680,609 new ordinary shares of the Company are or shall be, from time to time, available to satisfy awards under the 2017 Equity Incentive Plan. Shares available for distribution under the Equity Incentive may consist, in whole or in part, of authorized and unissued shares, treasury shares or shares reacquired by the Company in any manner. The 2017 Equity Incentive Plan provides for the potential award of two types of share option awards: incentive stock options and non-qualified stock options. The 2017 Equity Incentive Plan sets out eligibility conditions that must be followed, including that incentive stock options are only to be granted to employees and each award granted under the 2017 Equity Incentive Plan must be evidenced by an award agreement. The 2017 Equity Incentive Plan also provides for other awards consisting of stock appreciation rights, restricted awards, performance share awards and performance compensation awards. Performance compensation awards may take the form of a cash bonus, a portion of which may be deferred through the grant of restricted stock units. Award levels are determined each year by the Remuneration Committee. An award may not be granted to an individual if such grant would cause the aggregate total market value (as measured at the respective dates of grant) of the maximum number of shares that may be acquired on realization of the individual’s 2017 Equity Incentive Plan awards in relation to the same financial year to exceed 200% of the individual’s base salary at the date of grant. The vesting of awards granted to executive directors and other senior employees is normally dependent upon the satisfaction of stretching performance conditions that are appropriate to the strategic objectives of the Company. If the Remuneration Committee so determines upon the grant of certain types of awards, the number of shares under an award may be increased to account for dividends paid on any vesting shares in the period between grant and vesting (or such other period as the Remuneration Committee may determine). Alternatively, participants may receive

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a cash sum equal to the value of dividends paid on any vesting shares in the relevant period. Where appropriate, awards under the 2017 Equity Incentive Plan are granted subject to the Company’s policy relating to malus and clawback and post-vesting holding periods. In any 10-year period, the Company may not grant awards under the 2017 Equity Incentive Plan if such grant would cause the number of shares that could be issued under the 2017 Equity Incentive Plan or any other share plan adopted by the Company or any other company under the Company’s control on or after our admission on the LSE to exceed 10% of the Company’s issued ordinary share capital at the proposed date of grant. The 2017 Equity Incentive Plan is governed by the laws of the State of Alabama.

The following table summarizes the number of outstanding shares and options granted to executive directors and non-executive directors, as of March 31, 2022:

Name	Performance Stock Units		Stock Options		Exercise Price Per Ordinary Share (in £)	Grant Date	Expiration Date (if applicable)	Plan Name
Executive Director
Robert Russell (“Rusty”) Hutson, Jr.		—		5,800,000	£0.84	04/14/2018	04/14/2028	2017 Equity Incentive Plan
		—		1,600,000	£1.20	05/09/2019	05/09/2029	2017 Equity Incentive Plan
		1,699,011		—	n/a	06/23/2020	n/a	2017 Equity Incentive Plan
		832,653		—	n/a	03/15/2021	n/a	2017 Equity Incentive Plan
		1,402,038		—	n/a	03/15/2022	n/a	2017 Equity Incentive Plan
Bradley G. Gray		—		1,741,667	£0.84	04/14/2018	04/14/2028	2017 Equity Incentive Plan
		—		733,333	£1.20	05/09/2019	05/09/2029	2017 Equity Incentive Plan
		1,044,577		—	n/a	06/23/2020	n/a	2017 Equity Incentive Plan
		511,927		—	n/a	03/15/2021	n/a	2017 Equity Incentive Plan
		718,328		—	n/a	03/15/2022	n/a	2017 Equity Incentive Plan
Non-Executive Directors
David E. Johnson		—		—
Martin K. Thomas		—		—
David J. Turner, Jr		—		—
Sandra M. Stash		—		—
Melanie A. Little		—		—
Sylvia J. Kerrigan		—		—

Non-Executive Director Compensation

Directors’ Compensation Policy

The aggregate fees and any benefits of the Chairman of the Board and non-executive directors will not exceed the limit from time to time prescribed within the Company’s Articles of Association for such fees which is currently £950,000 per annum.

The following table sets forth the compensation paid during 2021 to the current non-executive directors, all of which was in the form of annual fees:

Name	Compensation
	(Amounts in $)
David E. Johnson		168,000
Martin K. Thomas		127,000
David J. Turner, Jr.		134,000

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Name	Compensation
	(Amounts in $)
Sandra M. Stash		127,000
Melanie A. Little		127,000
Sylvia J. Kerrigan(1)		22,000

(1)

Appointed to the board of directors October 1, 2021.

In addition, non-executive directors are reimbursed all necessary and reasonable expenses incurred in connection with the performance of their duties and any tax thereon in accordance with the Company’s Non-Executive Director Expense Reimbursement Policy.

Non-Executive Director Appointment Letters

We review our fee structure for non-executive directors on an annual basis and determine compensation based on, among other things, a review of current practices in other companies. We have entered into appointment letters with each of our non-executive directors for their services, which are for an initial period of 12 months, subject to re-election at each annual general meeting of the Company and are terminable subject to a three-month notice period.

Pension, Retirement or Similar Benefits

Our executive officers are entitled to matching contributions from us of up to $27,000 per annum into their 401(k) retirement plans. They also receive a range of core benefits such as life insurance, private medical coverage and annual health screens.

Insurance and Indemnification

To the extent permitted by the Companies Act 2006, we are empowered to indemnify our directors against any liability they incur by reason of their directorship. We maintain directors’ insurance to insure such persons against certain liabilities. We have entered into a deed of indemnity with each of our directors.

Further, we provide our directors with directors’ liability insurance. Insofar as indemnification of liabilities arising under the Securities Act may be permitted to our board of directors or persons controlling us pursuant to the foregoing provisions, we have been informed that, in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

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PRINCIPAL SHAREHOLDERS

The following table sets forth information relating to the beneficial ownership of our ordinary shares as of , 2022 and after this offering by:

•

each person, or group of affiliated persons, known by us to beneficially own 5% or more of our outstanding ordinary shares;

•

each of our directors and executive officers individually; and

•

all of our directors and executive officers as a group.

The number of ordinary shares beneficially owned by each entity, person, executive officer or board member is determined in accordance with the rules of the SEC, and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares over which the individual has sole or shared voting power or investment power as well as any shares that the individual has the right to acquire within 60 days of , 2022 through the exercise of any option, restricted stock unit (“RSU”), performance stock units (“PSU”), warrant or other right. Except as otherwise indicated, and subject to applicable community property laws, the persons named in the table have sole voting and investment power with respect to all ordinary shares held by that person.

The percentage of shares beneficially owned before the offering is computed on the basis of of our ordinary shares outstanding as of , 2022. The percentage of shares beneficially owned after the offering is based on the number of our ordinary shares to be outstanding after this offering and assumes no exercise of the underwriter’s option to purchase additional ADSs from us. Ordinary shares that a person has the right to acquire within 60 days of , 2022 are deemed outstanding for purposes of computing the percentage ownership of the person holding such rights, but are not deemed outstanding for purposes of computing the percentage ownership of any other person, except with respect to the percentage ownership of all executive officers and management and supervisory directors as a group. Unless otherwise indicated below, the address for each beneficial owner listed is c/o Diversified Energy Company plc, 1600 Corporate Drive, Birmingham, Alabama 35242.

A description of any material relationship that our principal shareholders have had with us or any of our affiliates within the past three years is included under the section titled “Related Party Transactions.”

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Name of beneficial owner

Number of
ordinary shares
beneficially
owned before the
offering

Percentage of ordinary shares
beneficially owned

Before offering

After
offering

5% or Greater Shareholders

M&G Investment Management Ltd(1)

Abrdn Investment Management Ltd(2)

JO Hambro Capital Management Ltd(3)

BlackRock(4)

GLG Partners LP(5)

AXA Framlington Investment Managers(6)

Pelham Capital Management LLP(7)

Executive Officers and Directors

Robert Russell (“Rusty”) Hutson, Jr

Bradley J. Gray

James P. Rode

Eric Williams

Benjamin Sullivan

Martin K. Thomas

David Johnson

David J. Turner, Jr.

Melanie A. Little

Sylvia J. Kerrigan

Sandra M. Stash

All executive officers and directors as a group (11 persons)

��

Indicates ownership of less than 1%.

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RELATED PARTY TRANSACTIONS

The following is a description of transactions we have entered into since January 1, 2019 with any of our directors or executive officers and the holders of more than 5% of our ordinary shares.

Martin K. Thomas, a member of our board of directors, is a partner at Wedlake Bell LLP (“Wedlake Bell”), the former UK legal advisor to the Company. During the years ended December 31, 2019, 2020, and 2021, the Company paid fees in the amounts of $195,000, $41,000 and $0, respectively, to Wedlake Bell.

Transactions with Our Executive Officers and Directors

For a description of our other agreements with our directors and executive officers, please see the subsections titled “Management—Compensation of Executive Directors—Executive Director Employment Agreements” and “Management—Compensation of Executive Directors—Non-Executive Director Appointment Letters.”

Indemnification Agreements

We have entered into indemnification agreements with our directors and executive officers. Our Articles of Association allow us to indemnify our directors to the fullest extent permitted by law, subject to certain exceptions. See the subsection titled “Management—Insurance and Indemnification” for a description of these indemnification agreements.

Related Party Transaction Policy

Prior to the completion of this offering, our board of directors plans to adopt a written related person transaction policy to set forth the policies and procedures for the review and approval or ratification of related person transactions.

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DESCRIPTION OF SHARE CAPITAL AND ARTICLES OF ASSOCIATION

The following is a description of the material terms of our Articles of Association as they will be in effect upon the closing of this offering. The following description may not contain all of the information that is important to you, and we therefore refer you to our Articles of Association, a copy of which is filed with the SEC as an exhibit to the registration statement of which this prospectus forms a part.

General

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 4th Floor Reading Bridge House, George Street, Reading, Berkshire, United Kingdom, RG1 8LS. The principal legislation under which we operate and our shares are issued is the Companies Act 2006.

As of December 31, 2021, our issued share capital amounted to $11,571,240, represented by 849,654,653 ordinary shares with a nominal value of £0.01 per share. All issued ordinary shares are fully paid.

As of June 30, 2022, there were approximately 496 holders of record of our ordinary shares, which does not include beneficial owners holding our securities through nominee names.

Ordinary Shares

In accordance with our Articles of Association, the following summarizes the rights of holders of our ordinary shares:

•

each holder of our ordinary shares is entitled to one vote per ordinary share on all matters to be voted on by shareholders generally;

•

the holders of the ordinary shares shall be entitled to receive notice of, attend, speak and vote at our general meetings; and

•

holders of our ordinary shares are entitled to receive such dividends as are recommended by our board of directors and declared by our shareholders.

Registered Shares

We are required by the Companies Act 2006 to keep a register of our shareholders. Under UK law, the ordinary shares are deemed to be issued when the name of the shareholder is entered in our share register. The share register is therefore prima facie evidence of the identity of our shareholders and the shares that they hold. The share register generally provides limited, or no, information regarding the ultimate beneficial owners of our ordinary shares. Our share register is maintained by our registrar, Computershare Investor Services PLC.

Holders of our ADSs will not be treated as one of our shareholders, and their names will therefore not be entered in our share register. The depositary, the custodian or their nominees will be the holder of the ordinary shares underlying our ADSs. For discussion on our ADSs and ADS holder rights see the section titled “Description of American Depositary Shares” in this prospectus. Holders of our ADSs have a right to receive the ordinary shares underlying their ADSs as discussed in the section titled “Description of American Depositary Shares” in this prospectus.

Under the Companies Act 2006, we must enter an allotment of shares in our share register as soon as practicable and in any event within two months of the allotment. We will perform all procedures necessary to update the share register to reflect the ordinary shares being sold in this offering, including updating the share register with the number of ordinary shares to be issued to the depositary upon the closing of this offering. We are also required by the Companies Act 2006 to register a transfer of shares (or give the transferee notice of and reasons for refusal) as soon as practicable and in any event within two months of receiving notice of the transfer.

We, any of our shareholders or any other affected person may apply to the court for rectification of the share register if:

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•

the name of any person, without sufficient cause, is wrongly entered in or omitted from our register of shareholders; or

•

there is a default or unnecessary delay in entering on the register the fact of any person having ceased to be a shareholder or on whose shares we have a lien, provided that such refusal does not prevent dealings in the shares taking place on an open and proper basis.

Preemptive Rights

UK law generally provides shareholders with preemptive rights when new shares are issued for cash; however, it is possible for a company’s articles of association, or shareholders in general meeting, to exclude preemptive rights. Such an exclusion of preemptive rights may be for a maximum period of up to five years from the date of adoption of the articles of association, if the exclusion is contained in the articles of association, or from the date of the shareholder resolution, if the exclusion is by shareholder resolution. In either case, this exclusion would need to be renewed by the company’s shareholders upon its expiration (i.e., at least every five years).

On April 26, 2022, our shareholders approved the exclusion of preemptive rights, with such authority expiring at the conclusion of our next annual general meeting or, if earlier, June 30, 2023. Such exclusion will need to be renewed upon expiration (i.e., on the conclusion of our next annual general meeting or, if earlier, June 30, 2023) to remain effective, but may be sought more frequently for additional five-year terms (or any shorter period). We intend to obtain authority from our shareholders to disapply preemptive rights for the allotment of ordinary shares, including in connection with this offering. This disapplication will be effective until the conclusion of the next annual general meeting of the Company.

Options

As of December 31, 2021, there were options to purchase 21,886,666 ordinary shares outstanding with a weighted average exercise price of $0.43 per share. These options lapse after ten years from the date of the grant.

Articles of Association

Shares and Rights Attaching to Them

Objects

The objects of our Company are unrestricted.

Rights Attached to Shares

Subject to the Companies Act 2006 and to the rights conferred on the holders of any other shares, any share may be issued with or have attached to it such rights and restrictions as the Company may by ordinary resolution decide or, if no such resolution is in effect or so far as the resolution does not make specific provision, as the board of directors may decide.

Voting Rights

Subject to the provisions of the Companies Act 2006 and any restrictions imposed in our Articles of Association and any rights or restrictions attached to any class of shares of our share capital, on a resolution, on a show of hands:

•

every shareholder present in person shall have one vote;

•

each proxy present who has been duly appointed by one or more shareholders entitled to vote on the resolution has one vote unless the proxy has been appointed by more than one shareholder entitled to vote on the resolution in which case: (i) where the proxy has been instructed by one or more of such shareholders to vote for the resolution and by one or more of such shareholders to vote against the resolution the proxy has one vote for and one vote against the resolution; or (ii) where the proxy has been instructed by, or exercises his discretion given by, one or more of those shareholders to vote for the resolution and has been instructed by, or exercises his discretion given

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by, one or more other of those shareholders to vote against it, a proxy has one vote for and one vote against the resolution; and

•

each person authorized by a corporation to exercise voting powers on behalf of the corporation is entitled to exercise the same voting powers as the corporation would be entitled to unless a corporation authorizes more than one person, in which case: (i) if more than one person authorized by the same corporation purport to exercise the power to vote on a show of hands in respect of the same shares in the Company and exercise the power in the same way as each other, the power is treated as exercised in that way; or (ii) if more than one person authorized by the same corporation purports to exercise the power to vote on a show of hands in respect of the same shares in the Company, and they do not exercise the power in the same way as each other, the power is treated as not exercised.

Subject to the provisions of the Companies Act 2006 and any restrictions imposed by our Articles of Association and any rights or restrictions attached to any class of shares of our share capital, on a vote on a resolution on a poll, every shareholder present shall have one vote for every ordinary share in our share capital held by him or his appointee, or and if entitled to more than one vote need not, if he votes, use all his votes or cast all his votes in the same way.

At a general meeting a resolution put to the vote of the meeting shall be decided on a show of hands, unless (before, or immediately after the declaration of the result of, the show of hands or on the withdrawal of any other demand for a poll) a poll is demanded by:

•

the chairman of the meeting;

•

at least five shareholders present in person or by proxy having the right to vote on the resolution; or

•

a shareholder or shareholders present in person or by proxy representing in aggregate not less than 10% of the total voting rights of all the shareholders having the right to vote on the resolution (excluding any voting rights attached to any shares in the Company held as treasury shares); or

•

a shareholder or shareholders present in person or by proxy holding shares conferring the right to vote on the resolution on which an aggregate sum has been paid up equal to not less than 10% of the total sum paid up on all the shares conferring that right (excluding shares in the Company conferring a right to vote on the resolution which are held as treasury shares),

and a demand for a poll by a person as proxy for a shareholder shall be as valid as if the demand were made by the shareholder himself.

Restrictions on Voting

Subject to the board of directors’ ability to decide otherwise, no shareholder shall be entitled to be present or to be counted in the quorum or vote, either in person or by proxy, at any general meeting or at any separate class meeting of the holders of a class of shares or on a poll or to exercise other rights conferred by the shareholders in relation to the meeting or poll, unless all calls or other monies due and payable in respect of the shareholder’s shares have been paid up.

The board of directors may from time to time make calls upon the shareholders in respect of any money unpaid on their shares and each shareholder shall (subject to at least 14 clear days’ notice specifying the time or times and place of payment) pay at the time or times so specified the amount called on their shares.

If a shareholder or a person appearing to be interested in shares held by that shareholder has been issued with a notice under section 793 of the Companies Act 2006 (“Section 793 Notice”) by the Company and has failed in relation to those shares (“Default Shares” which expression includes any shares issued after the date of such notice in right of those shares) and has failed to respond to the Section 793 Notice by not providing the information required within 14 days following the date of service of the notice, the shareholder holding the Default Shares shall not be entitled in respect of the Default Shares to be present or to vote (either in person or representative or proxy) at a general meeting or a separate meeting of the holders of the same class of shares, or on a poll or to exercise other rights conferred by virtue of being a shareholder of

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the Company. The restriction on voting shall cease to apply: (i) if the shares are transferred by means of an excepted transfer but only in respect of the shares transferred; or (ii) at the end of the period of seven days (or such shorter period as the board of directors may determine) following receipt by the Company of the information required by the Section 793 Notice and the board of directors being fully satisfied that such information is full and complete.

Dividends

The Company may, by ordinary resolution, declare a dividend to be paid to the shareholders, according to their respective rights and interests in the profits, and may fix the time for payment of such dividend, but no dividend shall exceed the amount recommended by the board of directors.

The board of directors may pay such interim dividends as appear to the board of directors to be justified by the financial position of the Company and may also pay any dividend payable at a fixed rate at intervals settled by the board of directors whenever the financial position of the Company, in the opinion of the board of directors, justifies its payment. If the board of directors acts in good faith, none of the directors shall incur any liability to the holders of shares conferring preferred rights for any loss such holders may suffer in consequence of the payment of an interim dividend on any shares having nonpreferred or deferred rights.

No dividend will be payable except out of profits of the Company available for distribution in accordance with the provisions of the Companies Act 2006, or in excess of the amount recommended by the board of directors. If, in the opinion of the board of directors, the profit of the Company justifies such payments, the board of directors may: (i) pay the fixed dividends on any class of shares carrying a fixed dividend expressed to be payable on fixed dates on the half-yearly or other dates prescribed for payment; and (ii) pay interim dividends of such amounts and on such dates as it thinks fit.

Subject to the provisions of the Companies Act 2006 and except as otherwise provided by our Articles of Association or by the rights or privileges attached to any shares carrying a preferential or special rights to dividends, Company profits will be used to pay dividends on shares and all dividends shall be declared and paid according to the amounts paid up on the shares and shall be apportioned and paid pro rata according to the amounts paid up on the shares during any part of the period in respect of which the dividend is paid.

No dividend or other monies payable by us on or in respect of any share shall bear interest against us. Any dividend unclaimed or retained in accordance with our Articles of Association after a period of 12 years from the date such dividend became due for payment will be forfeited and revert to us. The payment of any unclaimed dividend, interest or other sum payable by the Company on or in respect of any share into a separate account shall not constitute the Company a trustee in respect of it.

Dividends may be declared or paid in any currency. The board of directors may agree with any shareholder that dividends which may at any time or from time to time be declared or become due on his shares in one currency shall be paid or satisfied in another, and may agree the basis of conversion to be applied and how and when the amount to be paid in the other currency shall be calculated and paid and for the Company or any other person to bear any costs involved.

Upon the recommendation of the board of directors and with the sanction of an ordinary resolution of the Company, all or any part of the dividend can be paid by the distribution of specific assets and the board of directors must give effect to such ordinary resolution. With the sanction of an ordinary resolution of the Company, the board of directors may offer any holders of ordinary shares the right to elect to receive in lieu of a dividend an allotment of ordinary shares credited as fully paid up, instead of or part of a cash dividend, subject to such exclusions or arrangements as the board of directors may deem necessary or expedient.

Change of Control

There is no specific provision in our Articles of Association that would have the effect of delaying, deferring or preventing a change of control.

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Distributions on Winding Up

If the Company is in liquidation, the liquidator may, with the authority of a special resolution of the Company and any other authority required by the Companies Act 2006:

•

divide among the shareholders in specie the whole or any part of the assets of the Company and, for that purpose, value any assets and determine how the division shall be earned out as between the shareholders or different classes of shareholders; or

•

vest the whole or any part of the assets in trustees upon such trusts for the benefit of shareholders as the liquidator, with the like sanction, shall think fit but no shareholder shall be compelled to accept any assets upon which there is any liability.

Variation of Rights

Whenever the share capital of the Company is divided into different classes of shares, all or any of the rights for the time being attached to any class of shares in issue may from time to time (whether or not the Company is being wound up) be varied in such manner as those rights may provide or (if no such provision is made) either with the consent in writing of the holders of three-fourths in nominal value of the issued shares of that class or with the authority of a special resolution passed at a separate general meeting of the holders of those shares. The Companies Act 2006 provides a right to object to the variation of the share capital by the shareholders who did not vote in favor of the variation. Should an aggregate of 15% of the shareholders of the issued shares in question apply to the court to have the variation cancelled, the variation shall have no effect unless and until it is confirmed by the court.

Unless otherwise expressly provided by the rights attached to any class of shares those rights shall not be deemed to be varied by the creation or issue of further shares ranking pari passu with them or by the purchase or redemption by the Company of any of its own shares.

Alteration to Share Capital

We may, by ordinary resolution of shareholders, consolidate and divide all or any of our share capital into shares of larger nominal value than our existing shares, or sub-divide our shares or any of them into shares of a smaller nominal value. We may, by special resolution of shareholders, confirmed by the court, reduce our share capital or any capital redemption reserve or any share premium account in any manner authorized by the Companies Act 2006. We may redeem or purchase all or any of our shares as described in the subsection titled “—Other UK Law Considerations—Purchase of Own Shares.”

Preemption Rights

In certain circumstances, our shareholders may have statutory preemption rights under the Companies Act 2006 in respect of the allotment of new shares as described in the subsection titled “—Preemptive Rights” above and the subsection titled “—Differences in Corporate Law—Preemptive Rights” below.

Transfer of Shares

Subject to the restrictions in the Articles of Association, a shareholder may transfer all or any of his shares in any manner which is permitted by the Companies Act 2006 and is from time to time approved by the board of directors.

An instrument of transfer of a certificated share may be in any usual form or in any other form which the board of directors may approve and shall be signed by or on behalf of the transferor and (except in the case of a fully paid share) by or on behalf of the transferee.

The board of directors may, in its absolute discretion refuse to register any instrument of transfer of a certificated share:

•

which is not fully paid up but, in the case of a class of shares which has been admitted to official listing by the UK Financial Conduct Authority, not so as to prevent dealings in those shares from taking place on an open and proper basis; or

•

on which the Company has a lien.

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The board of directors may also refuse to register any instrument of transfer of a certificated share unless it is:

•

left at the office, or at such other place as the board of directors may decide, for registration;

•

accompanied by the certificate for the shares to be transferred and such other evidence (if any) as the board of directors may reasonably require to prove the title of the intending transferor or his right to transfer the shares; and

•

in respect of only one class of shares.

All instruments of transfer which are registered may be retained by the Company, but any instrument of transfer which the board of directors refuses to register shall (except in any case where fraud or any other crime involving dishonesty is suspected in relation to such transfer) be returned to the person presenting it.

Shareholder Meetings

Annual General Meetings

In accordance with the Companies Act 2006, we are required in each year to hold an annual general meeting in addition to any other general meetings in that year and to specify the meeting as such in the notice convening it. The annual general meeting shall be convened whenever and wherever the board of directors sees fit, subject to the requirements of the Companies Act 2006, as described in the subsections titled “—Differences in Corporate Law—Annual General Meeting” and “—Differences in Corporate Law—Notice of General Meetings” below.

Notice of General Meetings

The arrangements for the calling of general meetings are described in the subsection titled “ —Differences in Corporate Law—Notice of General Meetings” below.

Quorum of General Meetings

No business shall be transacted at any general meeting unless a quorum is present. At least two shareholders present in person or by proxy and entitled to vote shall be a quorum for all purposes. If within 15 minutes from the time fixed for holding a general meeting a quorum is not present, the meeting, if convened on the requisition of shareholders, shall be dissolved. In any other case, it shall stand adjourned for ten clear days (or, if that day is a Saturday, a Sunday or a holiday, to the next working day) and at the same time and place, or electronic platform, as the original meeting, or, subject to article 36.4 of our Articles of Association and the Companies Act 2006, to such other day, and at such other time and place, or electronic platform, as the board of directors may decide. If at an adjourned meeting a quorum is not present within 15 minutes from the time fixed for holding the meeting, the meeting shall be dissolved.

Class Meetings

The provisions in our Articles of Association relating to general meetings apply to every separate general meeting of the holders of a class of shares except that:

•

the quorum for such class meeting shall be two holders in person or by proxy representing not less than one-third in nominal value of the issued shares of the class (excluding any shares held in treasury);

•

at the class meeting, a holder of shares of the class present in person or by proxy may demand a poll and shall on a poll be entitled to one vote for every share of the class held by him; and

•

if at any adjourned meeting of such holders a quorum is not present at the meeting, one holder of shares of the class present in person or by proxy at an adjourned meeting constitutes a quorum.

Directors

Number of Directors

The board of directors (other than alternate directors) shall not, unless otherwise determined by an ordinary resolution of the Company, be less than two nor more than 15 in number.

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Appointment of Directors

The Company may by ordinary resolution elect any person who is willing to act to be a director, either to fill a vacancy or as an additional director, but so that the total number of directors shall not exceed any maximum number fixed by or in accordance with these articles.

No person (other than a director retiring in accordance with our Articles of Association) shall be elected or re-elected a director at any general meeting unless:

•

he is recommended by the board of directors; or

•

not less than 14 nor more than 42 days before the date appointed for the meeting there has been given to the Company, by a shareholder (other than the person to be proposed) entitled to vote at the meeting, notice of his intention to propose a resolution for the election of that person, stating the particulars which would, if he were so elected, be required to be included in the Company’s register of directors and a notice executed by that person of his willingness to be elected.

Every resolution of a general meeting for the election of a director shall relate to one named person and a single resolution for the election of two or more persons shall be void, unless a resolution that it shall be so proposed has been first agreed to by the meeting without any vote being cast against it.

At each annual general meeting every director shall retire from office. A retiring director shall be eligible for re-election, and a director who is re-elected will be treated as continuing in office without a break.

A retiring director who is not re-elected shall retain office until the close of the meeting at which he retires.

If the Company, at any meeting at which a director retires in accordance with our Articles of Association, does not fill the office vacated by such director, the retiring director, if willing to act, shall be deemed to be re-elected, unless at the meeting a resolution is passed not to fill the vacancy or to elect another person in his place or unless the resolution to re-elect him is put to the meeting and lost.

Directors’ Interests

If a director is in any way, directly or indirectly, interested in a proposed transaction or arrangement with the Company, he must declare the nature and extent of that interest to the other directors. Where a director is in any way, directly or indirectly, interested in a transaction or arrangement that has been entered into by the Company, he must declare the nature and extent of his interest to the other directors, unless the interest has already been declared.

Subject to the Companies Act 2006 and to declaring his interest in accordance with the Articles of Association, a director may:

•

enter into or be interested in any transaction or arrangement with the Company, either with regard to his tenure of any office or position in the management, administration or conduct of the business of the Company or as vendor, purchaser or otherwise;

•

hold any other office or place of profit with the Company (except that of auditor) in conjunction with his office of director for such period (subject to the Companies Act 2006) and upon such terms as the board of directors may decide and be paid such extra remuneration for so doing (whether by way of salary, commission, participation in profits or otherwise) as the board of directors may decide, either in addition to or in lieu of any remuneration under any other provision of our Articles of Association;

•

act by himself or his firm in a professional capacity for the Company (except as auditor) and be entitled to remuneration for professional services as if he were not a director;

•

be or become a shareholder or director of, or hold any other office or place of profit under, or otherwise be interested in, any holding company or subsidiary undertaking of that holding company or any other company in which the Company may be interested. The board of directors may cause the voting rights conferred by the shares in any other company held or owned by the Company

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or exercisable by them as directors of that other company to be exercised in such manner in all respects as it thinks fit (including the exercise of voting rights in favor of any resolution appointing the directors or any of them as directors or officers of the other company or voting or providing for the payment of any benefit to the directors or officers of the other company); and

•

be or become a director of any other company in which the Company does not have an interest if that cannot reasonably be regarded as likely to give rise to a conflict of interest at the time of his appointment as a director of that other company.

A director shall not vote (or be counted in the quorum at a meeting) in respect of any resolution concerning his own appointment (including fixing or varying its terms), or the termination of his own appointment, as the holder of any office or place of profit with the Company or any other company in which the Company is interested but, where proposals are under consideration concerning the appointment (including fixing or varying its terms), or the termination of the appointment, of two or more directors to offices or places of profit with the Company or any other company in which the Company is interested, those proposals may be divided and a separate resolution may be put in relation to each director and in that case each of the directors concerned (if not otherwise debarred from voting under the Article of Association) shall be entitled to vote (and be counted in the quorum) in respect of each resolution unless it concerns his own appointment or the termination of his own appointment.

A director shall also not vote (or be counted in the quorum at a meeting) in relation to any resolution relating to any transaction or arrangement with the Company in which he has an interest which may reasonably be regarded as likely to give rise to a conflict of interest and, if he purports to do so, his vote shall not be counted, but this prohibition shall not apply and a director may vote (and be counted in the quorum) in respect of any resolution concerning any one or more of the following matters:

•

any transaction or arrangement in which he is interested by virtue of an interest in shares, debentures or other securities of the Company or otherwise in or through the Company;

•

the giving of any guarantee, security or indemnity in respect of:

•

money lent or obligations incurred by him or by any other person at the request of, or for the benefit of, the Company or any of its subsidiary undertakings; or

•

a debt or obligation of the Company or any of its subsidiary undertakings for which he himself has assumed responsibility in whole or in part (either alone or jointly with others) under a guarantee or indemnity or by the giving of security;

•

indemnification (including loans made in connection with it) by the Company in relation to the performance of his duties on behalf of the Company or of any of its subsidiary undertakings;

•

any issue or offer of shares, debentures or other securities of the Company or any of its subsidiary undertakings in respect of which he is or may be entitled to participate in his capacity as a holder of any such securities or as an underwriter or sub underwriter;

•

any transaction or arrangement concerning any other company in which he does not hold, directly or indirectly as shareholder, or through his direct or indirect holdings of financial instruments (within the meaning of Chapter 5 of the Disclosure Guidance and Transparency Rules of the UK Financial Conduct Authority) voting rights representing 1% or more of any class of shares in the capital of that company;

•

any arrangement for the benefit of employees of the Company or any of its subsidiary undertakings which does not accord to him any privilege or benefit not generally accorded to the employees to whom the arrangement relates; and

•

the purchase or maintenance of insurance for the benefit of directors or for the benefit of persons including directors.

If any question arises at any meeting as to whether an interest of a director (other than the chairman of the meeting) may reasonably be regarded as likely to give rise to a conflict of interest or as to the entitlement of any director (other than the chairman of the meeting) to vote in relation to a transaction or arrangement with the Company and the question is not resolved by his voluntarily agreeing to abstain from

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voting, the question shall be referred to the chairman of the meeting and his ruling in relation to the director concerned shall be final and conclusive except in a case where the nature or extent of the interest of the director concerned, so far as known to him, has not been fairly disclosed. If any question shall arise in respect of the chairman of the meeting and is not resolved by his voluntarily agreeing to abstain from voting, the question shall be decided by a resolution of the board of directors (for which purpose the chairman shall be counted in the quorum but shall not vote on the matter) and the resolution shall be final and conclusive except in a case where the nature or extent of the interest of the chairman of the meeting, so far as known to him, has not been fairly disclosed.

Directors’ Fees and Remuneration

The directors shall be paid such fees not exceeding in aggregate £950,000 per annum (or such larger sum as the Company may, by ordinary resolution, determine) as the board of directors may decide, to be divided among them in such proportion and manner as they may agree or, failing agreement, equally. Any such fee payable shall be distinct from any remuneration or other amounts payable to a director under other provisions of our Articles of Association and shall accrue from day to day.

The board of directors may grant special remuneration to any director who performs any special or extra services to or at the request of the Company.

Such special remuneration may be paid by way of lump sum, salary, commission, participation in profits or otherwise as the board of directors may decide in addition to any remuneration payable under or pursuant to any other of the Articles of Association.

A director shall be paid out of the funds of the Company all travelling, hotel and other expenses properly incurred by him in and about the discharge of his duties, including his expenses of travelling to and from board meetings, committee meetings and general meetings. Subject to any guidelines and procedures established from time to time by the board of directors, a director may also be paid out of the funds of the Company all expenses incurred by him in obtaining professional advice in connection with the affairs of the Company or the discharge of his duties as a director.

The board of directors may exercise all the powers of the Company to:

•

pay, provide, arrange or procure the grant of pensions or other retirement benefits, death, disability or sickness benefits, health, accident and other insurances or other such benefits, allowances, gratuities or insurances, including in relation to the termination of employment, to or for the benefit of any person who is or has been at any time a director of the Company or in the employment or service of the Company or of any body corporate which is or was associated with the Company or of the predecessors in business of the Company or any such associated body corporate, or the relatives or dependents of any such person. For that purpose, the board of directors may procure the establishment and maintenance of, or participation in, or contribution to, any pension fund, scheme or arrangement and the payment of any insurance premiums;

•

establish, maintain, adopt and enable participation in any profit sharing or incentive scheme including shares, share options or cash or any similar schemes for the benefit of any director or employee of the Company or of any associated body corporate, and to lend money to any such director or employee or to trustees on their behalf to enable any such schemes to be established, maintained or adopted; and

•

support and subscribe to any institution or association which may be for the benefit of the Company or of any associated body corporate or any directors or employees of the Company or associated body corporate or their relatives or dependents or connected with any town or place where the Company or an associated body corporate carries on business, and to support and subscribe to any charitable or public object whatsoever.

Borrowing Powers

The board of directors may exercise all the powers of the Company to borrow money, to guarantee, to indemnify, to mortgage or charge all or any part of its undertaking, property, assets (present and future) and uncalled capital, and to issue debentures and other securities, whether outright or as collateral security

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for any debt, liability or obligation of the Company or of any third party. There is no requirement on the directors to restrict the borrowing of the Company or any of its subsidiary undertakings.

Indemnity

As far as the Companies Act 2006 allows, the Company may:

(i)

indemnify any director of the Company (or of an associated body corporate) against any liability;

(ii)

indemnify a director of a company that is a trustee of an occupational pension scheme for employees (or former employees) of the Company (or of an associated body corporate) against liability incurred in connection with the company’s activities as trustee of the scheme;

(iii)

purchase and maintain insurance against any liability for any director referred to in paragraph (i) or (ii) above; and

(iv)

provide any director referred to in paragraphs (i) or (ii) above with funds (whether by loan or otherwise) to meet expenditure incurred or to be incurred by him in defending any criminal, regulatory or civil proceedings or in connection with an application for relief (or to enable any such director to avoid incurring such expenditure),

the powers given by our Articles of Association shall not limit any general powers of the Company to grant indemnities, purchase and maintain insurance or provide funds (whether by way of loan or otherwise) to any person in connection with any legal or regulatory proceedings or applications for relief.

Other UK Law Considerations

Notification of Voting Rights

A shareholder in a public company incorporated in the United Kingdom whose shares are admitted to the premium segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE is required pursuant to Rule 5 of the Disclosure Guidance and Transparency Rules of the UK Financial Conduct Authority to notify us of the percentage of his voting rights if the percentage of voting rights that he holds as a shareholder or through his direct or indirect holding of financial instruments (or a combination of such holdings) reaches, exceeds or falls below 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10% and each 1% threshold thereafter up to 100% as a result of an acquisition or disposal of shares or financial instruments.

Mandatory Purchases and Acquisitions

Pursuant to Sections 979 to 991 of the Companies Act 2006, where a takeover offer has been made for us and the offeror has acquired or unconditionally contracted to acquire not less than 90% in value of the shares to which the offer relates and not less than 90% of the voting rights carried by those shares, the offeror may give notice to the holder of any shares to which the offer relates which the offeror has not acquired or unconditionally contracted to acquire that he wishes to acquire, and is entitled to so acquire, those shares on the same terms as the general offer. The offeror would do so by sending a notice to the outstanding minority shareholders telling them that it will compulsorily acquire their shares. Such notice must be sent within three months of the last day on which the offer can be accepted in the prescribed manner. The squeeze-out of the minority shareholders can be completed at the end of six weeks from the date the notice has been given, subject to the minority shareholders failing to successfully lodge an application to the court to prevent such squeeze-out any time prior to the end of those six weeks following which the offeror can execute a transfer of the outstanding shares in its favor and pay the consideration to us, which would hold the consideration on trust for the outstanding minority shareholders. The consideration offered to the outstanding minority shareholders whose shares are compulsorily acquired under the Companies Act 2006 must, in general, be the same as the consideration that was available under the takeover offer.

Sell Out

The Companies Act 2006 also gives our minority shareholders a right to be bought out in certain circumstances by an offeror who has made a takeover offer for all of our shares. The holder of shares to

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which the offer relates, and who has not otherwise accepted the offer, may require the offeror to acquire his shares if, prior to the expiry of the acceptance period for such offer, (i) the offeror has acquired or unconditionally agreed to acquire not less than 90% in value of the voting shares, and (ii) not less than 90% of the voting rights carried by those shares. The offeror may impose a time limit on the rights of minority shareholders to be bought out that is not less than three months after the end of the acceptance period. If a shareholder exercises his rights to be bought out, the offeror is required to acquire those shares on the terms of this offer or on such other terms as may be agreed.

Disclosure of Interest in Shares

Pursuant to Part 22 of the Companies Act 2006, we are empowered by notice in writing to any person whom we know or have reasonable cause to believe to be interested in our shares, or at any time during the three years immediately preceding the date on which the notice is issued has been so interested, within a reasonable time to disclose to us particulars of that person’s interest and (so far as is within his knowledge) particulars of any other interest that subsists or subsisted in those shares.

Under our Articles of Association, if a person defaults in supplying us with the required particulars in relation to the shares in question or the default shares within the prescribed period, the directors may by notice direct that:

•

in respect of the default shares, the relevant shareholder shall not be entitled to attend or vote (either in person or by proxy) at any general meeting or of a general meeting of the holders of a class of shares or upon any poll or to exercise any right conferred by the default shares;

•

where the default shares represent at least 0.25% of their class, (i) any dividend or other money payable in respect of the default shares shall be retained by us without liability to pay interest, and/or (ii) no transfers by the relevant shareholder of any default shares may be registered (unless the shareholder himself is not in default and the shareholder proves to the satisfaction of the board that no person in default as regards supplying such information is interested in any of the default shares); and/or

•

any shares held by the relevant shareholder in uncertificated form shall be converted into certificated form and that shareholder shall not after that be entitled to convert all or any shares held by him into uncertificated form (unless the shareholder himself is not in default as regards supplying the information required and the shareholder proves to the satisfaction of the board that, after due and careful inquiry, the shareholder is satisfied that none of the shares he is proposing to convert into uncertificated form is a default share).

Purchase of Own Shares

Under UK law, a limited company may only purchase its own shares out of the distributable profits of the company or the proceeds of a fresh issue of shares made for the purpose of financing the purchase, provided that they are not restricted from doing so by their articles. A limited company may not purchase its own shares if, as a result of the purchase, there would no longer be any issued shares of the company other than redeemable shares or shares held as treasury shares. Shares must be fully paid in order to be repurchased.

Subject to the above, we may purchase our own shares in the manner prescribed below. We may make a market purchase of our own fully paid shares pursuant to an ordinary resolution of shareholders. The resolution authorizing the purchase must:

•

specify the maximum number of shares authorized to be acquired;

•

determine the maximum and minimum prices that may be paid for the shares; and

•

specify a date, not being later than five years after the passing of the resolution, on which the authority to purchase is to expire.

We may purchase our own fully paid shares other than on a recognized investment exchange pursuant to a purchase contract authorized by resolution of shareholders before the purchase takes place. Any authority will not be effective if any shareholder from whom we propose to purchase shares votes on the

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resolution and the resolution would not have been passed if he had not done so. The resolution authorizing the purchase must specify a date, not being later than five years after the passing of the resolution, on which the authority to purchase is to expire.

Distributions and Dividends

Under the Companies Act 2006, before a company can lawfully make a distribution or dividend, it must ensure that it has sufficient distributable reserves (on a non-consolidated basis). The basic rule is that a company’s profits available for the purpose of making a distribution are its accumulated, realized profits, so far as not previously utilized by distribution or capitalization, less its accumulated, realized losses, so far as not previously written off in a reduction or reorganization of capital duly made. The requirement to have sufficient distributable reserves before a distribution or dividend can be paid applies to us and to each of our subsidiaries that has been incorporated under UK law.

It is not sufficient that we, as a public company, have made a distributable profit for the purpose of making a distribution. An additional capital maintenance requirement is imposed on us to ensure that the net worth of the company is at least equal to the amount of its capital. A public company can only make a distribution:

•

if, at the time that the distribution is made, the amount of its net assets (that is, the total excess of assets over liabilities) is not less than the total of its called-up share capital and undistributable reserves; and

•

if, and to the extent that, the distribution itself, at the time that it is made, does not reduce the amount of the net assets to less than that total.

City Code on Takeovers and Mergers

As a public company incorporated in the United Kingdom with our registered office in the United Kingdom and whose shares are admitted to the premium segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE, we are subject to the UK City Code on Takeovers and Mergers (the “City Code”), which is issued and administered by the UK Panel on Takeovers and Mergers (the “Panel”). The City Code provides a framework within which takeovers of companies subject to it are conducted. In particular, the City Code contains certain rules in respect of mandatory offers. Under Rule 9 of the City Code, if a person:

•

acquires an interest in our shares which, when taken together with shares in which he or persons acting in concert with him are interested, carries 30% or more of the voting rights of our shares;

•

who, together with persons acting in concert with him, is interested in shares that in the aggregate carry not less than 30% and not more than 50% of the voting rights of our shares, and such persons, or any person acting in concert with him, acquires additional interests in shares that increase the percentage of shares carrying voting rights in which that person is interested; or

•

the acquirer and depending on the circumstances, its concert parties, would be required (except with the consent of the Panel) to make a cash offer for our outstanding shares at a price not less than the highest price paid for any interests in the shares by the acquirer or its concert parties during the previous 12 months.

Exchange Controls

There are no governmental laws, decrees, regulations or other legislation in the United Kingdom that may affect the import or export of capital, including the availability of cash and cash equivalents for use by us, or that may affect the remittance of dividends, interest or other payments by us to non-resident holders of our ordinary shares or ADSs, other than withholding tax requirements. There is no limitation imposed by English law or in our Articles of Association on the right of non-residents to hold or vote shares.

Differences in Corporate Law

The applicable provisions of the Companies Act 2006 differ from laws applicable to U.S. corporations and their shareholders. Set forth below is a summary of certain differences between the provisions of the

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Companies Act 2006 applicable to us and the General Corporation Law of the State of Delaware relating to shareholders’ rights and protections. This summary is not intended to be a complete discussion of the respective rights and it is qualified in its entirety by reference to Delaware law and UK law.

	United Kingdom	Delaware
Appointment and Number of Directors	Under the Companies Act 2006, a public limited company must have at least two directors, and the number of directors may be fixed by or in the manner provided in a company’s articles of association.	Under Delaware law, a corporation must have at least one director, and the number of directors shall be fixed by or in the manner provided in the by-laws.
Removal of Directors	Under the Companies Act 2006, shareholders may remove a director without cause by an ordinary resolution (which is passed by a simple majority of those voting in person or by proxy at a general meeting) irrespective of any provisions of any service contract the director has with the company, provided 28 clear days’ notice of the resolution has been given to the company and its shareholders. On receipt of notice of an intended resolution to remove a director, the company must forthwith send a copy of the notice to the director concerned. Certain other procedural requirements under the Companies Act 2006 must also be followed, such as allowing the director to make representations against his or her removal either at the meeting or in writing.	Under Delaware law, any director or the entire board of directors may be removed, with or without cause, by the holders of a majority of the shares then entitled to vote at an election of directors, except (i) unless the certificate of incorporation provides otherwise, in the case of a corporation whose board of directors is classified, stockholders may effect such removal only for cause; or (ii) in the case of a corporation having cumulative voting, if less than the entire board of directors is to be removed, no director may be removed without cause if the votes cast against his removal would be sufficient to elect him if then cumulatively voted at an election of the entire board of directors, or, if there are classes of directors, at an election of the class of directors of which he is a part.
Vacancies on the Board of Directors	Under UK law, the procedure by which directors, other than a company’s initial directors, are appointed is generally set out in a company’s articles of association, provided that where two or more persons are appointed as directors of a public limited company by resolution of the shareholders, resolutions appointing each director must be voted on individually.	Under Delaware law, vacancies and newly created directorships may be filled by a majority of the directors then in office (even though less than a quorum) or by a sole remaining director unless (i) otherwise provided in the certificate of incorporation or by-laws of the corporation or (ii) the certificate of incorporation directs that a particular class of stock is to elect such director, in which case a majority of the other directors elected by such class, or a sole remaining director elected by such class, will fill such vacancy.
Annual General Meeting	Under the Companies Act 2006, a public limited company must hold an annual general meeting in each six-month period following the company’s annual accounting reference date.	Under Delaware law, the annual meeting of stockholders shall be held at such place, on such date and at such time as may be designated from time to time by the board of directors or as provided in the certificate of incorporation or by the by-laws.

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	United Kingdom	Delaware
General Meeting	Under the Companies Act 2006, a general meeting of the shareholders of a public limited company may be called by the directors. Shareholders holding at least 5% of the paid-up capital of the company carrying voting rights at general meetings (excluding nay paid up capital held as treasury shares) can require the directors to call a general meeting, and, if the directors fail to do so within a certain period, may themselves convene a general meeting.	Under Delaware law, special meetings of the stockholders may be called by the board of directors or by such person or persons as may be authorized by the certificate of incorporation or by the by-laws.
Notice of General Meetings	Under the Companies Act 2006, 21 clear days’ notice must be given for an annual general meeting and any resolutions to be proposed at the meeting. Subject to a company’s articles of association providing for a longer period, at least 14 clear days’ notice is required for any other general meeting. In addition, certain matters, such as the removal of directors or auditors, require special notice, which is 28 clear days’ notice. The shareholders of a company may in all cases consent to a shorter notice period, the proportion of shareholders’ consent required being 100% of those entitled to attend and vote in the case of an annual general meeting and, in the case of any other general meeting, a majority in number of the shareholders having a right to attend and vote at the meeting, being a majority who together hold not less than 95% in nominal value of the shares giving a right to attend and vote at the meeting.	Under Delaware law, unless otherwise provided in the certificate of incorporation or by-laws, written notice of any meeting of the stockholders must be given to each stockholder entitled to vote at the meeting not less than ten nor more than 60 days before the date of the meeting and shall specify the place, date, hour, and purpose or purposes of the meeting.
Proxy	Under the Companies Act 2006, at any meeting of shareholders, a shareholder may designate another person to attend, speak and vote at the meeting on their behalf by proxy.	Under Delaware law, at any meeting of stockholders, a stockholder may designate another person to act for such stockholder by proxy, but no such proxy shall be voted or acted upon after three years from its date, unless the proxy provides for a longer period. A director of a Delaware corporation may not issue a proxy representing the director’s vote (written or verbal) via another board member.
Preemptive Rights	Under the Companies Act 2006, “equity securities,” being (i) shares in a company other than shares that, with respect to dividends and capital, carry a right to participate only up to a	Under Delaware law, stockholders have no preemptive rights to subscribe to additional issues of stock or to any security convertible into such stock unless, and except to the extent that,

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	United Kingdom	Delaware
	specified amount in a distribution (“ordinary shares”) or (ii) rights to subscribe for, or to convert securities into, ordinary shares, proposed to be allotted for cash must be offered first to the existing equity shareholders in the company in proportion to the respective nominal value of their holdings, unless an exception applies or a special resolution to the contrary has been passed by shareholders in a general meeting or the articles of association provide otherwise, in each case in accordance with the provisions of the Companies Act 2006.	such rights are expressly provided for in the certificate of incorporation.
Authority to Allot	Under the Companies Act 2006, the directors of a company must not allot shares or grant rights to subscribe for or to convert any security into shares unless an exception applies or an ordinary resolution to the contrary has been passed by shareholders in a general meeting or the articles of association provide otherwise, in each case in accordance with the provisions of the Companies Act 2006.	Under Delaware law, if the corporation’s certificate of incorporation so provides, the board of directors has the power to authorize the issuance of stock. It may authorize capital stock to be issued for consideration consisting of cash, any tangible or intangible property or any benefit to the corporation or any combination thereof. It may determine the amount of such consideration by approving a formula. In the absence of actual fraud in the transaction, the judgment of the directors as to the value of such consideration is conclusive.
Liability of Directors and Officers	Under the Companies Act 2006, any provision, whether contained in a company’s articles of association or any contract or otherwise, that purports to exempt a director of a company, to any extent, from any liability that would otherwise attach to him in connection with any negligence, default, breach of duty or breach of trust in relation to the company is void. Any provision by which a company directly or indirectly provides an indemnity, to any extent, for a director of the company or of an associated company against any liability attaching to him in connection with any negligence, default, breach of duty or breach of trust in relation to the company of which he is a director is also void except as permitted by the Companies Act 2006, which provides exceptions for the company to (i) purchase and maintain insurance	Under Delaware law, a corporation’s certificate of incorporation may include a provision eliminating or limiting the personal liability of a director to the corporation and its stockholders for damages arising from a breach of fiduciary duty as a director. However, no provision can limit the liability of a director for: • any breach of the director’s duty of loyalty to the corporation or its stockholders; • acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law; • intentional or negligent payment of unlawful dividends or stock purchases or redemptions; or • any transaction from which the director derives an improper personal benefit.

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	United Kingdom	Delaware
	against such liability; (ii) provide a “qualifying third party indemnity” (being an indemnity against liability incurred by the director to a person other than the company or an associated company or for any criminal proceedings in which he is convicted); and (iii) provide a “qualifying pension scheme indemnity” (being an indemnity against liability incurred in connection with the company’s activities as trustee of an occupational pension plan).
Voting Rights	Under UK law, unless a poll is demanded by the shareholders of a company or is required by the chairman of the meeting or the company’s articles of association, shareholders shall vote on all resolutions on a show of hands. Under the Companies Act 2006, a poll may be demanded by (i) not fewer than five shareholders having the right to vote on the resolution; (ii) any shareholder(s) representing not less than 10% of the total voting rights of all the shareholders having the right to vote on the resolution (excluding any voting rights attaching to treasury shares); or (iii) any shareholder(s) holding shares in the company conferring a right to vote on the resolution (excluding any voting rights attaching to treasury shares) being shares on which an aggregate sum has been paid up equal to not less than 10% of the total sum paid up on all the shares conferring that right. A company’s articles of association may provide more extensive rights for shareholders to call a poll. Under UK law, an ordinary resolution is passed on a show of hands if it is approved by a simple majority (more than 50%) of the votes cast by shareholders present (in person or by proxy) and entitled to vote. If a poll is demanded, an ordinary resolution is passed if it is approved by holders representing a simple majority of the total voting rights of shareholders present, in person or by proxy, who, being entitled to vote, vote on the resolution. Special resolutions require the affirmative vote of not less than	Delaware law provides that, unless otherwise provided in the certificate of incorporation, each stockholder is entitled to one vote for each share of capital stock held by such stockholder.

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	United Kingdom	Delaware
	75% of the votes cast by shareholders present, in person or by proxy, at the meeting and entitled to vote. If a poll is demanded, a special resolution is passed if it is approved by shareholders representing not less than 75% of the total voting rights of shareholders who, being entitled to vote, vote in person, by proxy or in advance.
Shareholder Vote on Certain Transactions	The Companies Act 2006 provides for schemes of arrangement, which are arrangements or compromises between a company and any class of shareholders or creditors and used in certain types of reconstructions, amalgamations, capital reorganizations or takeovers. These arrangements require: • the approval at a shareholders’ or creditors’ meeting convened by order of the court, of a majority in number of shareholders or creditors representing 75% in value of the capital held by, or debt owed to, the class of shareholders or creditors, or class thereof present and voting, either in person or by proxy; and • the approval of the court.	Generally, under Delaware law, unless the certificate of incorporation provides for the vote of a larger portion of the stock, completion of a merger, consolidation, sale, lease or exchange of all or substantially all of a corporation’s assets or dissolution requires: • the approval of the board of directors; and • approval by the vote of the holders of a majority of the outstanding stock or, if the certificate of incorporation provides for more or less than one vote per share, a majority of the votes of the outstanding stock of a corporation entitled to vote on the matter.
Standard of Conduct for Directors	Under UK law, a director owes various statutory and fiduciary duties to the company, including: • to act in the way he considers, in good faith, would be most likely to promote the success of the company for the benefit of its shareholders as a whole; • to avoid a situation in which he has, or can have, a direct or indirect interest that conflicts, or possibly conflicts, with the interests of the company; • to act in accordance with the company’s constitution and only exercise his powers for the purposes for which they are conferred; • to exercise independent judgment; • to exercise reasonable care, skill and diligence; • not to accept benefits from a third party conferred by reason of his	Delaware law does not contain specific provisions setting forth the standard of conduct of a director. The scope of the fiduciary duties of directors is generally determined by the courts of the State of Delaware. In general, directors have a duty to act without self-interest, on a well-informed basis and in a manner they reasonably believe to be in the best interest of the stockholders. Directors of a Delaware corporation owe fiduciary duties of care and loyalty to the corporation and to its stockholders. The duty of care generally requires that a director act in good faith, with the care that an ordinarily prudent person would exercise under similar circumstances. Under this duty, a director must inform himself of all material information reasonably available regarding a significant transaction. The duty of loyalty requires that a director act in a manner he reasonably believes to be in the best interests of the corporation.

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	United Kingdom	Delaware
	being a director or doing, or not doing, anything as a director; and • a duty to declare any interest that he has, whether directly or indirectly, in a proposed or existing transaction or arrangement with the company.	He must not use his corporate position for personal gain or advantage. In general, but subject to certain exceptions, actions of a director are presumed to have been made on an informed basis, in good faith and in the honest belief that the action taken was in the best interests of the corporation. However, this presumption may be rebutted by evidence of a breach of one of the fiduciary duties. Delaware courts have also imposed a heightened standard of conduct upon directors of a Delaware corporation who take any action designed to defeat a threatened change in control of the corporation. In addition, under Delaware law, when the board of directors of a Delaware corporation approves the sale or break-up of a corporation, the board of directors may, in certain circumstances, have a duty to obtain the highest value reasonably available to the stockholders.
Shareholder Actions	Under UK law, generally, the company, rather than its shareholders, is the proper claimant in an action in respect of a wrong done to the company or where there is an irregularity in the company’s internal management. Notwithstanding this general position, the Companies Act 2006 provides that (i) a court may allow a shareholder to bring a derivative claim (that is, an action in respect of and on behalf of the company) in respect of a cause of action arising from a director’s negligence, default, breach of duty or breach of trust and (ii) a shareholder may bring a claim for a court order where the company’s affairs have been or are being conducted in a manner that is unfairly prejudicial to some of its shareholders generally or of some of its shareholders, or that an actual or proposed act or omission of the company is or would be so prejudicial.	Under Delaware law, a stockholder may initiate a derivative action to enforce a right of a corporation if the corporation fails to enforce the right itself. The complaint must: • state that the plaintiff was a stockholder at the time of the transaction of which the plaintiff complains or that the plaintiff’s shares thereafter devolved on the plaintiff by operation of law; and • either (i) allege with particularity the efforts made by the plaintiff to obtain the action the plaintiff desires from the directors and the reasons for the plaintiff’s failure to obtain the action; or (ii) state the reasons for not making the effort. Additionally, the plaintiff must remain a stockholder through the duration of the derivative suit. The action will not be dismissed or compromised without the approval of the Delaware Court of Chancery.

Listing

We intend to apply to have our ADSs listed on the under the symbol “DEC.”

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DESCRIPTION OF AMERICAN DEPOSITARY SHARES

American Depositary Shares

The depositary will register and deliver ADSs. Each ADS will represent ordinary shares (or a right to receive one ordinary share) deposited with the custodian. Each ADS will also represent any other securities, cash or other property which may be held by the depositary. The deposited shares together with any other securities, cash or other property held by the depositary are referred to as the deposited securities. The depositary’s office at which the ADSs will be administered and its principal executive office are located at .

You may hold ADSs either (a) directly (i) by having an ADR, which is a certificate evidencing a specific number of ADSs, registered in your name, or (ii) by having uncertificated ADSs registered in your name, or (b) indirectly by holding a security entitlement in ADSs through your broker or other financial institution that is a direct or indirect participant in DTC. If you hold ADSs directly, you are a registered ADS holder, or an “ADS holder.” If you hold the ADSs indirectly, you must rely on the procedures of your broker or other financial institution to assert the rights of ADS holders described in this section. You should consult with your broker or financial institution for more information regarding those products. Registered holders of uncertificated ADSs will receive statements from the depositary confirming their holdings.

As an ADS holder, we will not treat you as one of our shareholders and you will not have shareholder rights. UK law governs shareholder rights. The depositary will be the holder of the ordinary shares underlying your ADSs. As a registered holder of ADSs, you will have ADS holder rights. A deposit agreement among us, the depositary, ADS holders and all other persons indirectly or beneficially holding ADSs sets out ADS holder rights as well as the rights and obligations of the depositary. New York law governs the deposit agreement and the ADSs.

The following is a summary of the material provisions of the deposit agreement. For more complete information, you should read the entire deposit agreement and the form of ADR. Directions on how to obtain copies of those documents are described in the section titled “Where You Can Find Additional Information.”

Dividends and Other Distributions

How will you receive dividends and other distributions on the shares?

The depositary has agreed to pay or distribute to ADS holders the cash dividends or other distributions it or the custodian receives on ordinary shares or other deposited securities, upon payment or deduction of its fees and expenses. You will receive these distributions in proportion to the number of shares your ADSs represent.

Cash. The default currency for dividend payments is U.S. Dollars. Shareholders of the Company will receive their dividends in U.S. Dollars, unless a GBP dividend currency election is made. The deposit agreement allows the depositary to distribute the foreign currency only to those ADS holders to whom it is possible to do so. It will hold the foreign currency it cannot convert for the account of the ADS holders who have not been paid. It will not invest the foreign currency and it will not be liable for any interest.

Before making a distribution, any withholding taxes, or other governmental charges that must be paid will be deducted. See the section titled “Material Tax Considerations,” below. The depositary will distribute only whole U.S. dollars and cents and will round fractional cents to the nearest whole cent. If the exchange rates fluctuate during a time when the depositary cannot convert the foreign currency, you may lose some of the value of the distribution.

Shares. The depositary may distribute additional ADSs representing any ordinary shares we distribute as a dividend or free distribution. The depositary will only distribute whole ADSs. It will sell ordinary shares which would require it to deliver a fraction of an ADS (or ADSs representing those shares) and distribute the net proceeds in the same way as it does with cash. If the depositary does not distribute additional ADSs, the outstanding ADSs will also represent the new shares. The depositary may sell a portion of the distributed ordinary shares (or ADSs representing those shares) sufficient to pay its fees and expenses in connection with that distribution.

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Rights to purchase additional shares. If we offer holders of our securities any rights to subscribe for additional ordinary shares or any other rights, the depositary may (i) exercise those rights on behalf of ADS holders, (ii) distribute those rights to ADS holders or (iii) sell those rights and distribute the net proceeds to ADS holders, in each case after deduction or upon payment of its fees and expenses. To the extent the depositary does not do any of those things, it will allow the rights to lapse. In that case, you will receive no value for them. The depositary will exercise or distribute rights only if we ask it to and provide satisfactory assurances to the depositary that it is legal to do so. If the depositary will exercise rights, it will purchase the securities to which the rights relate and distribute those securities or, in the case of shares, new ADSs representing the new shares, to subscribing ADS holders, but only if ADS holders have paid the exercise price to the depositary. U.S. securities laws may restrict the ability of the depositary to distribute rights or ADSs or other securities issued on exercise of rights to all or certain ADS holders, and the securities distributed may be subject to restrictions on transfer.

There can be no assurance that you will be given the opportunity to exercise rights on the same terms and conditions as the holders of our ordinary shares or be able to exercise such rights at all.

Other Distributions. The depositary will send to ADS holders anything else we distribute on deposited securities by any means it thinks is legal, equitable and practical. If it cannot make the distribution in that way, the depositary has a choice. It may (1) decide to sell what we distributed and distribute the net proceeds, in the same way as it does with cash, or (2) , it may decide to hold what we distributed, in which case ADSs will also represent the newly distributed property. However, the depositary is not required to distribute any securities (other than ADSs) to ADS holders unless it receives satisfactory evidence from us that it is legal to make that distribution. The depositary may sell a portion of the distributed securities or property sufficient to pay its fees and expenses in connection with that distribution. U.S. securities laws may restrict the ability of the depositary to distribute securities to all or certain ADS holders, and the securities distributed may be subject to restrictions on transfer.

The depositary is not responsible if it decides that it is unlawful or impractical to make a distribution available to any ADS holders. We have no obligation to register ADSs, shares, rights or other securities under the Securities Act. We also have no obligation to take any other action to permit the distribution of ADSs, shares, rights or anything else to ADS holders. This means that you may not receive the distributions we make on our shares or any value for them if it is illegal or impractical for us to make them available to you.

Deposit, Withdrawal and Cancellation

How are ADSs issued?

The depositary will deliver ADSs if you or your broker deposits ordinary shares or evidence of rights to receive shares with the custodian. Upon payment of its fees and expenses and of any taxes or charges, such as stamp taxes or stock transfer taxes or fees, the depositary will register the appropriate number of ADSs in the names you request and will deliver the ADSs to or upon the order of the person or persons that made the deposit.

How can ADS holders withdraw the deposited securities?

You may surrender your ADSs to the depositary for the purpose of withdrawal. Upon payment of its fees and expenses and of any taxes or charges, such as stamp taxes or stock transfer taxes or fees, the depositary will deliver the ordinary shares and any other deposited securities underlying the ADSs to the ADS holder or a person the ADS holder designates at the office of the custodian. Alternatively, at your request, risk and expense, the depositary will deliver the deposited securities at its office, if feasible. The depositary may charge you a fee and its expenses for instructing the custodian regarding delivery of deposited securities.

How do ADS holders interchange between certificated ADSs and uncertificated ADSs?

You may surrender your ADR to the depositary for the purpose of exchanging your ADR for uncertificated ADSs. The depositary will cancel that ADR and will send to the ADS holder a statement confirming that the ADS holder is the registered holder of uncertificated ADSs. Upon receipt by the

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depositary of a proper instruction from a registered holder of uncertificated ADSs requesting the exchange of uncertificated ADSs for certificated ADSs, the depositary will execute and deliver to the ADS holder an ADR evidencing those ADSs.

Voting Rights

How do you vote?

ADS holders may instruct the depositary how to vote the number of deposited ordinary shares their ADSs represent at any meeting at which you are entitled to vote pursuant to applicable law and our Articles of Association. Upon receipt of notice of any shareholders’ meeting, if we ask it to, the depositary will notify you of such shareholders’ meeting and send or make voting materials available to you. Those materials will describe the matters to be voted on and explain how ADS holders may instruct the depositary how to vote. For instructions to be valid, they must reach the depositary by a date set by the depositary. The depositary will try, as far as practical, subject to the laws of the United Kingdom and the provisions of our Articles of Association or similar documents, to vote or to have its agents vote the ordinary shares or other deposited securities as instructed by ADS holders. If we do not request the depositary to solicit your voting instructions, you can still send voting instructions, and, in that case, the depositary may try to vote as you instruct, but it is not required to do so.

Except by instructing the depositary as described above, you will not be able to exercise voting rights unless you surrender your ADSs and withdraw the ordinary shares. However, you may not be aware of the meeting enough in advance of such meeting to withdraw the ordinary shares. In any event, the depositary will not exercise any discretion in voting deposited securities and it will only vote or attempt to vote as instructed.

We cannot assure you that you will receive the voting materials in time to ensure that you can instruct the depositary to vote your ordinary shares. In addition, the depositary and its agents are not responsible for failing to carry out voting instructions or for the manner of carrying out voting instructions. This means that you may not be able to exercise voting rights and there may be nothing you can do if your ordinary shares are not voted as you requested.

In order to give you a reasonable opportunity to instruct the depositary as to the exercise of voting rights relating to deposited securities, if we request the depositary to act, we agree to give the depositary notice of any such meeting and details concerning the matters to be voted upon at least 40 days in advance of the meeting date.

The depositary will not vote or attempt to exercise the right to vote or exercise any voting discretion, other than in accordance with such instructions received or deemed to have been received from ADS holders.

If we asked the depositary to solicit your instructions at least 40 days before the meeting date but the depositary does not receive voting instructions from you by the specified date, and we confirm to the depositary that:

•

we wish to receive a discretionary proxy,

•

as of the instruction cutoff date, we reasonably do not know of any substantial shareholder opposition to the particular question and

•

the particular question would not be materially adverse to the interests of our shareholders,

then the depositary will consider you to have authorized and directed it to give a discretionary proxy to a person designated by us to vote the number of deposited securities represented by your ADSs as to that question.

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Fees and Expenses

	Persons depositing or withdrawing shares or ADS holders must pay:			For
	$ (or less) per 100 ADSs (or portion of ADSs)			Issuance of ADSs, including issuances resulting from a distribution of shares or rights or other property
	$ (or less) per 100 ADSs (or portion of ADSs)			Cancellation of ADSs for the purpose of withdrawal, including if the deposit agreement terminates
	$ (or less) per ADSs			Any cash distribution to ADS holders
	$ (or less) per ADSs			Distribution of securities distributed to holders of deposited securities (including rights) that are distributed by the depositary to ADS holders
	$ (or less) per ADSs per calendar year			Depositary services
	Registration or transfer fees			Transfer and registration of shares on our share register to or from the name of the depositary or its agent when you deposit or withdraw shares
	Expenses of the depositary			Administrative and logistical expenses (when expressly provided in the deposit agreement)
	Expenses of the depositary			Converting foreign currency to U.S. dollars
	Taxes and other governmental charges the depositary or the custodian has to pay on any ADSs or shares underlying ADSs, such as stock transfer taxes, stamp duty or withholding taxes			As necessary
	Any charges incurred by the depositary or its agents for servicing the deposited securities			As necessary

The depositary collects its fees for delivery and surrender of ADSs directly from investors depositing ordinary shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The depositary may collect its annual fee for depositary services by deduction from cash distributions or by directly billing investors or by charging the book-entry system accounts of participants acting for them. The depositary may collect any of its fees by deduction from any cash distribution payable (or by selling a portion of securities or other property distributable) to ADS holders that are obligated to pay those fees. The depositary may generally refuse to provide fee-attracting services until its fees for those services are paid.

From time to time, the depositary may make payments to us to reimburse us for costs and expenses generally arising out of establishment and maintenance of the ADS program, waive fees and expenses for services provided to us by the depositary or share revenue from the fees collected from ADS holders. In performing its duties under the deposit agreement, the depositary may use brokers, dealers, foreign currency dealers or other service providers that are owned by or affiliated with the depositary and that may earn or share fees, spreads or commissions.

The depositary may convert currency itself or through any of its affiliates, or the custodian or we may convert currency and pay U.S. dollars to the depositary. Where the depositary converts currency itself or through any of its affiliates, the depositary acts as principal for its own account and not as agent, advisor, broker or fiduciary on behalf of any other person and earns revenue, including, without limitation, transaction spreads, that it will retain for its own account. The revenue is based on, among other things, the difference between the exchange rate assigned to the currency conversion made under the deposit agreement and the rate that the depositary or its affiliate receives when buying or selling foreign currency for its own account. The depositary makes no representation that the exchange rate used or obtained by it or its affiliate in any currency

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conversion under the deposit agreement will be the most favorable rate that could be obtained at the time or that the method by which that rate will be determined will be the most favorable to ADS holders, subject to the depositary’s obligation to act without negligence or bad faith. The methodology used to determine exchange rates used in currency conversions made by the depositary is available upon request. Where the custodian converts currency, the custodian has no obligation to obtain the most favorable rate that could be obtained at the time or to ensure that the method by which that rate will be determined will be the most favorable to ADS holders, and the depositary makes no representation that the rate is the most favorable rate and will not be liable for any direct or indirect losses associated with the rate. In certain instances, the depositary may receive dividends or other distributions from us in U.S. dollars that represent the proceeds of a conversion of foreign currency or translation from foreign currency at a rate that was obtained or determined by us. In such cases, the depositary will not engage in, or be responsible for, any foreign currency transactions and neither we nor the depositary make any representation that the rate obtained or determined by us is the most favorable rate and neither it nor we will be liable for any direct or indirect losses associated with the rate.

Payment of Taxes

You will be responsible for any taxes or other governmental charges payable with respect to your ADSs or on the deposited securities represented by any of your ADSs. The depositary may refuse to register any transfer of your ADSs or allow you to withdraw the deposited securities represented by your ADSs until those taxes or other charges are paid. It may apply payments owed to you or sell deposited securities represented by your ADSs to pay any taxes owed and you will remain liable for any deficiency. If the depositary sells deposited securities, it will, if appropriate, reduce the number of ADSs to reflect the sale and pay to ADS holders any proceeds, or send to ADS holders any property, remaining after it has paid the taxes.

Tender and Exchange Offers; Redemption, Replacement or Cancellation of Deposited Securities

The depositary will not tender deposited securities in any voluntary tender or exchange offer unless instructed to do by an ADS holder surrendering ADSs and subject to any conditions or procedures the depositary may establish. If deposited securities are redeemed for cash in a transaction that is mandatory for the depositary as a holder of deposited securities, the depositary will call for surrender of a corresponding number of ADSs and distribute the net redemption money to the holders of called ADSs upon surrender of those ADSs. If there is any change in the deposited securities such as a subdivision, combination or other reclassification, or any merger, consolidation, recapitalization or reorganization affecting the issuer of deposited securities in which the depositary receives new securities in exchange for or in lieu of the old deposited securities, the depositary will hold those replacement securities as deposited securities under the deposit agreement. However, if the depositary decides it would not be lawful to hold the replacement securities because those securities could not be distributed to ADS holders or for any other reason, the depositary may instead sell the replacement securities and distribute the net proceeds upon surrender of the ADSs.

If there is a replacement of the deposited securities and the depositary will continue to hold the replacement securities, the depositary may distribute new ADSs representing the new deposited securities or ask you to surrender your outstanding ADRs in exchange for new ADRs identifying the new deposited securities.

If there are no deposited securities underlying ADSs, including if the deposited securities are cancelled, or if the deposited securities underlying ADSs have become apparently worthless, the depositary may call for surrender of those ADSs or cancel those ADSs upon notice to the ADS holders.

Amendment and Termination

How may the deposit agreement be amended?

We may agree with the depositary to amend the deposit agreement and the ADRs without your consent for any reason. If an amendment adds or increases fees or charges, except for taxes and other governmental charges or expenses of the depositary for registration fees, facsimile costs, delivery charges or similar items, or prejudices a substantial right of ADS holders, it will not become effective for outstanding ADSs until 30 days after the depositary notifies ADS holders of the amendment. At the time an amendment

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becomes effective, you are considered, by continuing to hold your ADSs, to agree to the amendment and to be bound by the ADRs and the deposit agreement as amended.

How may the deposit agreement be terminated?

The depositary will initiate termination of the deposit agreement if we instruct it to do so. The depositary may initiate termination of the deposit agreement if:

•

60 days have passed since the depositary told us it wants to resign but a successor depositary has not been appointed and accepted its appointment;

•

we delist the ADSs from an exchange in the United States on which they were listed and do not list the ADSs on another exchange in the United States or make arrangements for trading of ADSs on the U.S. over-the-counter market;

•

we delist our shares from an exchange outside the United States on which they were listed and do not list the shares on another exchange outside the United States;

•

the depositary has reason to believe the ADSs have become, or will become, ineligible for registration on Form F-6 under the Securities Act of 1933;

•

we appear to be insolvent or enter insolvency proceedings;

•

all or substantially all the value of the deposited securities has been distributed either in cash or in the form of securities;

•

there are no deposited securities underlying the ADSs or the underlying deposited securities have become apparently worthless; or

•

there has been a replacement of deposited securities.

If the deposit agreement will terminate, the depositary will notify ADS holders at least 90 days before the termination date. At any time after the termination date, the depositary may sell the deposited securities. After that, the depositary will hold the money it received on the sale, as well as any other cash it is holding under the deposit agreement, unsegregated and without liability for interest, for the pro rata benefit of the ADS holders that have not surrendered their ADSs. Normally, the depositary will sell as soon as practicable after the termination date.

After the termination date and before the depositary sells, ADS holders can still surrender their ADSs and receive delivery of deposited securities, except that the depositary may refuse to accept a surrender for the purpose of withdrawing deposited securities if it would interfere with the selling process. The depositary may refuse to accept a surrender for the purpose of withdrawing sale proceeds until all the deposited securities have been sold. The depositary will continue to collect distributions on deposited securities, but, after the termination date, the depositary is not required to register any transfer of ADSs or distribute any dividends or other distributions on deposited securities to the ADS holder (until they surrender their ADSs) or give any notices or perform any other duties under the deposit agreement except as described in this paragraph.

Limitations on Obligations and Liability

Limits on our Obligations and the Obligations of the Depositary; Limits on Liability to Holders of ADSs

The deposit agreement expressly limits our obligations and the obligations of the depositary. It also limits our liability and the liability of the depositary. We and the depositary:

•

are only obligated to take the actions specifically set forth in the deposit agreement without negligence or bad faith and the depositary will not be a fiduciary or have any fiduciary duty to holders of ADSs;

•

are not liable if we are or it is prevented or delayed by law or by events or circumstances beyond our or its control from performing our or its obligations under the deposit agreement;

•

are not liable if we or it exercises discretion permitted under the deposit agreement;

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•

are not liable for the inability of any holder of ADSs to benefit from any distribution on deposited securities that is not made available to holders of ADSs under the terms of the deposit agreement, or for any special, consequential or punitive damages for any breach of the terms of the deposit agreement;

•

have no obligation to become involved in a lawsuit or other proceeding related to the ADSs or the deposit agreement on your behalf or on behalf of any other person;

•

are not liable for the acts or omissions of any securities depository, clearing agency or settlement system;

•

may rely upon any documents we believe or it believes in good faith to be genuine and to have been signed or presented by the proper person; and

•

the depositary has no duty to make any determination or provide any information as to our tax status, or any liability for any tax consequences that may be incurred by ADS holders as a result of owning or holding ADSs or be liable for the inability or failure of an ADS holder to obtain the benefit of a foreign tax credit, reduced rate of withholding or refund of amounts withheld in respect of tax or any other tax benefit.

In the deposit agreement, we and the depositary agree to indemnify each other under certain circumstances.

Requirements for Depositary Actions

Before the depositary will deliver or register a transfer of ADSs, make a distribution on ADSs, or permit withdrawal of ordinary shares, the depositary may require:

•

payment of stock transfer or other taxes or other governmental charges and transfer or registration fees charged by third parties for the transfer of any shares or other deposited securities;

•

satisfactory proof of the identity and genuineness of any signature or other information it deems necessary; and

•

compliance with regulations it may establish, from time to time, consistent with the deposit agreement, including presentation of transfer documents.

The depositary may refuse to deliver ADSs or register transfers of ADSs when the transfer books of the depositary or our transfer books are closed or at any time if the depositary or we think it advisable to do so.

Your Right to Receive the Shares Underlying your ADSs

ADS holders have the right to cancel their ADSs and withdraw the underlying ordinary shares at any time except:

•

when temporary delays arise because: (i) the depositary has closed its transfer books or we have closed our transfer books; (ii) the transfer of ordinary shares is blocked to permit voting at a shareholders’ meeting; or (iii) we are paying a dividend on our ordinary shares;

•

when you owe money to pay fees, taxes and similar charges; or

•

when it is necessary to prohibit withdrawals in order to comply with any laws or governmental regulations that apply to ADSs or to the withdrawal of shares or other deposited securities.

This right of withdrawal may not be limited by any other provision of the deposit agreement.

Direct Registration System

In the deposit agreement, all parties to the deposit agreement acknowledge that the Direct Registration System (“DRS”) and Profile Modification System (“Profile”) will apply to the ADSs. DRS is a system administered by DTC that facilitates interchange between registered holding of uncertificated ADSs and holding of security entitlements in ADSs through DTC and a DTC participant. Profile is a feature of DRS

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that allows a DTC participant, claiming to act on behalf of a registered holder of uncertificated ADSs, to direct the depositary to register a transfer of those ADSs to DTC or its nominee and to deliver those ADSs to the DTC account of that DTC participant without receipt by the depositary of prior authorization from the ADS holder to register that transfer.

In connection with and in accordance with the arrangements and procedures relating to DRS/Profile, the parties to the deposit agreement understand that the depositary will not determine whether the DTC participant that is claiming to be acting on behalf of an ADS holder in requesting registration of transfer and delivery as described in the paragraph above has the actual authority to act on behalf of the ADS holder (notwithstanding any requirements under the Uniform Commercial Code). In the deposit agreement, the parties agree that the depositary’s reliance on and compliance with instructions received by the depositary through the DRS/Profile system and in accordance with the deposit agreement will not constitute negligence or bad faith on the part of the depositary.

Shareholder Communications; Inspection of Register of Holders of ADSs

The depositary will make available for your inspection at its office all communications that it receives from us as a holder of deposited securities that we make generally available to holders of deposited securities. The depositary will send you copies of those communications or otherwise make those communications available to you if we ask it to. You have a right to inspect the register of holders of ADSs, but not for the purpose of contacting those holders about a matter unrelated to our business or the ADSs.

Jury Trial Waiver

The deposit agreement provides that, to the extent permitted by law, ADS holders waive the right to a jury trial of any claim they may have against us or the depositary arising out of or relating to our ordinary shares, the ADSs or the deposit agreement, including any claim under the U.S. federal securities laws. If we or the depositary opposed a jury trial demand based on the waiver, the court would determine whether the waiver is enforceable in the facts and circumstances of that case in accordance with applicable case law. By agreeing to this jury trial waiver provision, however, ADS holders will not be deemed to have waived our or the depositary’s compliance with the U.S. federal securities laws and the rules and regulations promulgated thereunder.

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SHARES AND ADSS ELIGIBLE FOR FUTURE SALE

Prior to this offering, and while our ordinary shares have been traded on the LSE since the LSE IPO, there has been no public market on a U.S. national securities exchange for our ADSs, and we cannot assure you that there will be an active public market for our ADSs following this offering. We cannot predict what effect sales of ADSs in the public market or the availability of ADSs for sale will have on the market price of our ADSs or our ordinary shares. Future sales of substantial amounts of our ADSs or our ordinary shares in the public market, including ordinary shares issued upon exercise of options, or the perception that such sales may occur, however, could adversely affect the market price of our ADSs and also could adversely affect our future ability to raise capital through the sale of ADSs or other equity-related securities at times and prices we believe appropriate.

Based on ADSs outstanding as of December 31, 2021, upon the completion of this offering ADSs, or ADSs if the underwriters exercise their option to purchase additional ADSs in full, will be outstanding. All of the ADSs expected to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, except for ADSs held by our “affiliates,” as that term is defined in Rule 144 under the Securities Act, who are subject to lock-up restrictions or are restricted from selling shares by Rule 144 as the case may be. The remaining outstanding ADSs will be deemed “restricted securities” as that term is defined under Rule 144. Restricted securities may be sold in the public market only if their offer and sale is registered under the Securities Act or if the offer and sale of those securities qualify for an exemption from registration, including exemptions provided by Rules 144 and 701 under the Securities Act, which are summarized below.

As a result of the lock-up agreements described below and the provisions of Rules 144 or 701, and assuming no extension of the lock-up period and no exercise of the underwriters’ option to purchase additional ADSs, the ADSs that will be deemed “restricted securities” will be available for sale in the public market following the completion of this offering as follows:

•

ADSs or ordinary shares, as applicable, will be eligible for sale on the date of this prospectus; and

•

ADSs or ordinary shares, as applicable, will be eligible for sale upon expiration of the lock-up agreements described below, beginning more than 180 days after the date of this prospectus.

Rule 144

In general, a person who has beneficially owned our ordinary shares or ADSs that are restricted shares for at least six months would be entitled to sell such securities, provided that (1) such person is not deemed to have been one of our affiliates at the time of, or at any time during the 90 days preceding, a sale and (2) we are subject to the Exchange Act periodic reporting requirements for at least 90 days before the sale. Persons who have beneficially owned our ordinary shares or ADSs that are restricted shares for at least six months but who are our affiliates at the time of, or any time during the 90 days preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three month period only a number of securities that does not exceed the greater of either of the following:

•

1% of the number of our ordinary shares then outstanding; or

•

the average weekly trading volume of our ADSs on the during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale;

provided, in each case, that we are subject to the Exchange Act periodic reporting requirements for at least 90 days before the sale. Such sales both by affiliates and by non-affiliates must also comply with the manner of sale, current public information and notice provisions of Rule 144 to the extent applicable.

Rule 701

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchases ordinary shares from us in connection with a compensatory share or option plan or other written agreement before the effective date of this offering is entitled to resell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirements or other restrictions contained in Rule 701.

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The SEC has indicated that Rule 701 will apply to typical share options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus. Securities issued in reliance on Rule 701 are restricted securities and, subject to the contractual restrictions described below, beginning 90 days after the date of this prospectus, may be sold by persons other than “affiliates,” as defined in Rule 144, subject only to the manner of sale provisions of Rule 144 and by “affiliates” under Rule 144 without compliance with its one-year minimum holding period requirement.

Regulation S

Regulation S provides generally that sales made in offshore transactions are not subject to the registration or prospectus-delivery requirements of the Securities Act.

Lock-up Agreements

We, our directors and officers and certain other holders of our equity securities have agreed, subject to certain exceptions, not to offer, pledge, sell, contract to sell, transfer, lend or otherwise dispose of, directly or indirectly, any ADSs, ordinary shares or securities convertible into or exchangeable or exercisable for ADSs or ordinary shares, for 180 days after the date of this prospectus without first obtaining the written consent of Citigroup Global Markets Inc., on behalf of the underwriters. These agreements are described below under the section titled “Underwriting.”

Citigroup Global Markets Inc. has advised us that they have no present intent or arrangement to release any ADSs, ordinary shares or other securities subject to a lock-up with the underwriters and will consider the release of any lock-up on a case-by-case basis. Upon a request to release any ADSs, ordinary shares or other securities subject to a lock-up, Citigroup Global Markets Inc. would consider the particular circumstances surrounding the request, including, but not limited to, the length of time before the lock-up expires, the number of ADSs, ordinary shares or other securities requested to be released, reasons for the request, the possible impact on the market for ADSs and whether the holder of our ordinary shares requesting the release is an officer, director or other affiliate of ours.

Share Options

We intend to file one or more registration statements on Form S-8 under the Securities Act to register the offer and sale of any ordinary shares issued or reserved for issuance under our share plans. We expect to file the registration statement covering these ordinary shares after the date of this prospectus, which will permit the resale of such shares by persons who are non-affiliates of ours in the public market without restriction under the Securities Act, subject, with respect to certain of the ordinary shares, to the provisions of the lock-up agreements described above.

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MATERIAL TAX CONSIDERATIONS

The following summary contains a description of certain United Kingdom and U.S. federal income tax consequences of the acquisition, ownership and disposition of ADSs, but it does not purport to be a comprehensive description of all the tax considerations that may be relevant to a decision to purchase ADSs. The summary is based upon the tax laws of the United Kingdom and regulations thereunder and on the tax laws of the United States and regulations thereunder as of the date hereof, which are subject to change.

Material United Kingdom Tax Considerations

The following statements are of a general nature and do not purport to be a complete analysis of all potential UK tax consequences of acquiring, holding and disposing of the ADSs. They are based on current UK tax law and on the current published practice of Her Majesty’s Revenue and Customs (“HMRC”) (which may not be binding on HMRC), as of the date of this prospectus, all of which are subject to change, possibly with retrospective effect. They are intended to address only certain UK tax consequences for holders of ADSs who are tax resident in (and only in) the United Kingdom, and in the case of individuals, domiciled in (and only in) the United Kingdom (except where expressly stated otherwise) who are the absolute beneficial owners of the ADSs and any dividends paid on them and who hold the ADSs as investments (other than in an individual savings account or a self-invested personal pension). They do not address the UK tax consequences which may be relevant to certain classes of ADS holders such as traders, brokers, dealers, banks, financial institutions, insurance companies, investment companies, collective investment schemes, tax-exempt organizations, trustees, persons connected with the Company, persons holding their ADSs as part of hedging or conversion transactions, ADS holders who have (or are deemed to have) acquired their ADSs by virtue of an office or employment, and ADS holders who are or have been officers or employees of the Company. The statements do not apply to any ADS holder who either directly or indirectly holds or controls 10% or more of the Company’s share capital (or class thereof), voting power or profits.

The following is intended only as a general guide and is not intended to be, nor should it be considered to be, legal or tax advice to any particular prospective subscriber for, or purchaser of, any ADSs. Accordingly, prospective subscribers for, or purchasers of, any ADSs who are in any doubt as to their tax position regarding the acquisition, ownership or disposition of any ADSs or who are subject to tax in a jurisdiction other than the United Kingdom should consult their own tax advisers.

UK Taxation of dividends

Withholding tax

The Company will not be required to withhold UK tax at source when paying dividends. The amount of any liability to UK tax on dividends paid by the Company will depend on the individual circumstances of an ADS holder.

Income tax

An individual ADS holder who is resident for tax purposes in the United Kingdom may, depending on his or her particular circumstances, be subject to UK tax on dividends received from the Company. An individual ADS holder who is not resident for tax purposes in the United Kingdom should not be chargeable to UK income tax on dividends received from the Company unless he or she carries on (whether solely or in partnership) any trade, profession or vocation in the United Kingdom through a branch or agency to which the ADSs are attributable. There are certain exceptions for trading in the United Kingdom through independent agents, such as some brokers and investment managers.

All dividends received by a UK tax resident individual holder of any ADSs from the Company or from other sources will form part of the ADS holder’s total income for income tax purposes and will constitute the top slice of that income. A nil rate of income tax will apply to the first £2,000 of taxable dividend income received by the ADS holder in a tax year. Income within the nil rate band will be taken into account in determining whether income in excess of the nil rate band falls within the basic rate, higher rate or additional rate tax bands. Where the dividend income is above the £2,000 dividend allowance, the first £2,000 of the dividend income will be charged at the nil rate and any excess amount will be taxed at 7.5% to the extent that the excess amount falls within the basic rate tax band (increasing to 8.75% from 6 April 2022), 32.5% to

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the extent that the excess amount falls within the higher rate tax band (increasing to 33.75% from 6 April 2022) and 38.1% to the extent that the excess amount falls within the additional rate tax band (increasing to 39.35% from 6 April 2022).

Corporation tax

Corporate ADS holders which are resident for tax purposes in the United Kingdom should not be subject to UK corporation tax on any dividend received from the Company so long as the dividends qualify for exemption (as is likely) and certain conditions are met (including anti-avoidance conditions). If the conditions for exemption are not met or cease to be satisfied, or such an ADS holder elects for an otherwise exempt dividend to be taxable, the ADS holder will be subject to UK corporation tax on dividends received from the Company, at the rate of corporation tax applicable to that ADS holder (the main rate of UK corporation tax is currently 19%, but announced to increase to 25% with effect from 1 April 2023).

Corporate ADS holders who are not resident in the United Kingdom will not generally be subject to UK corporation tax on dividends unless they are carrying on a trade, profession or vocation in the United Kingdom through a permanent establishment in connection with which the ADSs are used, held, or acquired.

A Shareholder who is resident outside the United Kingdom may be subject to non-UK taxation on dividend income under local law.

UK Taxation of capital gains

UK resident ADS holders

A disposal or deemed disposal of ADSs by an individual or corporate ADS holder who is tax resident in the United Kingdom may, depending on the ADS holder’s circumstances and subject to any available exemptions or reliefs, give rise to a chargeable gain or allowable loss for the purposes of UK taxation of chargeable gains.

Any chargeable gain (or allowable loss) will generally be calculated by reference to the consideration received for the disposal of the ADSs less the allowable cost to the ADS holder of acquiring any such ADSs.

The applicable tax rates for individual ADS holders realizing a gain on the disposal of ADSs is, broadly, 10% for basic rate taxpayers and 20% for higher and additional rate taxpayers. For corporate ADS holders, Corporation tax is generally charged on chargeable gains at the rate applicable to the relevant corporate ADS holder.

Non-UK ADS holders

ADS holders who are not resident in the United Kingdom and, in the case of an individual ADS holder, not temporarily non-resident, should not be liable for UK tax on capital gains realized on a sale or other disposal of ADSs unless (i) such ADSs are used, held or acquired for the purposes of a trade, profession or vocation carried on in the United Kingdom through a branch or agency or, in the case of a corporate ADS holder, through a permanent establishment or (ii) where certain conditions are met, the Company derives 75% or more of its gross value from UK land. ADS holders who are not resident in the United Kingdom may be subject to non-UK taxation on any gain under local law.

Generally, an individual ADS holder who has ceased to be resident in the United Kingdom for UK tax purposes for a period of five years or less and who disposes of any ADSs during that period may be liable on their return to the United Kingdom to UK taxation on any capital gain realized (subject to any available exemption or relief).

UK stamp duty (“stamp duty”) and UK stamp duty reserve tax (“SDRT”)

The statements in this paragraph are intended as a general guide to the current position relating to stamp duty and SDRT and apply to any ADS holder irrespective of their place of tax residence. Certain categories of person, including intermediaries, brokers, dealers and persons connected with depositary receipt arrangements and clearance services, may not be liable to stamp duty or SDRT or may be liable at a higher

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rate or may, although not primarily liable for the tax, be required to notify and account for it under the Stamp Duty Reserve Tax Regulations 1986.

Issue of Shares

As a general rule (and except in relation to depositary receipt systems and clearance services (as to which see below)), no UK stamp duty or stamp duty reserve tax, or SDRT, is payable on the issue of the ordinary shares underlying the ADSs.

Transfers of Shares

An unconditional agreement to transfer ordinary shares in certificated form will normally give rise to a charge to SDRT at the rate of 0.5% of the amount or value of the consideration payable for the transfer. The purchaser of the shares is liable for the SDRT. Transfers of ordinary shares in certificated form are generally also subject to stamp duty at the rate of 0.5% of the amount or value of the consideration given for the transfer (rounded up to the next £5.00). Stamp duty is normally paid by the purchaser. The charge to SDRT will be canceled or, if already paid, repaid (generally with interest), where a transfer instrument has been duly stamped within six years of that charge arising (either by paying the stamp duty or by claiming an appropriate relief) or if the instrument is otherwise exempt from stamp duty.

An unconditional agreement to transfer ordinary shares to, or to a nominee or agent for, a person whose business is or includes the issue of depositary receipts or the provision of clearance services will generally be subject to SDRT (or, where the transfer is effected by a written instrument, stamp duty) at a higher rate of 1.5% of the amount or value of the consideration given for the transfer unless the clearance service has made and maintained an election under section 97A of the UK Finance Act 1986, or a “section 97A election.” It is understood that HMRC regards the facilities of DTC as a clearance service for these purposes and we are not aware of any section 97A election having been made by DTC. However, no SDRT is generally payable where the transfer of ordinary shares to a clearance service or depositary receipt system is an integral part of an issue of new share capital.

Any stamp duty or SDRT payable on a transfer of ordinary shares to a depositary receipt system or clearance service will in practice generally be paid by the participants in the clearance service or depositary receipt system.

Transfers of ADSs

No SDRT should be required to be paid on a paperless transfer of ADSs through the clearance service facilities of DTC, provided that no section 97A election has been made by DTC, and such ADSs are held through DTC at the time of any agreement for their transfer.

No UK stamp duty will in practice be payable on a written instrument transferring an ADS provided that the instrument of transfer is executed and remains at all times outside the United Kingdom. Where these conditions are not met, the transfer of, or agreement to transfer, an ADS could, depending on the circumstances, attract a charge to UK stamp duty at the rate of 0.5% of the amount or value of the consideration. If it is necessary to pay stamp duty, it may also be necessary to pay interest and penalties.

Material United States Federal Income Tax Considerations

The following discussion is a summary of the material U.S. federal income tax consequences to U.S. Holders and Non-U.S. Holders (each, as defined below) of the purchase, ownership and disposition of an ADS issued pursuant to this offering, but does not purport to be a complete analysis of all potential U.S. federal tax effects. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local, or non-U.S. tax laws are not discussed herein. This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations promulgated thereunder, judicial decisions, and published rulings and administrative pronouncements of the U.S. Internal Revenue Service (the “IRS”), in each case in effect as of the date hereof. These authorities may change or be subject to differing interpretations. Any such change or differing interpretation may be applied retroactively in a manner that could adversely affect a holder of an ADS. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance that the IRS or a

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court will not take a contrary position to that discussed below regarding the tax consequences of the purchase, ownership and disposition of our ADSs.

This discussion is limited to U.S. Holders and Non-U.S. Holders that each hold an ADS as a “capital asset” within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all U.S. federal income tax consequences relevant to a holder’s particular circumstances, including the impact of the Medicare contribution tax on net investment income and the alternative minimum tax. In addition, it does not address consequences relevant to holders subject to special rules, including, without limitation:

•

U.S. expatriates and former citizens or long-term residents of the United States;

•

U.S. Holders (as defined below) whose functional currency is not the U.S. dollar;

•

persons holding an ADS as part of a hedge, straddle or other risk reduction strategy or as part of a conversion transaction or other integrated investment;

•

banks, insurance companies, and other financial institutions;

•

brokers, dealers or traders in securities;

•

“controlled foreign corporations,” passive foreign investment companies,” and corporations that accumulate earnings to avoid U.S. federal income tax;

•

partnerships or other entities or arrangements treated as partnerships for U.S. federal income tax purposes and other pass-through entities (and investors therein);

•

tax-exempt organizations or governmental organizations;

•

persons deemed to sell an ADS under the constructive sale provisions of the Code;

•

persons who hold or receive an ADS pursuant to the exercise of any employee stock option or otherwise as compensation;

•

tax qualified retirement plans;

•

“qualified foreign pension funds” as defined in Section 897(l)(2) of the Code and entities of all the interests of which are held by qualified foreign pension funds; and

•

persons subject to special tax accounting rules as a result of any item of gross income with respect to the ADSs being taken into account in an applicable financial statement.

If an entity or arrangement treated as a partnership for U.S. federal income tax purposes holds an ADS, the tax treatment of a partner in the partnership will depend on the status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, partnerships holding an ADS and the partners in such partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.

THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT TAX ADVICE. PROSPECTIVE INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF AN ADS ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL OR NON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

U.S. Tax Status of Diversified Energy

Pursuant to Section 7874 of the Code, we believe we are and will continue to be treated as a U.S. corporation for all purposes under the Code. Since we will be treated as a U.S. corporation for all purposes under the Code, we will not be treated as a “passive foreign investment company,” as such rules apply only to non-U.S. corporations for U.S. federal income tax purposes.

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Treatment of Depositary Shares

The discussion below assumes the representations contained in the deposit agreement are true and the obligations in the deposit agreement and any related agreement will be complied with in accordance with their terms. A holder of the ADSs, for U.S. federal income tax purposes, generally will be treated as the owner of the underlying ordinary shares that are represented by such ADSs. Accordingly, deposits or withdrawals of ordinary shares for or from ADSs will not be subject to U.S. federal income tax.

U.S. Holders

For purposes of this discussion, a “U.S. Holder” is any beneficial owner of an ADS that, for U.S. federal income tax purposes, is or is treated as any of the following:

•

an individual who is a citizen or resident of the United States;

•

a corporation created or organized under the laws of the United States, any state thereof, or the District of Columbia;

•

an estate, the income of which is subject to U.S. federal income tax regardless of its source; or

•

a trust that (1) is subject to the primary supervision of a U.S. court and the control of one or more “United States persons” (within the meaning of Section 7701(a)(30) of the Code), or (2) has a valid election in effect to be treated as a United States person for U.S. federal income tax purposes.

Distributions

Distributions, if any, made on the ADSs, generally will be included in a U.S. Holder’s income as ordinary dividend income to the extent of the Company’s current or accumulated earnings and profits. Distributions in excess of the Company’s current and accumulated earnings and profits will be treated as a tax-free return of capital to the extent of a U.S. Holder’s tax basis in the ADSs and thereafter as capital gain from the sale or exchange of such ADSs. Dividends received by a corporate U.S. Holder may be eligible for a dividends-received deduction, subject to applicable limitations. Dividends received by certain non-corporate U.S. Holders (including individuals) are generally taxed at the lower applicable long-term capital gains rates, provided certain holding period and other requirements are satisfied.

Sales, Certain Redemptions or Other Taxable Dispositions of ADSs

Upon the sale, certain redemption or other taxable disposition of an ADS, a U.S. Holder generally will recognize gain or loss equal to the difference between the amount realized and the U.S. Holder’s tax basis in the ADSs. Any gain or loss recognized on a taxable disposition of an ADS will be capital gain or loss. Such capital gain or loss will be long-term capital gain or loss if a U.S. Holder’s holding period at the time of the sale, redemption or other taxable disposition of the ADSs is longer than one year. Long-term capital gains recognized by certain non-corporate U.S. Holders (including individuals) are generally subject to a reduced rate of U.S. federal income tax. The deductibility of capital losses is subject to limitations.

Non-U.S. Holders

For purposes of this discussion, a “Non-U.S. Holder” is any beneficial owner of an ADS that is neither a U.S. Holder nor an entity or arrangement treated as a partnership for U.S. federal income tax purposes.

Distributions

If the Company makes distributions of cash or property on the ADSs, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from the Company’s current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and first be applied against and reduce a Non-U.S. Holder’s adjusted tax basis in its ADSs, but not below zero. Generally, a distribution that constitutes a return of capital will be subject to U.S. federal withholding tax at a rate of 15% if the Non-U.S. Holders’ ADSs constitute a USRPI (as defined below). However, we or the depositary may elect to withhold at a rate of up to 30% of the entire amount of the distribution, even if the Non-U.S. Holders’ ADSs do not constitute a USRPI. For additional information regarding when a Non-U.S. Holder may

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treat its ownership of the ADSs as not constituting a USRPI, see below under the subsection titled “—Sale or Other Taxable Disposition.” However, because a Non-U.S. Holder would not have any U.S. federal income tax liability with respect to a return of capital distribution, a Non-U.S. Holder would be entitled to request a refund of any U.S. federal income tax that is withheld from a return of capital distribution (generally by timely filing a U.S. federal income tax return for the taxable year in which the tax was withheld). Any excess will be treated as capital gain and will be treated as described below under the subsection titled “—Sale or Other Taxable Disposition.”

Subject to the discussion below on effectively connected income, dividends paid to a Non-U.S. Holder of an ADS will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends (or such lower rate specified by an applicable income tax treaty, provided the Non-U.S. Holder furnishes a valid IRS Form W-8BEN or W-8BEN-E (or other applicable documentation) certifying qualification for the lower treaty rate). A Non-U.S. Holder that does not timely furnish the required documentation, but that qualifies for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. Holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.

If dividends paid to a Non-U.S. Holder are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such dividends are attributable), the Non-U.S. Holder will be exempt from the U.S. federal withholding tax described above. To claim the exemption, the Non-U.S. Holder must furnish to the applicable withholding agent a valid IRS Form W-8ECI, certifying that the dividends are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States.

Any such effectively connected dividends will be subject to U.S. federal income tax on a net income basis at the regular rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on such effectively connected dividends, as adjusted for certain items. Non-U.S. Holders should consult their tax advisors regarding any applicable tax treaties that may provide for different rules.

Sale or Other Taxable Disposition

Subject to the discussion below on information reporting, backup withholding and FATCA (as defined below), a Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of an ADS unless:

•

the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such gain is attributable);

•

the Non-U.S. Holder is a nonresident alien individual present in the United States for 183 days or more during the taxable year of the disposition and certain other requirements are met; or

•

our ADSs constitutes a U.S. real property interest (“USRPI”) because we are (or have been during the shorter of the five-year period ending on the date of the disposition or the Non-U.S. Holder’s holding period)a U.S. real property holding corporation (“USRPHC”) for U.S. federal income tax purposes.

Gain described in the first bullet point above generally will be subject to U.S. federal income tax on a net income basis at the regular rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on such effectively connected gain, as adjusted for certain items.

A Non-U.S. Holder described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on gain realized upon the sale or other taxable disposition of our ADSs, which may be offset by U.S. source capital losses of the Non-U.S. Holder (even though the individual is not considered a resident of the United States), provided the Non-U.S. Holder has timely filed U.S. federal income tax returns with respect to such losses.

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With respect to the third bullet point above, due to the nature of our assets and operations, the Company believes it is (and will continue to be) a USRPHC under the Code and the ADSs constitute (and we expect the ADSs to continue to constitute) a USRPI. Non-U.S. Holders generally are subject to a 15% withholding tax on the amount realized from a sale or other taxable disposition of a USRPI, such as the ADSs, which is required to be collected from any sale or disposition proceeds. Furthermore, such Non-U.S. Holders are subject to U.S. federal income tax (at the regular rates) in respect of any gain on their sale or disposition of the ADSs and are required to file a U.S. tax return to report such gain and pay any tax liability that is not satisfied by withholding. Any gain should be determined in U.S. dollars, based on the excess, if any, of the U.S. dollar value of the consideration received over the Non-U.S. Holder’s basis in the ADSs determined in U.S. dollars under the rules applicable to Non-U.S. Holders. A Non-U.S. Holder may, by filing a U.S. tax return, be able to claim a refund for any withholding tax deducted in excess of the tax liability on any gain. However, if the ADSs are considered “regularly traded on an established securities market” (within the meaning of the Treasury Regulations) then Non-U.S. Holders will not be subject to the 15% withholding tax on the disposition of their ADSs, even if such ADSs constitute USRPIs. Moreover, if the ADSs are considered “regularly traded on an established securities market” (within the meaning of the Treasury Regulations) and the Non-U.S. Holder actually or constructively owns or owned, at all times during the shorter of the five-year period ending on the date of the disposition or the Non-U.S. Holder’s holding period, 5% or less of the ADSs taking into account applicable constructive ownership rules (the “5% test”), such Non-U.S. Holder may treat its ownership of the ADSs as not constituting a USRPI and will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of the ADSs (in addition to not being subject to the 15% withholding tax described above) or U.S. tax return filing requirements. It is unclear whether the Company’s ordinary shares may be treated as the same class of stock as the ADSs (and therefore included in the denominator) for purposes of applying the 5% test. The Company makes no representations as to whether the ADSs have been and will be treated as “regularly traded on an established securities market.”

Non-U.S. Holders should consult their tax advisors regarding tax consequences of our treatment as a USRPHC and regarding potentially applicable income tax treaties that may provide for different rules.

Information Reporting and Backup Withholding

U.S. Holders

Information reporting requirements generally will apply to payments of distributions on the ADSs and the proceeds of a sale of an ADS paid to a U.S. Holder unless the U.S. Holder is an exempt recipient and, if requested, certifies as to that status. Backup withholding generally will apply to those payments if the U.S. Holder fails to provide an appropriate certification with its correct taxpayer identification number or certification of exempt status. Any amounts withheld under the backup withholding rules will be allowed as a refund or credit against a U.S. Holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Non-U.S. Holders

Payments of dividends on the ADSs will not be subject to backup withholding, provided the applicable withholding agent does not have actual knowledge or reason to know the Non-U.S. Holder is a United States person and the Non-U.S. Holder either certifies its non-U.S. status, such as by furnishing a valid IRS Form W-8BEN, W-8BEN-E, or W-8ECI, or otherwise establishes an exemption. However, information returns are required to be filed with the IRS in connection with any distributions on our ADSs paid to the Non-U.S. Holder, regardless of whether such distributions constitute dividends or whether any tax was actually withheld. In addition, proceeds of the sale or other taxable disposition of our ADSs within the United States or conducted through certain U.S.-related brokers generally will not be subject to backup withholding or information reporting if the applicable withholding agent receives the certification described above and does not have actual knowledge or reason to know that such holder is a United States person or the holder otherwise establishes an exemption. Proceeds of a disposition of our ADSs conducted through a non-U.S. office of a non-U.S. broker generally will not be subject to backup withholding or information reporting.

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Copies of information returns that are filed with the IRS may also be made available under the provisions of an applicable treaty or agreement to the tax authorities of the country in which the Non-U.S. Holder resides or is established.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a Non-U.S. Holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Additional Withholding Tax on Payments Made to Foreign Accounts

Withholding taxes may be imposed under Sections 1471 to 1474 of the Code (such Sections commonly referred to as the Foreign Account Tax Compliance Act, or “FATCA”) on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or (subject to the proposed Treasury Regulations discussed below) gross proceeds from the sale or other disposition of, our ADSs paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any “substantial United States owners” (as defined in the Code) or furnishes identifying information regarding each substantial United States owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain “specified United States persons” or “United States owned foreign entities” (each as defined in the Code), annually report certain information about such accounts, and withhold 30% on certain payments to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

Under the applicable Treasury Regulations and administrative guidance, withholding under FATCA generally applies to payments of dividends on our ADSs. While withholding under FATCA would have applied also to payments of gross proceeds from the sale or other disposition of stock, including our ADSs, on or after January 1, 2019, proposed Treasury Regulations eliminate FATCA withholding on payments of gross proceeds entirely. Taxpayers generally may rely on these proposed Treasury Regulations until final Treasury Regulations are issued.

Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our ADSs.

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UNDERWRITING

Citigroup Global Markets Inc. is acting as the sole bookrunner for the offering and as representatives of the underwriters named below.

Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of ordinary shares represented by ADSs, set forth opposite each underwriter’s name.

Underwriter			Number of ADS
Citigroup Global Markets Inc.
Total

The underwriting agreement provides that the obligations of the underwriters to purchase the ADSs included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the ADSs (other than those covered by the over-allotment option described below) if they purchase any of the ADSs.

ADSs sold by the underwriters to the public will initially be offered at the initial public offering prices set forth on the cover of this prospectus. Any ADSs sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed US$ per ADS. If all of the ADSs are not sold at the initial offering prices, the representatives may change the public offering prices and the other selling terms. The representatives have advised us that the underwriters do not intend to make sales to discretionary accounts.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional ADSs, at the public offering price less the underwriting discounts and commissions. To the extent the option is exercised, each underwriter must purchase a number of additional ADSs approximately proportionate to that underwriter’s initial purchase commitment. Any ADSs issued or sold under the option will be issued and sold on the same terms and conditions as the other ADSs.

We and certain of our officers and directors have agreed that, for a period of days from the date of this prospectus and subject to certain exceptions, we will not, without the prior written consent of Citigroup Global Markets Inc., as lock-up release agent, dispose of or hedge any of our ordinary shares, ADSs, or any securities convertible into or exchangeable for our ordinary shares or ADSs.

Prior to this offering, there has been no public market for the ADSs. On , 2022, the last reported sale price of our ordinary shares on the LSE was £ per ordinary share (equivalent to $ per ADS based on an assumed exchange rate of £1.00 to $1. ). We cannot assure you that the price at which the ADSs will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in the ADSs will develop and continue after this offering.

We have applied to list the ADSs on the under the symbol “DEC.” Our ordinary shares are admitted to the premium segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE under the symbol “DEC.”

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the over-allotment option by the underwriters.

	No Exercise		Full Exercise
Per ADS		$
Total		$

We estimate that our portion of the total expenses of this offering will be $ . We have also agreed to reimburse the underwriters for certain expenses in connection with the offering in an amount of up to $ .

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In connection with the offering, the underwriters may purchase and sell ADSs and ordinary shares in the open market. Purchases and sales of ADSs or ordinary shares in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the over-allotment option, and stabilizing purchases.

•

Short sales involve secondary market sales by the underwriters of a greater number of ADSs and ordinary shares than they are required to purchase in the offering.

•

“Covered” short sales are sales of ADSs and ordinary shares in an amount up to the number of ADSs and ordinary shares represented by the underwriters’ over-allotment option.

•

“Naked” short sales are sales of ADSs and ordinary shares in an amount in excess of the number of ADSs and ordinary shares represented by the international underwriters’ over-allotment option.

•

Covering transactions involve purchases of ADSs and ordinary shares either pursuant to the international underwriters’ over-allotment option or in the open market in order to cover short positions.

•

To close a naked short position, the underwriters must purchase ADSs and ordinary shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the ADSs and ordinary shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•

To close a covered short position, the underwriters must purchase ADSs and ordinary shares in the open market or must exercise the over-allotment option. In determining the source of ADSs and ordinary shares to close the covered short position, the underwriters, as applicable, will consider, among other things, the price of ADSs and ordinary shares available for purchase in the open market as compared to the price at which they may purchase ADSs and ordinary shares through the over-allotment option.

Stabilizing transactions involve bids to purchase ADSs and ordinary shares so long as the stabilizing bids do not exceed a specified maximum.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters (as applicable) for their own accounts, may have the effect of preventing or retarding a decline in the market price of the ADSs and ordinary shares. They may also cause the price of the ADSs and ordinary shares to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters, as applicable, may conduct these transactions on the or the LSE, as applicable, or in the over-the-counter market, or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

Conflicts of Interest

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. The underwriters and their respective affiliates have in the past performed commercial banking, investment banking and advisory services for us from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. In addition, affiliates of some of the underwriters are lenders, and in some cases agents or managers for the lenders, under our Credit Facility, as well as counterparties to certain of our hedging arrangements. Certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. A typical such

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hedging strategy would include these underwriters or their affiliates hedging such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Notice to Prospective Investors in the European Economic Area

In relation to each Member State of the European Economic Area (each a Relevant State), no shares have been offered or will be offered pursuant to the offering to the public in that Relevant State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant State or, where appropriate, approved in another Relevant State and notified to the competent authority in that Relevant State, all in accordance with the Prospectus Regulation, except that the shares may be offered to the public in that Relevant State at any time:

(i)

to any legal entity which is a qualified investor as defined under Article 2 of the Prospectus Regulation;

(ii)

to fewer than 150 natural or legal persons (other than qualified investors as defined under Article 2 of the Prospectus Regulation), subject to obtaining the prior consent of representatives for any such offer; or

(iii)

in any other circumstances falling within Article 1(4) of the Prospectus Regulation,

provided that no such offer of the shares shall require us or any of the representatives to publish a prospectus pursuant to Article 3 of the Prospectus Regulation or supplement a prospectus pursuant to Article 23 of the Prospectus Regulation. Each person who initially acquires any shares or to whom any offer is made will be deemed to have represented, acknowledged and agreed to and with each of the representatives and the Company that it is a “qualified investor” within the meaning of Article 2(e) of the Prospectus Regulation. In the case of any shares being offered to a financial intermediary as that term is used in the Prospectus Regulation, each such financial intermediary will be deemed to have represented, acknowledged and agreed that the shares acquired by it in the offer have not been acquired on a non-discretionary basis on behalf of, nor have they been acquired with a view to their offer or resale to, persons in circumstances which may give rise to an offer of any shares to the public other than their offer or resale in a Relevant State to qualified investors as so defined or in circumstances in which the prior consent of the representatives have been obtained to each such proposed offer or resale.

For the purposes of this provision, the expression an “offer to the public” in relation to the shares in any Relevant State means the communication in any form and by any means of sufficient information on the terms of the offer and any shares to be offered so as to enable an investor to decide to purchase or subscribe for any shares, and the expression “Prospectus Regulation” means Regulation (EU) 2017/1129.

Notice to Prospective Investors in the United Kingdom

No shares have been offered or will be offered pursuant to the offering to the public in the United Kingdom prior to the publication of a prospectus in relation to the Shares which has been approved by the Financial Conduct Authority, except that the shares may be offered to the public in the United Kingdom at any time:

(i)

to any legal entity which is a qualified investor as defined under Article 2 of the UK Prospectus Regulation;

(ii)

to fewer than 150 natural or legal persons (other than qualified investors as defined under Article 2 of the UK Prospectus Regulation), subject to obtaining the prior consent of the representatives for any such offer; or

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(iii)

in any other circumstances falling within Section 86 of the FSMA,

provided that no such offer of the shares shall require the Issuer or any Manager to publish a prospectus pursuant to Section 85 of the FSMA or supplement a prospectus pursuant to Article 23 of the UK Prospectus Regulation.

For the purposes of this provision, the expression an “offer to the public” in relation to the shares in the United Kingdom means the communication in any form and by any means of sufficient information on the terms of the offer and any shares to be offered so as to enable an investor to decide to purchase or subscribe for any shares and the expression “UK Prospectus Regulation” means Regulation (EU) 2017/1129 as it forms part of domestic law by virtue of the European Union (Withdrawal) Act 2018.

Notice to Prospective Investors in Canada

The shares may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the shares must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws. Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

Pursuant to section 3A.3 of National Instrument 33-105 Underwriting Conflicts (NI 33-105), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

Notice to Prospective Investors in France

Neither this prospectus nor any other offering material relating to the shares described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers or of the competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the shares has been or will be:

•

released, issued, distributed or caused to be released, issued or distributed to the public in France; or

•

used in connection with any offer for subscription or sale of the shares to the public in France.

Such offers, sales and distributions will be made in France only:

•

to qualified investors (investisseurs qualifiés) and/or to a restricted circle of investors (cercle restreint d’investisseurs), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier;

•

to investment services providers authorized to engage in portfolio management on behalf of third parties; or

•

in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the French Code monétaire et financier and article 211-2 of the General Regulations (Règlement Général) of the Autorité des Marchés Financiers, does not constitute a public offer (appel public à l’épargne).

The shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier.

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Notice to Prospective Investors in Germany

Each person who is in possession of this prospectus is aware of the fact that no German sales prospectus (Verkaufsprospekt) within the meaning of the Securities Sales Prospectus Act (Wertpapier- Verkaufsprospektgesetz, the “Act”) of the Federal Republic of Germany has been or will be published with respect to our units. In particular, each underwriter has represented that it has not engaged and has agreed that it will not engage in a public offering in (offentliches Angebot) within the meaning of the Act with respect to any of our units otherwise than in accordance with the Act and all other applicable legal and regulatory requirements.

Notice to Prospective Investors in Hong Kong

The shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Notice to Prospective Investors in Japan

The shares offered in this prospectus have not been and will not be registered under the Financial Instruments and Exchange Law of Japan. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, in Japan or to or for the account of any resident of Japan (including any corporation or other entity organized under the laws of Japan), except (i) pursuant to an exemption from the registration requirements of the Financial Instruments and Exchange Law and (ii) in compliance with any other applicable requirements of Japanese law.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

•

a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

•

a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor,

shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the shares pursuant to an offer made under Section 275 of the SFA except:

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•

to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or to any person pursuant to an offer that is made on terms that such shares, debentures and units of shares and debentures of that corporation or such rights and interest in that trust are acquired at a consideration of not less than $200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions specified in Section 275 of the SFA;

•

where no consideration is or will be given for the transfer; or

•

where the transfer is by operation of law.

Solely for the purposes of its obligations pursuant to section 309B(1)(a) and 309B(1)(c) of the SFA and the Securities and Futures (Capital Markets Products) Regulations 2018 of Singapore (the “CMP Regulations 2018”), the issuer has determined, and hereby notifies all relevant persons (as defined in Section 309A(1) of the SFA), that the shares are “prescribed capital markets products” (as defined in the CMP Regulations 2018) and Excluded Investment Products (as defined in MAS Notice SFA 04-N12: Notice on the Sale of Investment Products; and MAS notice FAA-N16: Notice on Recommendations on Investment Products).

Notice to Prospective Investors in Bermuda

Shares may be offered or sold in Bermuda only in compliance with the provisions of the Investment Business Act of 2003 of Bermuda which regulates the sale of securities in Bermuda. Additionally, non-Bermudian persons (including companies) may not carry on or engage in any trade or business in Bermuda unless such persons are permitted to do so under applicable Bermuda legislation.

Notice to Prospective Investors in Australia

No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (“Corporations Act”)) in relation to the common stock has been or will be lodged with the Australian Securities & Investments Commission (“ASIC”). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:

(a)

you confirm and warrant that you are either:

(i)

a “sophisticated investor” under section 708(8)(a) or (b) of the Corporations Act;

(ii)

a “sophisticated investor” under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;

(iii)

a person associated with the Company under section 708(12) of the Corporations Act; or

(iv)

a “professional investor” within the meaning of section 708(11)(a) or (b) of the Corporations Act, and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and

(b)

you warrant and agree that you will not offer any of the common stock for resale in Australia within 12 months of that common stock being issued unless any such resale offer is exempt from the requirement to issue a disclosure document under section 708 of the Corporations Act.

Notice to Prospective Investors in Switzerland

The shares may not be publicly offered in Switzerland and will not be listed on the SIX Swiss Exchange (“SIX”) or on any other stock exchange or regulated trading facility in Switzerland. This document has been prepared without regard to the disclosure standards for issuance prospectuses under art. 652a or art. 1156

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of the Swiss Code of Obligations or the disclosure standards for listing prospectuses under art. 27 ff. of the SIX Listing Rules or the listing rules of any other stock exchange or regulated trading facility in Switzerland. Neither this document nor any other offering or marketing material relating to the shares or the offering may be publicly distributed or otherwise made publicly available in Switzerland.

Neither this document nor any other offering or marketing material relating to the offering, us, or the shares have been or will be filed with or approved by any Swiss regulatory authority. In particular, this document will not be filed with, and the offer of shares will not be supervised by, the Swiss Financial Market Supervisory Authority (“FINMA”), and the offer of shares has not been and will not be authorized under the Swiss Federal Act on Collective Investment Schemes (“CISA”). The investor protection afforded to acquirers of interests in collective investment schemes under the CISA does not extend to acquirers of shares.

Notice to Prospective Investors in the Dubai International Financial Centre

This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The shares to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.

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EXPENSES OF THE OFFERING

We estimate that our expenses in connection with this offering, other than underwriting discounts and commissions, will be as follows:

Expenses	Amount
SEC registration fee		$	*
FINRA filing fee			*
listing fee			*
Transfer agent’s fee			*
Printing and engraving expenses			*
Legal fees and expenses			*
Accounting fees and expenses			*
Miscellaneous costs			*
Total			*

To be filed by amendment.

All amounts in the table are estimates except the SEC registration fee, the FINRA filing fee and the listing fee. We will pay all of the expenses of this offering.

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LEGAL MATTERS

The validity of our ADSs and ordinary shares and certain other matters of UK law and U.S. federal law will be passed upon for us by Latham & Watkins LLP. Legal counsel to the underwriters in connection with this offering are Baker Botts L.L.P. with respect to UK law and U.S. federal law.

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EXPERTS

Independent Registered Public Accounting Firm

The financial statements as of December 31, 2021 and 2020 and for the years then ended included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting. The current address of PricewaterhouseCoopers LLP is 569 Brookwood Village, Suite 851, Birmingham, Alabama, 35209.

Independent Petroleum Engineers

The letter reports, included as an exhibit to the registration statement of which this prospectus forms a part, of Netherland, Sewell & Associates, Inc., independent consulting petroleum engineers, and information with respect to our natural gas, oil and NGL reserves derived from such reports, have been referred to in this prospectus upon the authority of such firm as experts with respect to such matters covered in such reports and in giving such reports. The current address of Netherland, Sewell & Associates, Inc. is 2100 Ross Avenue, Suite 2200, Dallas, Texas 75201.

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SERVICE OF PROCESS AND ENFORCEMENT OF CIVIL LIABILITIES

We are incorporated and currently existing 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 be difficult for investors to effect service of process on us or those persons in the United States or to enforce in the United States judgments obtained in United States courts against us or those persons based on the civil liability or other provisions of the United States securities laws or other laws. In addition, uncertainty exists as to whether the courts of the United Kingdom would:

•

recognize or enforce judgments of United States courts obtained against us or our directors or officers predicated upon the civil liabilities provisions of the securities laws of the United States or any state in the United States; or

•

entertain original actions brought in the United Kingdom against us or our directors or officers predicated upon the securities laws of the United States or any state in the United States.

We have been advised by Latham & Watkins LLP that there is currently no treaty between (i) the United States and (ii) the United Kingdom providing for reciprocal recognition and enforcement of judgments of United States courts in civil and commercial matters (although the United States and the United Kingdom are both parties to the New York Convention on the Recognition and Enforcement of Foreign Arbitral Awards) and that a final judgment for the payment of money rendered by any general or state court in the United States based on civil liability, whether or not predicated solely upon the United States securities laws, would not be automatically enforceable in the United Kingdom. We have also been advised by Latham & Watkins LLP that any final and conclusive monetary judgment for a definite sum obtained against us in United States courts would be treated by the courts of the United Kingdom as a cause of action in itself and sued upon as a debt at common law so that no retrial of the issues would be necessary, provided that:

•

the relevant U.S. court had jurisdiction over the original proceedings according to UK conflicts of laws principles at the time when proceedings were initiated;

•

the UK courts had jurisdiction over the matter on enforcement and we either submitted to such jurisdiction or were resident or carrying on business within such jurisdiction and were duly served with process;

•

the U.S. judgment was final and conclusive on the merits in the sense of being final and unalterable in the court that pronounced it and being for a definite sum of money;

•

the judgment given by the courts was not in respect of penalties, taxes, fines or similar fiscal or revenue obligations (or otherwise based on a U.S. law that a UK court considers to relate to a penal, revenue or other public law);

•

the judgment was not procured by fraud;

•

recognition or enforcement of the judgment in the United Kingdom would not be contrary to public policy or the Human Rights Act 1998;

•

the proceedings pursuant to which judgment was obtained were not contrary to natural justice;

•

the U.S. judgment was not arrived at by doubling, trebling or otherwise multiplying a sum assessed as compensation for the loss or damages sustained and not being otherwise in breach of Section 5 of the UK Protection of Trading Interests Act 1980, or is a judgment based on measures designated by the Secretary of State under Section 1 of that Act;

•

there is not a prior decision of a UK court or the court of another jurisdiction on the issues in question between the same parties; and

•

the UK enforcement proceedings were commenced within the limitation period.

Whether these 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.

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Subject to the foregoing, investors may be able to enforce in the United Kingdom judgments in civil and commercial matters that have been obtained from U.S. federal or state courts. Nevertheless, we cannot assure you that those judgments will be recognized or enforceable in the United Kingdom.

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. In addition, it may not be possible to obtain a UK judgment or to enforce that judgment if the judgment debtor is or becomes subject to any insolvency or similar proceedings, or if the judgment debtor has any set-off or counterclaim against the judgment creditor. Also note that, in any enforcement proceedings, the judgment debtor may raise any counterclaim that could have been brought if the action had been originally brought in the UK unless the subject of the counterclaim was in issue and denied in the U.S. proceedings.

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WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the SEC a registration statement (including amendments and exhibits to the registration statement) on Form F-1 under the Securities Act. This prospectus, which is part of the registration statement, does not contain all of the information set forth in the registration statement. The rules and regulations of the SEC allow us to omit certain information from this prospectus that is included in the registration statement and the exhibits and schedules to the registration statement. For further information, we refer you to the registration statement and the exhibits and schedules filed as part of the registration statement.

Statements made in this prospectus concerning the contents of any contract, agreement or other document are not complete descriptions of all terms of these documents. If a document has been filed as an exhibit to the registration statement, we refer you to the copy of the document that has been filed for a complete description of its terms. Each statement in this prospectus relating to a document filed as an exhibit is qualified in all respects by the filed exhibit. You should read this prospectus and the documents that we have filed as exhibits to the registration statement of which this prospectus is a part completely.

Upon the closing of this offering, we will become subject to the periodic reporting and other informational requirements of the Exchange Act, as applicable to foreign private issuers. Accordingly, we will be required to file reports and other information with the SEC, including annual reports on Form 20-F and reports on Form 6-K. The SEC maintains an internet website that contains reports and other information about issuers, like us, that file electronically with the SEC. We are not required to prepare and issue quarterly reports as a foreign private issuer. The address of that website is www.sec.gov.

As a foreign private issuer, we are exempt under the Exchange Act from, among other things, the rules prescribing the furnishing and content of proxy statements, and our officers, directors and principal shareholders are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act. In addition, we will not be required under the Exchange Act to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act.

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DIVERSIFIED ENERGY COMPANY PLC

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS (AUDITED)

	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2021 and 2020		F-3
Consolidated Statement of Financial Position as of December 31, 2021 and 2020		F-4
Consolidated Statement of Changes in Equity for the Years Ended December 31, 2021 and 2020		F-5
Consolidated Statement of Cash Flows for the Years Ended December 31, 2021 and 2020		F-6
Notes to the Consolidated Financial Statements		F-8

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders
Diversified Energy Company plc

Opinion on the Financial Statements

We have audited the accompanying consolidated statement of financial position of Diversified Energy Company plc and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of comprehensive income, of changes in equity, and of cash flows for the years then ended, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the years then ended in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers L.L.P.

Birmingham, Alabama
June 2, 2022

We have served as the Company’s auditor since 2020.

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Consolidated Statement of Comprehensive Income
(Amounts in thousands, except per share and per unit data)

			Year Ended
	Notes		December 31, 2021			December 31, 2020
Revenue		6		$	1,007,561		$	408,693
Operating expense		7			(291,213)			(203,963)
Depreciation, depletion and amortization		7			(167,644)			(117,290)
Gross profit				$	548,704		$	87,440
General and administrative expense		7			(102,326)			(77,234)
Allowance for expected credit losses		14			4,265			(8,490)
Gain (loss) on natural gas and oil property and equipment		10,11			(901)			(2,059)
Gain (loss) on derivative financial instruments		13			(974,878)			(94,397)
Gains on bargain purchases		5			58,072			17,172
Operating profit (loss)				$	(467,064)		$	(77,568)
Finance costs		21			(50,628)			(43,327)
Accretion of asset retirement obligation		19			(24,396)			(15,424)
Other income (expense)		24			(8,812)			(421)
Income (loss) before taxation				$	(550,900)		$	(136,740)
Income tax benefit (expense)		8			225,694			113,266
Net income (loss)				$	(325,206)		$	(23,474)
Other comprehensive income (loss)					51			(28)
Total comprehensive income (loss)				$	(325,155)		$	(23,502)
Net income (loss) attributable to:
Diversified Energy Company PLC				$	(325,509)		$	(23,474)
Non-controlling interest					303			—
Net income (loss)				$	(325,206)		$	(23,474)
Earnings (loss) per share–basic and diluted		9		$	(0.41)		$	(0.03)
Weighted average shares outstanding–basic and diluted		9			793,542			685,170

The notes are an integral part of the Consolidated Financial Statements.

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Consolidated Statement of Financial Position
(Amounts in thousands, except per share and per unit data)

	Notes		December 31, 2021			December 31, 2020
ASSETS
Non-current assets:
Natural gas and oil properties, net		10		$	2,530,078		$	1,755,085
Property, plant and equipment, net		11			413,980			382,103
Intangible assets		12			14,134			19,213
Restricted cash		3			18,069			20,100
Derivative financial instruments		13			219			717
Deferred tax asset		8			176,955			14,777
Other non-current assets		15			3,635			4,213
Total non-current assets				$	3,157,070		$	2,196,208
Current assets:
Trade receivables, net		14		$	282,922		$	66,991
Cash and cash equivalents		3			12,558			1,379
Restricted cash		3			1,033			250
Derivative financial instruments		13			1,052			17,858
Other current assets		15			39,574			7,996
Total current assets				$	337,139		$	94,474
Total assets				$	3,494,209		$	2,290,682
EQUITY AND LIABILITIES
Shareholders’ equity:
Share capital		16		$	11,571		$	9,520
Share premium		16			1,052,959			841,159
Share based payment and other reserves					14,156			8,797
Retained earnings (accumulated deficit)					(431,277)			27,182
Equity attributable to owners of the parent:				$	647,409		$	886,658
Non-controlling interest		5			16,541			—
Total equity				$	663,950		$	886,658
Non-current liabilities:
Asset retirement obligations		19		$	522,190		$	344,242
Leases		20			18,177			13,865
Borrowings		21			951,535			652,281
Deferred tax liability		8			—			15,746
Derivative financial instruments		13			556,982			168,524
Other non-current liabilities		23			7,775			12,860
Total non-current liabilities				$	2,056,659		$	1,207,518
Current liabilities:
Trade and other payables		22		$	62,418		$	19,366
Leases		20			9,627			5,013
Borrowings		21			58,820			64,959
Derivative financial instruments		13			251,687			15,858
Other current liabilities		23			391,048			91,310
Total current liabilities				$	773,600		$	196,506
Total liabilities				$	2,830,259		$	1,404,024
Total equity and liabilities				$	3,494,209		$	2,290,682

The Consolidated Financial Statements were approved and authorized for issue by the Board on June 2, 2022 and were signed on its behalf by:

DAVID E. JOHNSON

Chairman of the Board

June 2, 2022

The notes are an integral part of the Consolidated Financial Statements.

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Consolidated Statement of Changes in Equity
(Amounts in thousands, except per share and per unit data)

	Notes		Share Capital			Share Premium			Share Based Payment and Other Reserves			Retained Earnings (Accumulated Deficit)			Equity Attributable to Owners of the Parent			Non- Controlling Interest			Total Equity
Balance as of December 31, 2020				$	9,520		$	841,159		$	8,797		$	27,182		$	886,658		$	—		$	886,658
Net Income (loss)					—			—			—			(325,509)			(325,509)			303			(325,206)
Other comprehensive income (loss)				��	—			—			—			51			51			—			51
Total comprehensive income (loss)					—			—			—			(325,458)			(325,458)			303			(325,155)
Non-controlling interest		5			—			—			—			—			—			16,238			16,238
Issuance of share capital		16			2,044			211,800			—			—			213,844			—			213,844
Equity compensation					7			—			6,788			(2,762)			4,033			—			4,033
Dividends		18			—			—			—			(130,239)			(130,239)			—			(130,239)
Cancellation of warrants		16			—			—			(1,429)			—			(1,429)			—			(1,429)
Transactions with shareholders					2,051			211,800			5,359			(133,001)			86,209			16,238			102,447
Balance as of December 31, 2021				$	11,571		$	1,052,959		$	14,156		$	(431,277)		$	647,409		$	16,541		$	663,950

	Notes		Share Capital			Share Premium			Share Based Payment and Other Reserves			Retained Earnings (Accumulated Deficit)			Equity Attributable to Owners of the Parent			Non- Controlling Interest			Total Equity
Balance as of December 31, 2019				$	8,800		$	760,543		$	3,947		$	164,845		$	938,135		$	—		$	938,135
Net income (loss)					—			—			—			(23,474)			(23,474)			—			(23,474)
Other comprehensive income (loss)					—			—			—			(28)			(28)			—			(28)
Total comprehensive income (loss)					—			—			—			(23,502)			(23,502)			—			(23,502)
Issuance of share capital		16			791			80,616			—			—			81,407			—			81,407
Equity compensation					3			—			4,776			—			4,779			—			4,779
Repurchase of shares		16			(74)			—			74			(15,634)			(15,634)			—			(15,634)
Dividends		18			—			—			—			(98,527)			(98,527)			—			(98,527)
Transactions with shareholders					720			80,616			4,850			(114,161)			(27,975)			—			(27,975)
Balance as of December 31, 2020				$	9,520		$	841,159		$	8,797		$	27,182		$	886,658		$	—		$	886,658

The notes are an integral part of the Consolidated Financial Statements.

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Consolidated Statement of Cash Flows
(Amounts in thousands, except per share and per unit data)

			Year Ended
	Notes		December 31, 2021			December 31, 2020
Cash flows from operating activities:
Income (loss) after taxation				$	(325,206)		$	(23,474)
Cash flows from operations reconciliation:
Depreciation, depletion and amortization		7			167,644			117,290
Accretion of asset retirement obligations		19			24,396			15,424
Income tax (benefit) expense		8			(225,694)			(113,266)
(Gain) loss on fair value adjustments of unsettled financial instruments		13			652,465			238,795
Plugging costs of asset retirement obligations		19			(2,879)			(2,442)
(Gain) loss on natural gas and oil properties and equipment		5,11,12			901			1,356
(Gains) on bargain purchases		5			(58,072)			(17,172)
Finance costs		21			50,628			43,327
Revaluation of contingent consideration		5			8,963			567
Hedge modifications		13			(10,164)			(7,723)
Non-cash equity compensation		7			7,400			5,007
Working capital adjustments:
Change in trade receivables		14			(122,724)			2,390
Change in other current assets		15			(4,233)			1,958
Change in other assets		15			(556)			(1,173)
Change in trade and other payables		22			9,307			(4,772)
Change in other current and non-current liabilities		23			158,886			(8,532)
Cash generated from operations				$	331,062		$	247,560
Cash paid for income taxes					(10,880)			(5,850)
Net cash provided by operating activities				$	320,182		$	241,710
Cash flows from investing activities:
Consideration for business acquisitions, net of cash acquired		5		$	(286,804)		$	(100,138)
Consideration for asset acquisitions		5			(287,330)			(122,953)
Proceeds from divestitures		5			86,224			—
Payments associated with potential acquisitions		15			(25,002)			—
Acquisition related debt and hedge extinguishments		5,14			(56,466)			—
Expenditures on natural gas and oil properties and equipment		10,11			(50,175)			(21,947)
(Increase) decrease in restricted cash					1,838			(12,637)
Proceeds on disposals of natural gas and oil properties and equipment		10,11			2,663			3,712
Other acquired intangibles		12			—			(2,900)
Contingent consideration payments		5			(10,822)			(893)
Net cash used in investing activities				$	(625,874)		$	(257,756)
Cash flows from financing activities:
Repayment of borrowings		21		$	(1,432,566)		$	(705,314)
Proceeds from borrowings		21			1,727,745			799,650
Cash paid for interest		21			(41,623)			(34,335)
Debt issuance cost		21			(10,255)			(7,799)
Proceeds from equity issuance, net		16			213,844			81,407
Principal element of lease payments		20			(8,606)			(3,684)
Cancellation of warrants		16			(1,429)			—
Dividends to shareholders		18			(130,239)			(98,527)
Repurchase of shares		16			—			(15,634)
Net cash provided by financing activities				$	316,871		$	15,764
Net change in cash and cash equivalents				$	11,179		$	(282)
Cash and cash equivalents, beginning of period					1,379			1,661
Cash and cash equivalents, end of period				$	12,558		$	1,379

The notes are an integral part of the Consolidated Financial Statements.

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

Index to the Notes to the Consolidated Financial Statements

	Page
Note 1—General Information		F-8
Note 2—Basis of Preparation		F-8
Note 3—Significant Accounting Policies		F-11
Note 4—Significant Accounting Judgments and Estimates		F-18
Note 5—Acquisitions		F-20
Note 6—Revenue		F-28
Note 7—Expenses by Nature		F-29
Note 8—Taxation		F-31
Note 9—Earnings (Loss) Per Share		F-35
Note 10—Natural Gas and Oil Properties		F-36
Note 11—Property, Plant and Equipment		F-37
Note 12—Intangible Assets		F-38
Note 13—Derivative Financial Instruments		F-39
Note 14—Trade and Other Receivables		F-44
Note 15—Other Assets		F-45
Note 16—Share Capital		F-45
Note 17—Non-Cash Share-Based Compensation		F-46
Note 18—Dividends		F-49
Note 19—Asset Retirement Obligations		F-49
Note 20—Leases		F-51
Note 21—Borrowings		F-53
Note 22—Trade and Other Payables		F-57
Note 23—Other Liabilities		F-58
Note 24—Fair Value and Financial Instruments		F-58
Note 25—Financial Risk Management		F-61
Note 26—Contingencies		F-64
Note 27—Related Party Transactions		F-64
Note 28—Subsequent Events		F-65
Note 29—Supplemental Natural Gas and Oil Information (unaudited)		F-65

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 1—GENERAL INFORMATION

Diversified Energy Company PLC (the “Parent”), formerly Diversified Gas & Oil PLC, and its wholly owned subsidiaries (the “Company”) is an independent energy company engaged in the production, marketing and transportation of primarily natural gas related to its synergistic US onshore upstream and midstream assets. The Company’s assets are located within the Appalachian Basin of the US and more recently have expanded into the Central Region, consisting of the Cotton Valley, Haynesville and Barnett shales located in the states of Louisiana, Texas and Oklahoma.

The Parent was incorporated on July 31, 2014 in the United Kingdom and is registered in the United Kingdom under the Companies Act 2006 as a public limited company under company number 09156132. The Company’s registered office is located at 4th floor Reading Bridge House, George Street, Reading, Berkshire, RG1 8LS, United Kingdom.

In February 2017, the Company’s shares were admitted to trading on AIM under the ticker “DGOC.” In May 2020, the Company’s shares were admitted to trading on the LSE’s Main Market for listed securities. The shares trading on AIM were cancelled concurrent to their admittance on the LSE. With the change in corporate name in 2021, the Company’s shares listed on the LSE began trading on May, 7 2021 as Diversified Energy Company PLC under the new ticker “DEC”.

NOTE 2—BASIS OF PREPARATION

Basis of Preparation

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). The principal accounting policies set out below have been applied consistently throughout the year and are consistent with prior year unless otherwise stated.

Unless otherwise stated, the Consolidated Financial Statements are presented in US Dollars, which is the Company’s subsidiaries’ functional currency and the currency of the primary economic environment in which the Company operates, and all values are rounded to the nearest thousand dollars except per share and per unit amounts and where otherwise indicated.

Transactions in foreign currencies are translated into US Dollars at the rate of exchange on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate at the date of the Consolidated Statement of Financial Position. Where the Company has a different functional currency, its results and financial position are translated into the presentation currency as follows:

•

Assets and liabilities in the Consolidated Statement of Financial Position are translated at the closing rate at the date of that Consolidated Statement of Financial Position;

•

Income and expenses in the Consolidated Statement of Comprehensive Income are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions); and

•

All resulting exchange differences are reflected within other comprehensive income in the Consolidated Statement of Comprehensive Income.

The Consolidated Financial Statements have been prepared under the historical cost convention, as modified by the revaluation of financial assets and liabilities (including derivative instruments) held at fair value through profit and loss or through other comprehensive income.

Segment Reporting

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 2—BASIS OF PREPARATION (continued)

Texas and Louisiana. The Company’s strategy is to acquire long-life producing assets, efficiently operate those assets to generate Free Cash Flow for shareholders and then to retire assets safely and responsibly at the end of their useful life. The Company’s assets consist of natural gas and oil wells, pipelines and a network of gathering lines and compression facilities which are complementary to the Company’s assets. The Directors acquire and manage these assets in a complementary fashion to vertically integrate and improve margins rather than as separate operations. Accordingly, when determining operating segments under IFRS 8, the Company has identified one reportable segment that produces and transports natural gas, NGLs and oil in the US.

Going Concern

The Consolidated Financial Statements have been prepared on the going concern basis, which contemplates the continuity of normal business activity and the realization of assets and the settlement of liabilities in the normal course of business. The Directors have reviewed the Company’s overall position and outlook and are of the opinion that the Company is sufficiently well funded to be able to operate as a going concern for at least the next twelve months from the date of approval of its 2021 Annual Report.

The Directors closely monitor and carefully manage the Company’s liquidity risk. Our financial outlook is assessed primarily through the annual business planning process, however it is also carefully monitored on a monthly basis. This process includes regular Board discussions, led by Senior Leadership, at which the current performance of, and outlook for, the Company are assessed. The outputs from the business planning process include a set of key performance objectives, an assessment of the Company’s primary risks, the anticipated operational outlook and a set of financial forecasts that consider the sources of funding available to the Company (the “Base Plan”).

The Base Plan incorporates key assumptions which underpin the business planning process. These assumptions are as follows:

•

Projected operating cash flows are calculated using a production profile which is consistent with current operating results and decline rates;

•

Assumes commodity prices are in line with the current forward curve which considers basis differentials;

•

Operating cost levels stay consistent with historical trends;

•

The financial impact of our current hedging contracts in place, being approximately 90%, 70%, and 55% of total production volumes hedged for the years ending December 31, 2022, 2023 and 2024 respectively; and

•

The scenario also includes the scheduled principal and interest payments on our current debt arrangements and the funding of a dividend utilizing approximately 40% of Free Cash Flow; and

•

The continuation of $15 million a year in emissions reductions initiatives.

The Directors and Senior Leadership also consider further scenarios around the Base Plan that primarily reflect a more severe, but plausible, downside impact of the principal risks, both individually and in the aggregate, as well as the additional capital requirements that downside scenarios could place on us.

Scenario 1:

A sharp and sustained decline in pricing resulting in a 10% reduction to net realized prices.

Scenario 2:

A operational stoppage or regulatory event occurs which results in reduced production by approximately 5%.

Scenario 3:

A market or regulatory event triggers an increase in operating and midstream expenses by approximately 5%.

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 2—BASIS OF PREPARATION (continued)

will be funded utilizing the higher commodity revenues from which the derivative liability was derived. The Company will also continue to meet the covenant requirements under its Credit Facility as well as its other existing borrowing instruments, and continue to return cash flows to shareholders.

The Directors and Senior Leadership consider the impact that these principal risks could, in certain circumstances, have on the Company’s prospects within the assessment period, and accordingly appraise the opportunities to actively mitigate the risk of these severe, but plausible, downside scenarios. In addition to its modeled downside going concern scenarios, the Board has reverse stress tested the model to determine the extent of downturn which would result in a breach of covenants. Assuming similar levels of cash conversion as seen in 2020, a decline in production volume and pricing well in excess of that historically experienced by the Company would need to persist throughout the going concern period for a covenant breach to occur, which is considered very unlikely. This stress test also does not incorporate certain mitigating actions or cash preservation responses, which the Company would implement in the event of a severe and extended revenue decline.

In addition to the scenarios above, the Directors also considered the risk of a temporary shutdown resulting from the COVID-19 pandemic. Notwithstanding the modelling of this scenario, the Company is considered an essential service as the Company falls under the US Department of Homeland Security’s definition of essential criteria infrastructure workers as defined on March 19, 2020. As a result of the announcement, the Company’s employees are exempt from any lockdown in the US. Further, the Company has not experienced any shutdown of this nature to date, and the Company’s business model naturally lends itself to a socially distant operating environment provided that the majority of our employees are most commonly working alone or in small teams in remote areas when servicing wells. Accordingly no principal risk associated with COVID-19 was identified.

Based on the above the Directors have reviewed the Company’s overall position and outlook and are of the opinion that the Company is sufficiently well funded to be able to operate as a going concern for at least the next twelve months from the date of approval of the Consolidated Financial Statements.

Prior Period Reclassifications and Changes in Presentation

The Company has reclassified certain amounts in its prior year Consolidated Statement of Cash Flows to conform to its current period presentation. These changes in classification do not affect total comprehensive income previously reported the Consolidated Statement of Cash Flows.

Reclassifications in the Consolidated Statement of Cash Flows. During the year ended December 31, 2020, the Company reclassified $893 in “Contingent consideration payments” from “Cash flows from financing activities” to “Cash flows from investing activities”.

Changes in Presentation. During the year ended December 31, 2020, the Company combined $478 in “Merger reserve,” $592 in “Capital redemption reserve,” and $8,683 in “Share-based payment reserve” into the combined ending balance of $8,797. These balances have now been presented under the new financial statement line item “Share based payment and other reserves” on the Consolidated Statement of Financial Position and the Consolidated Statement of Changes in Equity.

Basis of Consolidation

The Consolidated Financial Statements for the year ended December 31, 2021 reflect the following corporate structure of the Company:

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 2—BASIS OF PREPARATION (continued)

The Company, and its 100% wholly owned subsidiaries:

—

Diversified Energy Company PLC (“DEC”) as well as its wholly owned subsidiaries

—

Diversified Gas & Oil Corporation

Diversified Production, LLC

—

Diversified ABS Holdings LLC

Diversified ABS LLC

—

Diversified ABS Phase II Holdings LLC

Diversified ABS Phase II LLC

—

Diversified ABS Phase III Holdings LLC(a)

—

Diversified ABS Phase IV Holdings LLC(a)

Diversified ABS Phase IV LLC

—

DP Bluegrass Holdings LLC

DP Bluegrass LLC

—

BlueStone Natural Resources II LLC

—

Chesapeake Granite Wash Trust(b)

—

Tapstone Energy Holdings, LLC

Tapstone Energy Holdings II, LLC

Tapstone Energy Holdings III, LLC

Tapstone Energy, LLC

—

Tapstone Manager, LLC

—

Tapstone Management Company, LLC(c)

—

Tapstone Midstream, LLC

—

Giant Land, LLC(d)

—

Beehive Land, LLC(d)

—

Castle Land, LLC(d)

—

Daisy Land, LLC(d)

—

Eureka Land, LLC(d)

—

Link Land, LLC(d)

—

Old Faithful Land, LLC(d)

—

Rift Land, LLC(d)

—

Riverside Land, LLC(d)

—

Spendid Land, LLC(d)

Diversified Midstream LLC

—

Cranberry Pipeline Corporation

—

Coalfield Pipeline Company

—

DM Bluebonnet LLC

—

Diversified Energy Marketing LLC

DGOC Holdings LLC

—

DGOC Holdings Sub III LLC

(a)

These legal entities were formed prior to December 31, 2021, however, the ABS III and ABS IV transactions did not close until subsequent to December 31, 2021.

(b)

Diversified Production, LLC holds 50.8% of the issued and outstanding common shares of Chesapeake Granite Wash Trust.

(c)

Owned 99.9% by Tapstone Energy LLC and 0.1% by Tapstone Manager LLC.

(d)

Owned 55% by Tapstone Energy LLC.

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES

The preparation of the Consolidated Financial Statements in compliance with International Financial Reporting Standards as issued by the International Accounting Standards Board requires management to make estimates and exercise judgment in applying the Company’s accounting policies. In preparing the Consolidated Financial Statements, the significant judgments made by management in applying the Company’s accounting policies and the key sources of estimation uncertainty are disclosed in Note 4.

Business Combinations and Asset Acquisitions

The Company performs an assessment of each acquisition to determine whether the acquisition should be accounted for as an asset acquisition or a business combination. For each transaction, the Company may elect to apply the concentration test under the IFRS 3 amendment to determine if the fair value of assets acquired is substantially concentrated in a single asset (or a group of similar assets). If this concentration test is met, the acquisition qualifies as an acquisition of a group of assets and liabilities, not of a business.

Accounting for business combinations under IFRS 3 is applied once it is determined that a business has been acquired. Under IFRS 3, a business is defined as an integrated set of activities and assets conducted and managed for the purpose of providing a return to investors. A business generally consists of inputs, processes applied to those inputs, and resulting outputs that are, or will be, used to generate revenues.

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES (continued)

When less than the entire interest of an entity is acquired, the choice of measurement of the non-controlling interest, either at fair value or at the proportionate share of the acquiree’s identifiable net assets, is determined on a transaction by transaction basis.

More information regarding the judgments and conclusions reached with respect to business combinations and asset acquisitions is included in Notes 4 and 5.

Oaktree Capital Management, L.P. (“Oaktree”) Participation Agreement

In October 2020, the Company entered into a definitive participation agreement with funds managed by Oaktree to jointly identify and fund future proved developed producing acquisition opportunities (“PDP acquisitions”) that the Company identifies. The Oaktree Funding Commitment provides for up to $1,000,000 in aggregate over three years for mutually agreed upon PDP acquisitions with transaction valuations typically greater than $250,000. The Company and Oaktree each funded 50% of the net purchase price in exchange for proportionate working interests of 51.25% and 48.75%, respectively, in the acquired assets. The Company’s greater share reflects the upfront promote it will receive from Oaktree (2.5% of Oaktree’s investment) which is intended to compensate the Company for the increase in general and administrative expenses needed to operate an entity that increases with acquired growth. Additionally, upon Oaktree achieving a 10.0% unlevered internal rate of return, Oaktree will convey a back-end promote to the Company which will increase the Company’s working interest to 60%. The Company also maintains the right of first offer to acquire Oaktree’s interest if and when Oaktree decides to divest. The Company and Oaktree each have the right to participate in a sale by the other party with a third-party upon comparable terms.

When jointly participating in mineral interest acquisitions the arrangement is evaluated under IFRS 11 as a joint operation and the Company consolidates its proportionate share of the assets and liabilities acquired similar to how the Company is currently accounting for wells in which it does not own the full working interest. When jointly acquiring other assets or businesses that exclude mineral rights, the arrangement is assessed under IFRS 10 and fully consolidated when control exits.

Inventory

Natural gas inventory is stated at the lower of cost and net realizable value, cost being determined on a weighted average cost basis. Inventory also consists of material and supplies used in connection with the Company’s maintenance, storage and handling. Inventory is stated at the lower of cost or net realizable value.

Cash and Cash Equivalents

Cash on the balance sheet comprises cash at banks. Balances held at banks, at times, exceed US federally insured amounts. The Company has not experienced any losses in such accounts and the Directors believe the Company is not exposed to any significant credit risk on its cash. As of December 31, 2021 and 2020, the Company’s cash balance was $12,558 and $1,379, respectively.

Trade Receivables

Trade receivables are stated at the historical carrying amount, net of any provisions required. Trade receivables are due from customers throughout the natural gas and oil industry. Although diversified among several customers, collectability is dependent on the financial condition of each individual customer as well as the general economic conditions of the industry. The Directors review the financial condition of customers prior to extending credit and generally do not require collateral to support the recoverability of the Company’s trade receivables. Any changes in the Directors’ allowance for current expected credit losses during the year are recognized in the Consolidated Statement of Comprehensive Income. Trade receivables also include certain receivables from third-party working interest owners. The Company consistently assesses the collectability of these receivables. As of December 31, 2021 and 2020, the Company considered

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES (continued)

a portion of these working interest receivables uncollectable and recorded an allowance for credit losses in the amount of $6,141 and $11,082, respectively. See Note 14 for additional information.

Impairment of Financial Assets

IFRS 9, Financial Instruments (“IFRS 9”), requires the application of an expected credit loss model in considering the impairment of financial assets. The expected credit loss model requires the Company to account for expected credit losses and changes in those expected credit losses at each reporting date to reflect changes in credit risk since initial recognition of the financial assets. The credit event does not have to occur before credit losses are recognized. IFRS 9 allows for a simplified approach for measuring the loss allowance at an amount equal to lifetime expected credit losses for trade receivables and contract assets.

The Company applies the simplified approach to the expected credit loss model to trade receivables arising from:

•

Sales of natural gas, NGLs and oil;

•

Sales of gathering and transportation of third-party natural gas; and

•

The provision of other services.

Borrowings

Borrowings are recognized initially at fair value, net of any applicable transaction costs incurred. Borrowings are subsequently carried at amortized cost. Any difference between the proceeds (net of transaction costs) and the redemption value is recognized in the Consolidated Statement of Comprehensive Income over the period of the borrowings using the effective interest method (if applicable).

Interest on borrowings is accrued as applicable to each class of borrowing.

Derivative Financial Instruments

Derivatives are used as part of the Company’s overall strategy to mitigate risk associated with the unpredictability of cash flows due to volatility in commodity prices. Further details of the Company’s exposure to these risks are detailed in Note 25. The Company has entered into financial instruments which are considered derivative contracts, such as swaps and collars, which result in net cash settlement each month and do not result in physical deliveries. The derivative contracts are initially recognized at fair value at the date the contract is entered into and remeasured to fair value every balance sheet date. The resulting gain or loss is recognized in the Consolidated Statement of Comprehensive Income in the year incurred in the Gain (loss) on derivative financial instruments line item.

Restricted Cash

Cash held on deposit for bonding purposes is classified as restricted cash and recorded within current and non-current assets. The cash (1) is restricted in use by state governmental agencies to be utilized and drawn upon if the operator should abandon any wells, or (2) is being held as collateral by the Company’s surety bond providers. Additionally, the Company is required to maintain certain reserves for interest payments related to its asset-backed security financings discussed in Note 21. These reserves approximate seven and a half months of interest and any associated fees. The Company classifies restricted cash as current or non-current based on the classification of the associated asset or liability to which the restriction relates.

	December 31, 2021			December 31, 2020
Cash restricted by asset backed securitizations		$	18,069		$	20,100
Other restricted cash			1,033			250
Total restricted cash		$	19,102		$	20,350

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES (continued)

Natural Gas and Oil Properties

Development and Acquisition Costs

Expenditures related to the construction, installation or completion of infrastructure facilities, such as platforms, and the drilling of development wells, including delineation wells, are capitalized within natural gas and oil properties. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, and the initial estimate of the asset retirement obligation. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

Depletion

Natural gas and oil properties are depleted on a unit-of-production basis over the proved reserves of the geographic region concerned, except in the case of assets whose useful life is shorter than the lifetime of the region, in which case the straight-line method is applied. Rights and concessions are depleted on the unit-of-production basis over the total proven reserves of the relevant area. The unit-of-production rate for the depreciation of development costs considers expenditures incurred to date, together with sanctioned future development expenditure.

Intangible Assets

Software Development and Acquisition Costs

Development costs that are directly attributable to the design and testing of identifiable and unique software products controlled by the Company are recognized as intangible assets where the following criteria are met:

•

It is technically feasible to complete the software so that it will be available for use;

•

The Directors intend to complete the software and use or sell it;

•

There is an ability to use the software;

•

It can be demonstrated how the software will generate probable future economic benefits;

•

Adequate technical, financial and other resources to complete the development and to use the software are available; and

•

The expenditure attributable to the software during its development can be reliably measured.

Directly attributable costs that are capitalized as part of the software include employee costs and an appropriate portion of relevant overheads. Capitalized development costs are recorded as intangible assets and amortized from the point at which the asset is ready for use. Costs associated with maintaining software programs are recognized as an expense as incurred.

Impairment of Intangible Assets

Intangible assets are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognized for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs of disposal and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows which are largely independent of the cash inflows from other assets or groups of assets (cash-generating units). Intangible assets that suffer an impairment are reviewed for possible reversal of the impairment at the end of each reporting period.

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TABLE OF CONTENTS

Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES (continued)

Amortization

The Company amortizes intangible assets with a limited useful life, using the straight-line method over the following periods:

	Range in Years
Software		3 – 5
Other acquired intangibles		3

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation and impairment losses, if any. The cost of property, plant and equipment initially recognized includes its purchase price and any cost that is directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by the Directors.

Property, plant and equipment are generally depreciated on a straight-line basis over their estimated useful lives:

	Range in Years
Buildings and leasehold improvements		10��– 40
Equipment		5 – 10
Motor vehicles		5
Midstream assets		10 – 15
Other property and equipment		5 – 10

Property, plant and equipment held under leases are depreciated over the shorter of lease term or estimated useful life.

Impairment of Non-Financial Assets

At each reporting date, the Directors assess whether indications exist that an asset may be impaired. If indications exist, or when annual impairment testing for an asset is required, the Directors estimate the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s, or cash generating unit’s, fair value less costs to sell and its value-in-use, and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. Where the carrying amount of an asset or cash-generating unit exceeds its recoverable amount, the Directors consider the asset impaired and write the asset down to its recoverable amount. In assessing value-in-use, the Directors discount the estimated future cash flows to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, the Directors consider recent market transactions, if available. If no such transactions can be identified, the Directors will utilize an appropriate valuation model.

Leases

The Company recognizes a right-of-use asset and a lease liability at the commencement date of contracts (or separate components of a contract) which convey to the Company the right to control the use of an identified asset for a period of time in exchange for consideration, when such contracts meet the definition of a lease as determined by IFRS 16, Leases (“IFRS 16”). The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at inception date.

The Company initially measures the lease liability at the present value of the future lease payments. The lease payments are discounted using the interest rate implicit in the lease. When this rate cannot be readily

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES (continued)

determined, the Company uses its incremental borrowing rate. After the commencement date, the lease liability is reduced for payments made by the lessee and increased for interest on the lease liability.

Right-of-use assets are initially measured at cost, which comprises:

•

The amount of the initial measurement of the lease liability;

•

Any lease payments made at or before the commencement date, less any lease incentives received, any initial direct costs incurred by the lessee; and

•

An estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease unless those costs are incurred to produce inventories.

Subsequent to the measurement date, the right-of-use asset is depreciated on a straight line basis for a period of time that reflects the life of the underlying asset, and also adjusted for the remeasurement of any lease liability.

Asset Retirement Obligations

Where a liability for the retirement of a well, removal of production equipment and site restoration at the end of the production life of a well exists, the Company recognizes a liability for asset retirement. The amount recognized is the present value of estimated future net expenditures determined in accordance with our anticipated retirement plans as well as with local conditions and requirements. The unwinding of the discount on the decommissioning liability is included as accretion of the decommissioning provision. The cost of the relevant property, plant and equipment asset is increased with an amount equivalent to the liability and depreciated on a unit of production basis. The Company recognizes changes in estimates prospectively, with corresponding adjustments to the liability and the associated non-current asset.

As of December 31, 2021 and 2020, the Company had no midstream asset retirement obligations.

Taxation

Deferred Taxation

Deferred tax is provided in full on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Consolidated Financial Statements. Deferred tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the balance sheet date and are expected to apply when the related deferred tax is realized or the deferred liability is settled.

Deferred tax assets are recognized to the extent that it is probable that the future taxable profit will be available against which the temporary differences can be utilized.

Income Taxation

Current income tax assets and liabilities for the years ended December 31, 2021 and 2020 were measured at the amount to be recovered from, or paid to, the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted at the reporting date in the jurisdictions where the Company operates and generates taxable income.

Uncertain Tax Positions

Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation and considers whether it is probable that a taxation authority will accept an uncertain tax treatment. The Company measures its tax balances based on either the most likely amount, or the expected value, depending on which method provides a better prediction of the resolution of the uncertainty.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES (continued)

Revenue Recognition

Natural Gas, NGLs and Oil

Commodity revenue is derived from sales of natural gas, NGLs and oil products and is recognized when the customer obtains control of the commodity. This transfer generally occurs when product is physically transferred into a vessel, pipe, sales meter or other delivery mechanism. This also represents the point at which the Company carries out its single performance obligation to its customer under contracts for the sale of natural gas, NGLs and oil.

Commodity revenue in which the Company has an interest with other producers is recognized proportionately based on the Company’s working interest and the terms of the relevant production sharing contracts. The portion of revenue that is due to minority working interest is included as a liability in Note 23.

Commodity revenue is recorded based on the volumes accepted each day by customers at the delivery point and is measured using the respective market price index for the applicable commodity plus or minus the applicable basis differential based on the quality of the product.

Third-Party Gathering Revenue

Revenue from gathering and transportation of third-party natural gas is recognized when the customer transfers its natural gas to the entry point in the Company’s midstream network and becomes entitled to withdraw an equivalent volume of natural gas from the exit point in the Company’s midstream network under contracts for the gathering and transportation of natural gas. This transfer generally occurs when product is physically transferred into the Company’s vessel, pipe, or sales meter. The customer’s entitlement to withdraw an equivalent volume of natural gas is broadly coterminous with the transfer of natural gas into the Company’s midstream network. Customers are invoiced and revenue is recognized each month based on the volume of natural gas transported at a contractually agreed upon price per unit.

Other Revenue

Revenue from the operation of third-party wells is recognized as earned in the month work is performed and consistent with the Company’s contractual obligations. The Company’s contractual obligations in this respect are considered to be its performance obligations for the purposes of IFRS 15, Revenue from Contracts with Customers (“IFRS 15”).

Revenue from the sale of water disposal services to third-parties into the Company’s disposal wells is recognized as earned in the month the water was physically disposed at a contractually agreed upon price per unit. Disposal of the water is considered to be the Company’s performance obligation under these contracts.

Revenue is stated after deducting sales taxes, excise duties and similar levies.

Share-Based Payments

The Company accounts for share-based payments under IFRS 2, Share-Based Payment (“IFRS 2”). All of the Company’s share-based awards are equity settled. The fair value of the awards are determined at the date of grant. As of December 31, 2021 and 2020, the Company had three types of share-based payment awards: restricted stock units (“RSUs”), performance stock units (“PSUs”) and Non-Qualified Stock Options (“Options”). The fair value of the Company’s RSUs is measured using the stock price at the grant date. The fair value of the Company’s PSUs is measured using a Monte Carlo simulation model. The inputs to the Monte Carlo simulation model included:

•

The share price at the date of grant;

•

Expected volatility;

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES (continued)

•

Expected dividends;

•

Risk free rate of interest; and

•

Patterns of exercise of the plan participants.

The fair value of the Company’s Options are calculated using the Black-Scholes model as of the grant date. The inputs to the Black-Scholes model included:

•

The share price at the date of grant;

•

Exercise price;

•

Expected volatility; and

•

Risk-free rate of interest.

The grant date fair value of share-based awards, adjusted for market-based performance conditions, are expensed uniformly over the vesting period.

New Standards and Interpretations

Certain new accounting standards and interpretations have been published that are not mandatory for December 31, 2021 reporting periods and have not been early adopted by the Company. None of these new standards or interpretations are expected to have a material impact on the consolidated financial statements of the Company.

NOTE 4—SIGNIFICANT ACCOUNTING JUDGMENTS AND ESTIMATES

In application of the Company’s accounting policies, described in Note 3, the Directors have made the following judgments and estimates which may have a significant effect on the amounts recognized in the Consolidated Financial Statements.

Significant Judgments

Business Combinations and Asset Acquisitions

The Company follows the guidance in IFRS 3, Business Combinations (“IFRS 3”) for determining the appropriate accounting treatment for acquisitions. IFRS 3 permits an initial fair value assessment to determine if substantially all of the fair value of the assets acquired is concentrated in a single asset or group of similar assets. If the initial screening test is not met, the asset is considered a business based on whether there are inputs and substantive processes in place. Based on the results of this analysis and conclusion on an acquisition’s classification of a business combination or an asset acquisition, the accounting treatment is derived.

If the acquisition is deemed to be a business, the acquisition method of accounting is applied. Identifiable assets acquired and liabilities assumed at the acquisition date are recorded at fair value. When the fair value exceeds the consideration transferred, a bargain purchase gain is recognized. Conversely, when the consideration transferred exceeds the fair value, goodwill is recorded. If the transaction is deemed to be an asset purchase, the cost accumulation and allocation model is used whereby the assets and liabilities are recorded based on the purchase price and allocated to the individual assets and liabilities based on relative fair values. As a result, bargain purchase gains are not recognized on asset acquisitions. Additionally, in instances when the acquisition of a group of assets contains contingent consideration, the Company records changes in the fair value of the contingent consideration through the basis of the asset acquired rather than through the Consolidated Statement of Comprehensive Income. More information regarding conclusions reached with respect to this judgment is included in Note 5.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 4—SIGNIFICANT ACCOUNTING JUDGMENTS AND ESTIMATES (continued)

The determination and allocation of fair values to the identifiable assets acquired and liabilities assumed are based on various assumptions and valuation methodologies requiring considerable judgment by management. The most significant variables in these valuations are discount rates and other assumptions and estimates used to determine the cash inflows and outflows. Management determines discount rates based on the risk inherent in the acquired assets, specific risks, industry beta and capital structure of guideline companies. The valuation of an acquired business is based on available information at the acquisition date and assumptions that are believed to be reasonable. However, a change in facts and circumstances as of the acquisition date can result in subsequent adjustments during the measurement period, but no later than one year from the acquisition date.

Significant Estimates

Estimating the Fair Value of Natural Gas and Oil Properties

The Company determines the fair value of its natural gas and oil properties acquired in business combination using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and natural gas and oil forward prices. The future net cash flows are discounted using a weighted average cost of capital as well as any additional risk factors. Proved reserves are estimated by reference to available geological and engineering data and only include volumes for which access to market is assured with reasonable certainty. Estimates of proved reserves are inherently imprecise, require the application of judgment and are subject to regular revision, either upward or downward, based on new information such as from the drilling of additional wells, observation of long-term reservoir performance under producing conditions and changes in economic factors, including product prices, contract terms or development plans. Sensitivity analysis on the significant inputs to the fair value is included in Note 5.

Impairment of Natural Gas and Oil Properties

In preparing the Consolidated Financial Statements the Directors considered that a key judgment was whether there was any evidence that the natural gas and oil properties were impaired. When making this assessment, producing assets are reviewed for indicators of impairment at the balance sheet date. Indicators of impairment for the Company’s producing assets can include significant or prolonged:

•

Decreases in commodity pricing or other negative changes in market conditions;

•

Downward revisions of reserve estimates; or

•

Increases in operating costs.

The Company reviews the carrying value of its natural gas and oil properties annually or when an indicator of impairment is identified. The impairment test compares the carrying value of natural gas and oil properties to their recoverable amount based on the present value of estimated future net cash flows from the proved natural gas and oil reserves. The future cash flows are calculated using estimated reserve quantities, costs to produce and develop reserves, and natural gas and oil forward prices. The fair value of proved reserves is estimated by reference to available geological and engineering data and only include volumes for which access to market is assured with reasonable certainty. When the carrying value is in excess of the fair value, the Company recognizes an impairment by writing down the value of its natural gas and oil properties to their fair value. No such impairments were recorded during the years ended December 31, 2021 and 2020.

Where there has been a charge for impairment in an earlier period, that charge will be reversed in a later period when there has been a change in circumstances to the extent that the recoverable amount is higher than the net book value at the time. In reversing impairment losses, the carrying amount of the asset will be increased to the lower of its original carrying value or the carrying value that would have been determined (net of depletion) had no impairment loss been recognized in prior years. No such recoveries were recorded during the years ended December 31, 2021 and 2020. Refer to Note 19 for additional information.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 4—SIGNIFICANT ACCOUNTING JUDGMENTS AND ESTIMATES (continued)

When applicable, the Company recognizes impairment losses in the Consolidated Statement of Comprehensive Income in those expense categories consistent with the function of the impaired asset.

Reserve Estimates

Reserves are estimates of the amount of natural gas, NGLs and oil product that can be economically and legally extracted from the Company’s properties. To calculate the reserves, significant estimates and assumptions are required about a range of geological, technical and economic factors, including quantities, production techniques, recovery rates, production costs, transport costs, commodity demand, commodity prices and exchange rates.

Estimating the quantity and/or grade of reserves requires the size, shape and depth of fields to be determined by analyzing geological data, such as drilling samples. This process may require complex and difficult geological judgments and calculations to interpret the data.

Given the economics used to estimate reserve changes from year to year and, because additional geological data is generated during the course of operations, estimates of reserves may change from time to time.

Taxation

The Company makes certain estimates in calculating deferred tax assets and liabilities, as well as income tax expense. These estimates often involve judgment regarding differences in the timing and recognition of revenue and expense for tax and financial reporting purposes as well as the tax basis of our assets and liabilities at the balance sheet date before tax returns are completed. Additionally, the Company must assess the likelihood that it will be able to recover or utilize its deferred tax assets and record a valuation allowance against deferred tax assets when all or a portion of that asset is not expected to be realized. In evaluating whether a valuation allowance should be applied, the Company considers evidence such as future taxable income, among other factors, both positive and negative. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change and, in particular, decrease in a period where the Company determines it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely than not that the asset will be realized.

Asset Retirement Obligation Costs

The ultimate asset retirement obligation 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 or experience at other production sites. The expected timing and amount of expenditures can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, significant estimates and assumptions are made in determining the provision for asset retirement. These assumptions include the cost to plug the wells, the economic life of the wells and the discount rate. Changes in assumptions related to the Company’s asset retirement obligations could result in a material change in the carrying value within the next financial year. Refer to Note 19 for more information and sensitivity analysis.

NOTE 5—ACQUISITIONS AND DIVESTITURES

The assets acquired in all acquisitions include the necessary permits, rights to production, royalties, assignments, contracts and agreements that support the production from wells and operation of pipelines. The Company determines the accounting treatment of acquisitions using IFRS 3.

As part of the Company’s corporate strategy it actively seeks to acquire assets when they meet the Company’s acquisition criteria of being long life, low-decline assets that strategically complement the Company’s existing portfolio.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 5—ACQUISITIONS AND DIVESTITURES (continued)

2021 Acquisitions

Tapstone Energy Holdings LLC (“Tapstone”) Business Combination

On December 7, 2021, the Company acquired a proportionate 51.25% working interest in certain upstream assets, field infrastructure, equipment, and facilities within the Central Region from Tapstone in conjunction with Oaktree, via the previously disclosed participation agreement between the two parties. The acquisition also included 5 wells which were under development at the time of close which will be completed by the Company. DEC will serve as the sole operator of the assets. When evaluating the transaction, DEC determined it did not have significant asset concentration and as a result it had acquired an identifiable set of inputs, processes and outputs and concluded the transaction was a business combination. The Company paid purchase consideration of $177,496, inclusive customary purchase price adjustments. Transaction costs associated with the acquisition were $4,039 and have been expensed. The Company funded the purchase with proceeds from the Credit Facility.

In connection with the acquisition the Company also acquired the beneficial ownership in the Chesapeake Granite Wash Trust (“the GWT”). The Company consolidates the GWT as it has determined that it controls the GWT because it (1) possesses power over the GWT, (2) has exposure to variable returns from its involvement with the GWT, and (3) has the ability to use its power over the GWT to affect its returns. The elements of control are achieved through the Company’s operating a majority of the natural gas and oil properties that are subject to the conveyed royalty interests, marketing of the associated production, and through its ownership of 50.8% of the outstanding common units of the GWT. The common units of the GWT owned by third parties have been reflected as a non-controlling interest in the consolidated financial statements. Common units outstanding as of December 7, 2021 were 46,750,000 with the Company’s beneficial interests in the GWT representing 50.8%. The GWT is publicly traded and the GWT’s market capitalization was utilized when determining the value of the non-controlling interests.

The GWT’s non-controlling interest is heavily concentrated in the acquired Tapstone natural gas and oil properties and as a result the Company has consolidated $16,087 into its natural gas and oil properties associated with this non-controlling interest as of December 31, 2021. The remaining amounts in the Company’s Consolidated Statement of Financial Position associated with non-controlling interest are immaterial and working capital in nature.

The provisional fair value of the assets and liabilities acquired exceeded the consideration transferred and resulted in a bargain purchase gain of $25,589. The gain is a function of Tapstone recently undergoing a troubled debt restructuring with its bank group and having sufficient motivation to sell.

In the period from its acquisition to December 31, 2021, the acquisition of Tapstone increased the Company’s production by 289 MBoe with average 2021 December production of 9 MBoepd. Revenues and operating expenses in this period were $12,844 and $2,271 respectively.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 5—ACQUISITIONS AND DIVESTITURES (continued)

The Company utilized a discount rate of 9.5% when determining the fair value of the Tapstone natural gas and oil properties. The provisional fair value of the assets acquired and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	177,496
Non-controlling interest		16,238
LESS: Cash acquired		(6,752)
Total consideration	$	186,982
Net assets acquired
Natural gas and oil properties	$	313,001
Natural gas and oil properties (asset retirement obligation, asset portion)		16,814
Property, plant and equipment(a)		4,739
Restricted cash		590
Other non-current assets		127
Trade receivables, net		48,298
Other current assets		2,343
Asset retirement obligation, liability portion		(16,814)
Leases		(700)
Borrowings		(3,801)
Deferred tax liability		(85,415)
Other non-current liabilities		(3,083)
Trade and other payables		(36,254)
Other current liabilities		(27,274)
Net assets acquired	$	212,571
Gain on bargain purchase		(25,589)
Purchase price	$	186,982

(a)

Includes $700 in right of use assets associated with the acquired leases.

As stated in Note 4, changes in the Company’s assumptions used for acquisitions could result in a material change of the fair value of the acquired reserves. The Company considers the discount rate, commodity pricing, production and operating expense to be the assumptions most sensitive to the fair value of the acquired reserves. The table below represents the impact a 10% change in the discount rate, commodity price, production and operating expense would have on the fair value of the acquired reserves provided this represents a reasonably possible change in these assumptions.

Adjusted fair value of natural gas and oil properties	+10%		-10%
Discount rate		(13,600)		15,200
Pricing(a)		48,000		(46,200)
Production		37,100		(37,000)
Operating expense		(8,400)		8,400

(a)

The Company performed the sensitivity analysis for changes in pricing by evaluating a 10% basis point change in the forward curve as of the acquisition date.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 5—ACQUISITIONS AND DIVESTITURES (continued)

Tanos Energy Holdings III, LLC (“Tanos”) Business Combination

On August 18, 2021, the Company acquired a 51.25% working interest in certain upstream assets, field infrastructure, equipment and facilities within the Central Region from Tanos, in conjunction with Oaktree, via the previously disclosed participation agreement between the two parties. The Company will serve as the sole operator of the assets. When evaluating the transaction, DEC determined it did not have significant asset concentration and as a result it had acquired an identifiable set of inputs, processes and outputs and concluded the transaction was a business combination. The Company paid purchase consideration of $116,061, including customary purchase price adjustments. Transaction costs associated with the acquisition were $2,384 and have been expensed. DEC funded the purchase with proceeds from a drawdown on the Credit Facility.

As part of the acquisition, the Company obtained the option to novate or extinguish the Tanos hedge book. In conjunction with the closing settlement, DEC elected to extinguish their share of the Tanos hedge book. The cost to terminate was $52,666. This payment relieved the termination liability established on the Company’s Consolidated Statement of Financial Position in purchase accounting and has been presented as an investing activity on the Consolidated Statement of Cash Flows given its connection to the Tanos acquisition. New contracts were subsequently entered into for more favorable pricing in order to secure the cash flows associated with these producing assets.

The provisional fair value of the assets and liabilities acquired exceeded the consideration transferred and resulted in a bargain purchase gain of $32,482. The gain is a function of Tanos being in a forbearance position with its bank group and having sufficient motivation to sell.

In the period from its acquisition to December 31, 2021 the acquisition of Tanos increased the Company’s production by 1,533 Mboe with average December 2021 production of 10 MBoepd. The properties associated with the acquisition have been integrated with the Company’s existing operations and it is impractical to provide stand-alone operational results related to these acquired properties for the twelve month period ended December 31, 2021.

The Company utilized a discount rate of 9.5% when determining the fair value of the Tanos natural gas and oil properties. The provisional fair value of the assets acquired and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	116,061
Total consideration	$	116,061
Net assets acquired
Natural gas and oil properties(a)	$	203,495
Natural gas and oil properties (asset retirement obligation, asset portion)		18,379
Property, plant and equipment		6,216
Trade receivables, net		1,377
Asset retirement obligation, liability portion		(18,379)
Other non-current liabilities		(2,111)
Other current liabilities(b)		(60,434)
Net assets acquired	$	148,543
Gain on bargain purchase		(32,482)
Purchase price	$	116,061

(a)

Includes undeveloped acreage of $33,911.

(b)

Includes the hedge book extinguishment liability of $52,666.

As stated in Note 4, changes in the Company’s assumptions used as inputs for acquisitions could result in a material change of the fair value of the acquired reserves. The Company considers the discount rate,

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 5—ACQUISITIONS AND DIVESTITURES (continued)

commodity pricing, production and operating expense assumptions to be the inputs most sensitive to the fair value of the acquired reserves. The table below represents the impact a 100 basis point adjustment in the discount rate, commodity price, production and operating expense would have on the fair value of the acquired reserves provided this represents a reasonably possible change in these assumptions.

Adjusted fair value of natural gas and oil properties	+10%		-10%
Discount rate		(7,200)		8,000
Pricing(a)		(29,400)		29,600
Production		(28,400)		28,400
Operating expense		10,900		(10,900)

(a)

The Company performed the sensitivity analysis for changes in pricing by evaluating a 10% basis point change in the forward curve as of the acquisition date.

Blackbeard Operating LLC (“Blackbeard”) Asset Acquisition

On July 5, 2021, the Company acquired certain upstream assets and related gathering infrastructure in the Central Region from Blackbeard. Given the concentration of assets this transaction was considered an asset acquisition rather than a business combination. When making this determination management performed an asset concentration test considering the fair value of the acquired assets. The Company paid purchase consideration of $170,523, including customary purchase price adjustments and transaction costs. Transaction costs associated with the acquisition were $3,644 and have been capitalized to natural gas and oil properties. The Company funded the purchase with proceeds from the May 2021 equity placement and a draw on the Credit Facility, discussed in Notes 16 and 21, respectively.

In the period from its acquisition to December 31, 2021 the acquisition of Blackbeard increased the Company’s production by 2,681 MBoe with average 2021 December production of 14 MBoepd.

The assets acquired and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	170,523
Total consideration	$	170,523
Net assets acquired
Natural gas and oil properties	$	167,338
Natural gas and oil properties (asset retirement obligation, asset portion)		22,890
Property, plant and equipment(a)		8,461
Trade receivables, net		471
Asset retirement obligation, liability portion		(22,890)
Leases		(917)
Other current liabilities		(4,830)
Net assets acquired	$	170,523

(a)

Includes $917 in right of use assets associated with the acquired leases.

Indigo Asset Acquisition

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 5—ACQUISITIONS AND DIVESTITURES (continued)

When making this determination management performed an asset concentration test considering the fair value of the acquired assets. The Company paid purchase consideration of $117,352, including customary purchase price adjustments and transaction costs. Transaction costs associated with the acquisition were $473 and have been capitalized to natural gas and oil properties. The Company funded the purchase with proceeds from the May 2021 equity placement and a draw on the Credit Facility, discussed in Notes 16 and 21, respectively.

In the period from its acquisition to December 31, 2021 the acquisition of Indigo increased the Company’s production by 2,011 MBoe with average 2021 December production of 7 MBoepd.

The assets acquired and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	117,352
Total consideration	$	117,352
Net assets acquired
Natural gas and oil properties	$	131,771
Natural gas and oil properties (asset retirement obligation, asset portion)		33,695
Property, plant and equipment(a)		6,545
Other non-current assets		575
Derivative financial instruments, net		(5,248)
Trade receivables, net		25
Leases		(6,445)
Asset retirement obligation, liability portion		(33,695)
Other current liabilities		(9,871)
Net assets acquired	$	117,352

(a)

Includes $6,445 in right of use assets associated with the acquired leases.

2021 Divestitures

Indigo Minerals LLC (“Indigo”) Divestiture

On July 9, 2021, the Company divested to Oaktree a non-operating 48.75% proportionate working interest in the Indigo assets that were previously acquired (as disclosed above) by the Company on May 19, 2021. The initial consideration received was $52,314, or 50% of the Company’s net purchase price on the Indigo assets which is consistent with the terms of the previously disclosed participation agreement between the Company and Oaktree. The Company will continue to serve as the sole operator of the assets. The Company used the proceeds to reduce outstanding balances on the Credit Facility.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 5—ACQUISITIONS AND DIVESTITURES (continued)

In June 2021 the average production of the divested assets was 7 MBoepd. The book value of the assets and liabilities divested, and provisional fair value of assets and liabilities assumed from the transaction were as follows:

Net assets divested
Natural gas and oil properties	$	(63,341)
Natural gas and oil properties (asset retirement obligation, asset portion)		(16,500)
Asset retirement obligation, liability portion		16,500
Other current liabilities		4,139
Net assets divested	$	(59,202)

In connection with the divestiture, the Company entered into a swap contract with Oaktree where the Company receives a market price and pays a fixed weighted average swap price of $2.86 per Mcfe. When considering the fair value of the swap arrangement as well as the value of the upfront promote received from Oaktree at the date of close the Company realized a loss of $1,461 on the divestiture.

Other Divestitures

On December 23, 2021, the Company divested certain predominantly undeveloped Haynesville Shale acreage in Texas, acquired as part of the Tanos acquisition. The total consideration received was $66,168 with DEC’s 51.25% interest through joint ownership with Oaktree generating net proceeds of $33,911 to DEC inclusive of customary purchase price adjustments.

2020 Acquisitions

Carbon Energy Corporation (“Carbon”) Business Combination

On May 26, 2020, the Company acquired certain upstream and midstream assets in the states of Kentucky, West Virginia and Tennessee from Carbon. When evaluating the transaction, the Company determined it had acquired an identifiable set of inputs, processes and outputs and concluded the transaction was a business combination. The Company initially paid purchase consideration of $98,120, excluding customary purchase price adjustments. Subsequent to the initial closing price the companies settled on a final closing statement and the Company paid an additional $3,370 in cash consideration for a total cash consideration of $101,490. Transaction costs associated with the acquisition were $1,118. The Company funded the cash consideration for the purchase with proceeds from the $160,000 Term Loan I, discussed in Note 21.

Carbon may earn additional contingent consideration of up to $15,000 in the aggregate. The contingent consideration will be calculated based on fixed volumes and the average settled natural gas pricing for 2020, 2021, and 2022 as compared to established benchmark pricing. Any payments due will be paid annually on 5 January through 2023 based on the contingent consideration calculation for the respective calendar years. Based on forward NYMEX natural gas prices the fair value of the contingent consideration as at the acquisition date was $5,463. As of December 31, 2021 the fair value of the contingent consideration was $14,992 and no contingent consideration payments have been made.

EQT Corporation (“EQT”) Asset Acquisition

On May 21, 2020, the Company acquired upstream assets and related gathering infrastructure in the states of Pennsylvania and West Virginia from EQT. Given the concentration of assets this transaction was considered an acquisition of assets rather than a business combination. The Company initially paid purchase consideration of $111,587, excluding customary purchase price adjustments. Subsequent to the initial closing price the companies settled on a final closing statement and the Company paid an additional $3,215 in cash consideration for a total cash consideration of $114,802. Transaction costs associated with the

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 5—ACQUISITIONS AND DIVESTITURES (continued)

acquisition were $1,069 and have been capitalized to natural gas and oil properties. The Company funded the purchase with proceeds from the $160,000 Term Loan I and a short-term draw from the Credit Facility, both discussed in Note 21.

EQT may earn additional contingent consideration of up to $20,000 in the aggregate. The contingent consideration is calculated based on the three-month average of the NYMEX Henry Hub natural gas settlement price relative to stated floor and target price thresholds beginning on 31 August 2020 and ending on 30 November 2022. Based on forward NYMEX natural gas prices the fair value of the contingent consideration as at the acquisition date was $7,082. As of December 31, 2021 the fair value of the contingent consideration was $7,511. The Company made contingent consideration payments of $10,561 and $893 during the years ended December 31, 2021 and 2020,

Other Asset Acquisitions of Natural Gas Properties

In December 2020, the Company acquired five gross unconventional Utica Shale horizontal wells in the state of Ohio. The Company paid purchase consideration of $7,083, excluding customary purchase price adjustments. Transaction costs associated with the acquisition were insignificant. The Company funded the cash consideration for the purchase with a draw on its Credit Facility.

Pro Forma Information (Unaudited)

The following table summarizes the unaudited pro forma condensed financial information of the Company as if the EQT and Carbon acquisitions each had occurred on January 1, 2020, and the Indigo, Blackbeard, Tanos and Tapstone acquisitions each had occurred on January 1, 2021.

	Year Ended
	December 31, 2021			December 31, 2020
Revenues		$	1,249,983		$	440,142
Net income (loss)		$	(279,121)		$	(21,373)

The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had the EQT and Carbon acquisitions each been completed at January 1, 2020, and the Indigo, Blackbeard, Tanos and Tapstone acquisitions each been completed at January 1, 2021, nor is it necessarily indicative of future operating results of the combined entities. The unaudited pro forma information gives effect to the acquisitions and any related equity and debt issuances, along with the use of proceeds therefrom, as if they had occurred on the respective dates discussed above and is a result of combining the statements of operations of the Company with the pre-acquisition results of EQT, Carbon, Indigo, Blackbeard, Tanos and Tapstone, including adjustment for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the acquisitions, and include adjustments to depreciation, depletion and amortization based on the purchase price allocated to property, plant and equipment and the estimated useful lives as well as adjustments to interest expense.

Subsequent Events

In April 2022, the Company acquired certain upstream assets and related facilities from a private seller, in conjunction with Oaktree, via the previously disclosed participation agreement between the two parties, for a gross purchase price of $100,000. The Company and Oaktree each funded 50% of the net purchase price in exchange for proportionate working interest of 52.5% and 47.5%, respectively, in the acquired assets.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 6—REVENUE

The Company extracts and sells natural gas, NGLs and oil to various customers in addition to operating a majority of these natural gas and oil wells for customers and other working interest owners. In addition, the Company provides gathering and transportation services to third parties. All revenue was generated in the US. The following table reconciles the Company’s revenue for the periods presented:

	Year Ended
	December 31, 2021				December 31, 2020
Natural gas		$	818,726			$	343,425
NGLs			115,747				23,173
Oil			38,634	��			15,064
Total commodity revenue		$	973,107			$	381,662
Midstream			31,988				25,389
Other			2,466				1,642
Total revenue		$	1,007,561			$	408,693

A significant portion of the Company’s trade receivables represent receivables related to either sales of natural gas, NGLs and oil or operational services, all of which are uncollateralized, and are collected within 30–60 days.

During the year ended December 31, 2021, two customers individually comprised more than 10% of total revenues, representing 22% of consolidated revenues, while during the year ended December 31, 2020, two customers individually comprised more than 10% of total revenues, representing 22% of consolidated revenues.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 7—EXPENSES BY NATURE

The following table provides a detail of the Company’s expenses for the periods presented:

	Year Ended
	December 31, 2021			December 31, 2020
LOE(a)		$	119,594		$	92,288
Production taxes(b)			30,518			13,705
Midstream operating expense(c)			60,481			52,815
Transportation expense(d)			80,620			45,155
Total operating expense(e)		$	291,213		$	203,963
Depreciation and amortization			44,841			33,673
Depletion			122,803			83,617
Total depreciation, depletion and amortization		$	167,644		$	117,290
Employees and benefits (administrative)			32,038			28,843
Other administrative(f)			13,885			9,650
Professional fees(g)			7,567			6,259
Auditors’ remuneration(h)			3,322			2,429
Costs associated with acquisitions(i)			31,335			10,465
Other adjusting costs(j)			6,779			14,581
Non–cash equity compensation(k)			7,400			5,007
Total G&A		$	102,326		$	77,234
Non–recurring allowance for credit losses			—			6,931
Recurring allowance for credit losses			(4,265)			1,559
Total allowance for credit losses(l)		$	(4,265)		$	8,490
Total expense		$	556,918		$	406,977
Aggregate remuneration (including Directors):
Wages and salaries		$	83,790		$	75,719
Payroll taxes			7,137			5,383
Benefits			19,083			14,926
Total employees and benefits expense		$	110,010		$	96,028

(a)

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

(b)

Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural gas, NGLs and oil production at fixed rates established by federal, state or local taxing authorities. Property taxes are generally based on the taxing jurisdictions’ valuation of the Company’s natural gas and oil properties and midstream assets.

(c)

Midstream operating expenses are daily costs incurred to operate the Company’s owned midstream assets inclusive of employee and benefit expenses.

(d)

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

(e)

Total operating expense increased due to additional operating expense related to the Tapstone, Tanos, Blackbeard and Indigo acquisitions in 2021 and the EQT and Carbon acquisitions, both acquired in 2020. Refer to Note 5 for additional information regarding acquisitions.

(f)

Other administrative expense includes general liability insurance, IT services, rent, other office expenses and travel.

(g)

Professional fees include legal, marketing, payroll and consultation fees and costs associated with being a public company.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 7—EXPENSES BY NATURE (continued)

(h)

Auditors’ remuneration includes fees payable to the Company’s auditors for the audit of the Company and its parent entity, Diversified Energy Company PLC, annual accounts, accounts of subsidiaries and other assurance services. Please refer to the table below for more information.

(i)

The Company generally incurs costs related to the integration of acquisitions which will vary for each acquisition. For acquisitions considered to be a business combination, these costs will include transaction costs directly associated with a successful acquisition transaction. These costs will also include costs associated with transition service arrangements with acquirees where the Company pays the acquirees a fee to handle various G&A functions until the Company has fully integrated the assets onto its system. In addition, these costs will also include costs related to integrating IT systems and consulting as well as internal workforce costs directly related to integrating acquisitions into the Company’s systems.

(j)

Other adjusting costs for 2021 are primarily associated with one-time projects and contemplated financing arrangements. Also included are expenses associated with an unused firm transportation agreement acquired as part of the Carbon acquisition. For 2020, other adjusting costs are associated with legal and professional fees related to the up-list to the Premium Segment of the Main Market of the LSE.

(k)

Non-cash equity compensation in 2021 and 2020, reflect the expense recognition related to share-based compensation provided to certain key members of the management team.

(l)

Allowance for credit losses consists of the recognition and reversal of credit losses. Refer to Note 14 for additional information regarding credit losses.

The number of employees was as follows for the years presented:

	Year Ended
	December 31, 2021		December 31, 2020
Number of production support employees, including Directors		283		183
Number of production employees		1,143		924
Workforce		1,426		1,107

The Directors consider that the Company’s key management personnel comprise the Directors. The Directors’ remuneration was as follows for the periods presented:

	Year Ended
	December 31, 2021			December 31, 2020
Executive Directors
Salary		$	1,119		$	1,090
Taxable benefits(a)			22			16
Benefit plan(b)			71			71
Bonus			1,427			1,537
Total Executive Directors’ remuneration			2,639			2,714
Non-Executive Directors
Salary			683			763
Total Non-Executive Directors’ remuneration			683			763
Total remuneration		$	3,322		$	3,477

(a)

Taxable benefits were comprised of Company paid life insurance premiums and automobile reimbursements.

(b)

Benefit plan amounts reflect matching contributions under the Company’s 401(k) plan.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 7—EXPENSES BY NATURE (continued)

Auditors’ remuneration for the Company was as follows for the periods presented:

	Year Ended
	December 31, 2021			December 31, 2020
Auditors’ remuneration (PwC)
Fees payable to the Company’s external auditors and their associates for the audit of the consolidated financial statements		$	1,694		$	1,196
Audit-related assurance services(a)			1,628			1,146
Other assurance services			—			87
Total auditors’ remuneration (PwC)		$	3,322		$	2,429

(a)

Fees incurred associated with the Company’s capital market activity which is outside the scope of the audit of the consolidated financial statements.

Subsequent Events

In February 2022 the Company paid $28,345 to terminate a fixed price purchase contract associated with certain Barnett volumes acquired during the Blackbeard acquisition. The contract extended through March 2024, and as a result of the termination, the Company will realize more favorable pricing over this period and be positioned to refinance these assets as part of the asset-backed securitization financing we announced in late February 2022 at a low 4.95%. The termination also enhanced the Company’s liquidity by eliminating the need for a $20,000 letter of credit on the Credit Facility.

NOTE 8—TAXATION

The Company files a consolidated US federal tax return, multiple state tax returns, and a separate UK tax return for the Parent entity. The consolidated taxable income includes an allocatable portion of income from the Company’s co-investments with Oaktree and its investment in the Chesapeake Granite Wash Trust. Income taxes are provided for the tax effects of transactions reported in the Consolidated Financial Statements and consist of taxes currently due plus deferred taxes related to differences between the basis of assets and liabilities for financial and income tax reporting.

For the taxable years ended December 31, 2021 and 2020, the Company had a tax benefit of $225,694 and $113,266, respectively. The effective tax rate used for the year ended December 31, 2021 was 41.0%, compared to 82.8% for the year ended December 31, 2020. The effective tax rate is primarily impacted by the Company’s recognition of the US marginal well tax credit available to qualified producers in 2021, who operate lower-volume wells during a low commodity pricing environment. The federal government provides these credits to encourage companies to continue operating lower-volume wells during periods of low prices to maintain the underlying jobs they create and the state and local tax revenues they generate for communities to support schools, social programs, law enforcement and other similar public services. The US marginal well tax credit is prescribed by Internal Revenue Code Section 45I and is available for certain natural gas production from qualifying wells. In June 2021, the US Internal Revenue Service released Notice 2021-34 which quantified the amount of credit per Mcf of qualified natural gas production for tax years beginning in 2020 and also detailed the calculation methodology for future years. The federal tax credit is intended to provide a benefit for wells producing less than 90 Mcfe per day when market prices for natural gas are relatively low. The Company benefits from this credit given its portfolio of long-life, low-decline conventional wells. Other impacts to the effective rate include changes in state tax rates as a result of acquisitions and recurring permanent differences, such as meals and entertainment.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 8—TAXATION (continued)

The provision for income taxes in the Consolidated Statement of Comprehensive Income is summarized below:

	Year Ended
	December 31, 2021			December 31, 2020
Current income tax expense
Federal		$	25,738		$	233
State			11,958			4,923
Foreign–UK			(52)			616
Total current income tax expense			37,644			5,772
Deferred income tax (benefit) expense
Federal			(233,679)			(108,627)
State			(29,597)			(10,411)
Foreign–UK			(62)			—
Total deferred income tax (benefit) expense			(263,338)			(119,038)
Total income tax (benefit) expense		$	(225,694)		$	(113,266)

The effective tax rates and differences between the statutory US federal income tax rate and the effective tax rates are summarized as follows:

	Year Ended
	December 31, 2021			December 31, 2020
Income (loss) before taxation		$	(550,900)		$	(136,740)
Income tax benefit (expense)			225,694			113,266
Effective tax rate			41.0%			82.8%

	Year Ended
	December 31, 2021		December 31, 2020
Expected tax at statutory US federal income tax rate		21.0%		21.0%
State income taxes, net of federal tax benefit		4.4%		5.4%
Federal credits		15.4%		58.8%
Other, net		0.2%		(2.4)%
Effective tax rate		41.0%		82.8%

The Company had a net deferred tax asset of $176,955 at December 31, 2021 compared to a net deferred tax liability of $969 at December 31, 2020. The change was primarily due to unrealized losses for unsettled derivatives not recognized for tax purposes, the recognition of federal tax credits, and deferred tax liabilities acquired as part of acquisition purchase accounting. The presentation in the balance sheet takes into consideration the offsetting of deferred tax assets and deferred tax liabilities within the same tax jurisdiction, where permitted. The overall deferred tax position in a particular tax jurisdiction determines if a deferred tax balance related to that jurisdiction is presented within deferred tax assets or deferred tax liabilities.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 8—TAXATION (continued)

The following table presents the components of the net deferred income tax asset included in non-current assets and net deferred income tax asset included in non-current assets as at the periods presented:

	December 31, 2021			December 31, 2020
Deferred tax asset
Asset retirement obligations		$	114,182		$	90,949
Derivative financial instruments			202,802			46,237
Allowance for doubtful accounts			1,735			2,968
Net operating loss carryover			562			474
Federal tax credits carryover			183,460			99,117
Other			13,306			4,160
Total deferred tax asset			516,047			243,905
Deferred tax liability
Amortization and depreciation			(266,988)			(244,874)
Investment in partnerships			(72,104)			—
Total deferred tax liability			(339,092)			(244,874)
Net deferred tax liability		$	176,955		$	(969)
Balance sheet presentation
Deferred tax asset		$	176,955		$	14,777
Deferred tax liability			—			(15,746)
Net deferred tax asset (liability)		$	176,955		$	(969)

In assessing the realizability of deferred tax assets, the Company considers whether it is probable that some or all the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible or before credits expire. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. The Company has determined, at this time, it will have sufficient future taxable income to recognize its deferred tax assets.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 8—TAXATION (continued)

The Company reported the effects of deferred tax expense as at and for the year ended December 31, 2021:

	Opening Balance			Consolidated Statement of Comprehensive Income			Other(a)			Closing Balance
Asset retirement obligations		$	90,949		$	19,052		$	4,181		$	114,182
Allowance for doubtful accounts			2,968			(1,320)			86			1,734
Net operating loss carryover			474			(1,655)			1,743			562
Federal tax credits carryover			99,117			84,343			—			183,460
Property, plant, and equipment and natural gas and oil properties			(244,874)			65,910			(88,023)			(266,987)
Derivative financial instruments			46,237			156,565			—			202,802
Investment in partnerships			—			(67,379)			(4,726)			(72,105)
Other			4,160			7,822			1,324			13,306
Total deferred tax asset (liability)		$	(969)		$	263,338		$	(85,415)		$	176,954

(a)

Amounts primarily relate to deferred taxes acquired as part of acquisition purchase accounting.

The Company reported the effects of deferred tax expense as at and for the year ended December 31, 2020:

	Opening Balance			Consolidated Statement of Comprehensive Income			Other(a)			Closing Balance
Asset retirement obligations		$	52,254		$	38,695		$	—		$	90,949
Allowance for doubtful accounts			841			2,127			—			2,968
Net operating loss carryover			43,263			(43,181)			392			474
Federal tax credits carryover			19,503			79,614			—			99,117
Property, plant, and equipment and natural gas and oil properties			(228,005)			(20,079)			3,210			(244,874)
Derivative financial instruments			(14,311)			60,548			—			46,237
Other			2,343			1,314			503			4,160
Total deferred tax asset (liability)		$	(124,112)		$	119,038		$	4,105		$	(969)

(a)

Amounts primarily relate to deferred taxes acquired as part of acquisition purchase accounting.

The Company’s material deferred tax assets and liabilities all arise in the US.

For US federal tax purposes, the Company is taxed as one consolidated entity. The Company’s co-investments with Oaktree and its investment in the Chesapeake Granite Wash Trust are taxed as partnerships that pass through to the Company’s consolidated return. The Company is subject to additional taxes in its domiciled jurisdiction of the UK. For the years ended December 31, 2021 and 2020, the Company incurred a benefit of $52 and expense of $616 in the UK, respectively.

The Company had no uncertain tax position liability at December 31, 2021 compared to a liability of $1,837 at December 31, 2020. The former uncertainty was in relation to a carried over tax position from the Alliance Petroleum acquisition for which the Company was indemnified. During 2021 the statute of

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 8—TAXATION (continued)

limitations associated with the uncertain tax position was met and the Company is no longer subject to the potential tax liability. As a result, the provision for the uncertain tax position and the indemnification receivable were removed.

At the date of acquisition, the Directors determined that Alliance Petroleum had taken uncertain tax positions. The Company had no other uncertain tax positions as at December 31, 2021.

At December 31, 2021, the Company had US federal net operating loss carryforwards (“NOLs”) of approximately $1,629, which are subject to limitation. Additionally, the Company had US state NOLs of approximately $3,729, which expire in the years 2034 through 2036.

The Company had US marginal well tax credit carryforwards of approximately $183,460 at December 31, 2021 compared to $99,117 at December 31, 2020. As discussed earlier, the federal tax credit is intended to provide a benefit for wells producing less than 90 Mcfe per day when market prices for natural gas are relatively low. Due to the low commodity price environment in 2020, the Company generated $84,958 of federal tax credits and utilized $2,445 for the year ended December 31, 2021. The tax credits expire in the years 2037 through 2041.

The Company had US federal capital loss carryforwards of $9,904 at December 31, 2021 and December 31, 2020. For the year ended December 31, 2021, no capital loss carryforwards expired, and the remaining amounts expire in 2023. The Company does not expect to utilize these carryforwards, and therefore, a deferred tax asset for these carryforwards has not been recorded.

The Company completed a Section 382 study through December 31, 2021 in accordance with the Internal Revenue Code of 1986, as amended. If the Company experiences an ownership change, tax credit carryforwards can be utilized but are limited each year and could expire before they are fully utilized. The study concluded that the Company has not experienced an ownership change as defined by Section 382 since the last ownership change that occurred on January 31, 2018. The Directors expect its tax credit carryforwards, limited by the January 31, 2018 ownership change, to be fully available for utilization by 2024.

NOTE 9—EARNINGS (LOSS) PER SHARE

The calculation of basic earnings (loss) per share is based on the income (loss) available to shareholders after taxation and on the weighted average number of shares outstanding during the period. The calculation of diluted earnings per share is based on the income (loss) available to shareholders after taxation and the weighted average number of shares outstanding plus the weighted average number of shares that would be issued if dilutive options and warrants were converted into shares on the last day of the reporting period. Basic and diluted earnings (loss) per share are calculated as follows for the periods presented:

		Year Ended
	Calculation	December 31, 2021			December 31, 2020
Net income (loss)	A		$	(325,206)		$	(23,474)
Weighted average shares outstanding – basic and diluted	B			793,542			685,170
Earnings (loss) per share – basic and diluted	= A/B		$	(0.41)		$	(0.03)

Due to the Company’s Net loss for the years ended December 31, 2021 and 2020, 6,493 and 3,178 potential shares were not included in the computation of diluted EPS because their effect would have been anti-dilutive.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 10—NATURAL GAS AND OIL PROPERTIES

The following table summarizes the Company’s natural gas and oil properties for the periods presented:

	Year Ended
	December 31, 2021			December 31, 2020
Costs
Beginning balance		$	1,968,557		$	1,625,884
Additions(a)			1,012,691			346,385
Disposals(b)			(114,895)			(3,712)
Ending balance		$	2,866,353		$	1,968,557
Depletion and impairment
Beginning balance		$	(213,472)		$	(129,855)
Period changes			(122,803)			(83,617)
Disposals			—			—
Ending balance		$	(336,275)		$	(213,472)
Net book value		$	2,530,078		$	1,755,085

(a)

For the year ended December 31, 2021, the Company added $907,383 related to acquisitions and $78,156 resulting from normal revisions to the Company’s asset retirement obligations. The remaining change is primarily attributable to recurring capital expenditures and the revaluation of the EQT contingent consideration. For the year ended December 31, 2020, the Company added $228,223 related to acquisitions. The remaining change is primarily attributable to revisions in the Company’s asset retirement obligations as a result of changes in the discount rate. Refer to Notes 5 and 19 for additional information regarding acquisitions and asset retirement obligations, respectively.

(b)

For the year ended December 31, 2021, the Company divested $113,752 in natural gas and oil properties related to Indigo and the Tanos undeveloped acreage transactions. Refer to Note 5 for additional information regarding divestitures. For the year ended December 31, 2020 the Company divested 662 wells in McKean, Forest, and Warren Counties, Pennsylvania.

Impairment Assessment for Natural Gas and Oil Properties

For the period ended December 31, 2021, the Directors assessed the indicators of impairment, noting strong pricing along the forward curve and an improving economic outlook for the Company. This assessment also included a comparison of the carrying value of the Company’s natural gas and oil properties to their fair values and an assessment of the projected impact of climate change on the Company. As a result of their assessments no impairment indicators were identified.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 11—PROPERTY, PLANT AND EQUIPMENT

The following tables summarize the Company’s property, plant and equipment for the periods presented:

	Year Ended December 31, 2021
	Buildings and Leasehold Improvements			Equipment			Motor Vehicles			Midstream Assets			Other Property and Equipment			Total
Costs
Beginning balance		$	28,190		$	6,768		$	35,129		$	367,331		$	5,600		$	443,018
Additions(a)(b)			13,494			2,737			12,700			31,485			10,439			70,855
Disposals			—			(13)			(2,267)			(153)			—			(2,433)
Ending balance(c)		$	41,684		$	9,492		$	45,562		$	398,663		$	16,039		$	511,440
Accumulated depreciation
Beginning balance		$	(1,007)		$	(2,860)		$	(12,409)		$	(43,597)		$	(1,042)		$	(60,915)
Period changes			(1,071)			(1,231)			(9,259)			(25,928)			(564)			(38,053)
Disposals			—			2			1,482			24			—			1,508
Ending balance		$	(2,078)		$	(4,089)		$	(20,186)		$	(69,501)		$	(1,606)		$	(97,460)
Net book value		$	39,606		$	5,403		$	25,376		$	329,162		$	14,433		$	413,980

	Year Ended December 31, 2020
	Buildings and Leasehold Improvements			Equipment			Motor Vehicles			Midstream Assets			Other Property and Equipment			Total
Costs
Beginning balance		$	22,654		$	4,438		$	19,099		$	306,537		$	2,205		$	354,933
Additions(a)(b)			5,536			2,415			19,127			60,794			3,395			91,267
Disposals			—			(85)			(3,097)			—			—			(3,182)
Ending balance(c)		$	28,190		$	6,768		$	35,129		$	367,331		$	5,600		$	443,018
Accumulated depreciation
Beginning balance		$	(559)		$	(1,987)		$	(7,251)		$	(23,455)		$	(728)		$	(33,980)
Period changes			(448)			(876)			(5,770)			(20,142)			(314)			(27,550)
Disposals			—			3			612			—			—			615
Ending balance		$	(1,007)		$	(2,860)		$	(12,409)		$	(43,597)		$	(1,042)		$	(60,915)
Net book value		$	27,183		$	3,908		$	22,720		$	323,734		$	4,558		$	382,103

(a)

Of the $70,855 in 2021 additions, $25,961 was related to acquisitions and $16,482 was associated with right-of-use asset additions for new and acquired leases. Of the $91,267 in 2020 additions, $46,713 and $10,956 were related to the acquisitions of Carbon and EQT, respectively, while $19,820 was associated with right-of-use asset additions for new and amended leases. Refer to Note 5 for additional information regarding acquisitions and divestitures.

(b)

Remaining additions are related to routine capital projects on the Company’s compressor and gathering systems, vehicle and equipment additions.

(c)

Buildings and Leasehold Improvements and Motor Vehicles are inclusive of right-of-use assets associated with the Company’s leases. Refer to Note 20 for additional information regarding leases.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 11—PROPERTY, PLANT AND EQUIPMENT (continued)

The Company continued to utilize certain fully depreciated assets during the years ended December 31, 2021 and December 31, 2020 with an original cost basis of $5,597 and $3,313, respectively.

NOTE 12—INTANGIBLE ASSETS

Intangible assets consisted of the following for the periods presented:

	Year Ended December 31, 2021
	Software			Other Acquired Intangibles			Total
Costs
Beginning balance		$	24,271		$	2,900		$	27,171
Additions(a)			3,824			—			3,824
Disposals			—			—			—
Ending balance		$	28,095		$	2,900		$	30,995
Accumulated amortization
Beginning balance		$	(7,246)		$	(712)		$	(7,958)
Period changes			(7,946)			(957)			(8,903)
Disposals			—			—			—
Ending balance		$	(15,192)		$	(1,669)		$	(16,861)
Net book value		$	12,903		$	1,231		$	14,134

	Year Ended December 31, 2020
	Software			Other Acquired Intangibles			Total
Costs
Beginning balance		$	17,822		$	—		$	17,822
Additions(a)			6,449			2,900			9,349
Disposals			—			—			—
Ending balance		$	24,271		$	2,900		$	27,171
Accumulated amortization
Beginning balance		$	(1,841)		$	—		$	(1,841)
Period changes			(5,405)			(712)			(6,117)
Disposals			—			—			—
Ending balance		$	(7,246)		$	(712)		$	(7,958)
Net book value		$	17,025		$	2,188		$	19,213

(a)

For the year ended December 31, 2021 additions were related to software enhancements. For the year ended December 31, 2020 additions were related to software enhancements and $2,900 in other acquired intangibles.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 13—DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to volatility in market prices and basis differentials for natural gas, NGLs and oil, which impacts the predictability of its cash flows related to the sale of those commodities. The Company is also exposed to volatility in interest rate markets, which impacts the predictability of its cash flows related to interest payments on the Company’s variable rate debt obligations. These risks are managed by the Company’s use of certain derivative financial instruments. As of December 31, 2021, the Company’s derivative financial instruments consisted of swaps, collars, basis swaps, stand-alone put and call options, and swaptions. A description of the Company’s derivative financial instruments is provided below:

•

Swaps: If the Company sells a swap, it receives a fixed price for the contract and pays a floating market price to the counterparty.

•

Collars: Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net costs. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price.

Certain collar arrangements may also include a sold put option with a strike price below the purchased put option. Referred to as a three-way collar, the structure works similar to the above description, except that when the index price settles below the sold put option, the Company pays the counterparty the difference between the index price and sold put option, effectively enhancing realized pricing by the difference between the price of the sold and purchased put option.

•

Basis swaps: Arrangements that guarantee a price differential for commodities from a specified delivery point. If the Company sells a basis swap, it receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

•

Put options: The Company purchases and sells put options in exchange for a premium. If the Company purchases a put option, it receives from the counterparty the excess (if any) of the market price below the strike price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party.

•

Call options: The Company purchases and sells call options in exchange for a premium. If the Company purchases a call option, it receives from the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company sells a call option, it pays the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party.

•

Swaptions: If the Company sells a swaption, the counterparty will receive the option to enter into a swap contract at a specified date and receives a fixed price for the contract and pays a floating market price to the counterparty.

The Company may elect to enter into offsetting transactions for the above instruments for the purpose of cancelling or terminating certain positions.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 13—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

The following tables summarize the Company’s calculated net fair value of derivative financial instruments as of the reporting date as follows:

	Weighted Average Price per Mcfe(a)
NATURAL GAS CONTRACTS	Volume (MMcf)		Swaps			Sold Puts			Purchased Puts			Sold Calls			Purchased Calls			Basis Differential			Fair Value at December 31, 2021
2022
Swaps		202,199		$	2.91		$	—		$	—		$	—		$	—		$	—		$	(169,964)
Collars		7,300			—			—			4.63			5.28			—			—			4,606
Stand-Alone Calls		35,650			—			—			—			2.97			3.00			—			(32,916)
Basis Swaps		159,549			—			—			—			—			—			(0.42)			13,581
Total 2022 contracts		404,698																				$	(184,693)
2023
Swaps		127,747		$	2.85		$	—		$	—		$	—		$	—		$	—		$	(88,147)
Three-Way Collars		5,400			—			2.14			2.81			3.58			—			—			(4,585)
Stand-Alone Calls		70,792			—			—			—			2.95			—			—			(57,253)
Basis Swaps		42,875			—			—			—			—			—			(0.71)			383
Total 2023 contracts		246,814																				$	(149,602)
2024
Swaps		86,319		$	2.66		$	—		$	—		$	—		$	—		$	—		$	(54,636)
Stand-Alone Calls		37,698			—			—			—			2.90			—			—			(26,388)
Total 2024 contracts		124,017																				$	(81,024)
2025
Swaps		65,864		$	2.55		$	—		$	—		$	—		$	—		$	—		$	(44,066)
Stand-Alone Calls		21,900			—			—			—			3.00			—			—			(13,119)
Total 2025 contracts		87,764																				$	(57,185)
2026
Swaps		42,454		$	2.53		$	—		$	—		$	—		$	—		$	—		$	(29,116)
2027
Swaps		33,820		$	2.50		$	—		$	—		$	—		$	—		$	—		$	(23,546)
2028
Swaps		32,190		$	2.49		$	—		$	—		$	—		$	—		$	—		$	(24,576)
2029
Swaps		29,190		$	2.48		$	—		$	—		$	—		$	—		$	—		$	(24,093)
2030
Swaps		5,450		$	2.43		$	—		$	—		$	—		$	—		$	—		$	(5,535)
Swaptions
10/1/2024 − 9/30/2028(b)		14,610		$	—		$	—		$	—		$	2.91		$	—		$	—		$	(7,178)
1/1/2025 − 12/31/2029(c)		36,520			—			—			—			2.77			—			—			(20,403)
4/1/2026 − 3/31/2030(d)		97,277			—			—			—			2.57			—			—			(70,681)
4/1/2030 − 3/31/2032(e)		42,627			—			—			—			2.57			—			—			(45,230)
Total 2025 − 2032 contracts		334,138																				$	(250,358)
Total natural gas contracts		1,197,431																				$	(722,862)

(a)

Rates have been converted from Btu to Mcfe using a Btu conversion factor of 1.07.

(b)

Option expires on 6 September 2024.

(c)

Option expires on 23 December 2024.

(d)

Option expires on 23 March 2026.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 13—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

(e)

Option expires on 22 March 2030.

	Weighted Average Price per Bbl
NGLs CONTRACTS	Volume (MBbls)		Swaps			Sold Puts			Purchased Puts			Sold Calls			Purchased Calls			Basis Differential			Fair Value at December 31, 2021
2022
Swaps		3,791		$	31.97		$	—		$	—		$	—		$	—		$	—		$	(60,192)
2023
Swaps		1,882		$	36.78		$	—		$	—		$	—		$	—		$	—		$	(6,014)
Stand-Alone Calls		365			—			—			—			24.78			—			—			(5,159)
Total NGLs contracts		6,038																				$	(71,365)

	Weighted Average Price per Bbl
OIL CONTRACTS	Volume (MBbls)		Swaps			Sold Puts			Purchased Puts			Sold Calls			Purchased Calls			Basis Differential			Fair Value at December 31, 2021
2022
Sold Swaps		1,000		$	67.12		$	—		$	—		$	—		$	—		$	—		$	(5,306)
2023
Swaps		428		$	60.75		$	—		$	—		$	—		$	—		$	—		$	(2,421)
Sold Calls		117			—			—			—			53.20			—			—			(2,213)
2024
Swaps		64		$	37.00		$	—		$	—		$	—		$	—		$	—		$	(1,610)
2025
Swaps		56		$	37.00		$	—		$	—		$	—		$	—		$	—		$	(1,249)
2026
Swaps		13		$	37.00		$	—		$	—		$	—		$	—		$	—		$	(281)
Total oil contracts		1,678																				$	(13,080)

INTEREST	Principal Hedged			Fixed-Rate		Fair Value at December 31, 2021
2022
LIBOR Interest Rate Swap		$	150,000		0.45%		$	(91)
Net fair value of derivative financial instruments at 31 December 2021							$	(807,398)

Netting the fair values of derivative assets and liabilities for financial reporting purposes is permitted if such assets and liabilities are with the same counterparty and a legal right of set-off exists, subject to a master netting arrangement. The Directors have elected to present derivative assets and liabilities net when these conditions are met. The following table outlines the Company’s net derivatives as of the reporting date as follows:

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 13—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

Derivative Financial Instruments	Consolidated Statement of Financial Position	December 31, 2021			December 31, 2020
Assets:
Non-current assets	Derivative financial instruments		$	219		$	717
Current assets	Derivative financial instruments			1,052			17,858
Total assets			$	1,271		$	18,575
Liabilities
Non-current liabilities	Derivative financial instruments		$	(556,982)		$	(168,524)
Current liabilities	Derivative financial instruments			(251,687)			(15,858)
Total liabilities			$	(808,669)		$	(184,382)
Net assets (liabilities):
Net assets (liabilities)– non-current	Other non-current assets (liabilities)		$	(556,763)		$	(167,807)
Net assets (liabilities)– current	Other current assets (liabilities)			(250,635)			2,000
Total net assets (liabilities)			$	(807,398)		$	(165,807)

The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

	As of December 31, 2021
	Presented without Effects of Netting			Effects of Netting			As Presented with Effects of Netting
Non-current assets		$	29,767		$	(29,548)		$	219
Current assets			62,144			(61,092)			1,052
Total assets		$	91,911		$	(90,640)		$	1,271
Non-current liabilities			(586,584)			29,602			(556,982)
Current liabilities			(312,725)			61,038			(251,687)
Total liabilities		$	(899,309)		$	90,640		$	(808,669)
Total net assets (liabilities)		$	(807,398)		$	—		$	(807,398)

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 13—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

	As of December 31, 2020
	Presented without Effects of Netting			Effects of Netting			As Presented with Effects of Netting
Non-current assets		$	25,159		$	(24,442)		$	717
Current assets			42,023			(24,165)			17,858
Total assets		$	67,182		$	(48,607)		$	18,575
Non–current liabilities			(192,967)			24,443			(168,524)
Current liabilities			(40,022)			24,164			(15,858)
Total liabilities		$	(232,989)		$	48,607		$	(184,382)
Total net assets (liabilities)		$	(165,807)		$	—		$	(165,807)

The Company recorded the following gain (loss) on derivative financial instruments in the Consolidated Statement of Comprehensive Income for the periods presented:

	Year Ended
	December 31, 2021			December 31, 2020
Net gain (loss) on commodity derivatives settlements(a)		$	(320,656)		$	144,600
Net gain (loss) on interest rate swaps(a)			(530)			(202)
Gain (loss) on foreign currency hedges(a)			(1,227)			—
Total gain (loss) on settled derivative instruments		$	(322,413)		$	144,398
Gain (loss) on fair value adjustments of unsettled financial instruments(b)			(652,465)			(238,795)
Total gain (loss) on derivative financial instruments		$	(974,878)		$	(94,397)

(a)

Represents the cash settlement of hedges that settled during the period.

(b)

Represents the change in fair value of financial instruments net of removing the carrying value of hedges that settled during the period.

All derivatives are defined as Level 2 instruments as they are valued using inputs and outputs other than quoted prices that are observable for the assets and liabilities.

Commodity Derivative Contract Modifications and Extinguishments

From time to time such as when acquiring producing assets, completing ABS financing arrangements or navigating changing price environments, the Company will opportunistically modify, offset, extinguish or add certain existing hedge positions. Modifications include the volume of production subject to contracts, the swap or strike price of certain derivative contracts and similar elements of the derivative contract.

In August 2021 as part of the Tanos acquisition, the Company obtained the option to novate or extinguish the Tanos hedge book. In conjunction with the closing settlement, DEC elected to extinguish their share of the Tanos hedge book. The cost to terminate was $52,666. This payment relieved the termination liability established on the Company’s Consolidated Statement of Financial Position in purchase accounting and has been presented as an investing activity in the Consolidated Statement of Cash Flows given its connection to the Tanos acquisition. New derivative contracts were subsequently entered into for more favorable pricing in order to secure the cash flows associated with these producing assets in an elevated price environment.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 13—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

terminate certain legacy Indigo derivative positions resulting in a cash payment of $6,797 which the Company recorded on its Consolidated Statement of Financial Position. Since this extinguishment occurred subsequent to the acquisition date the Company has presented this payment as an operating activity on the Consolidated Statement of Cash Flows. New derivative contracts were subsequently entered into for more favorable pricing in order to secure the cash flows associated with these producing assets in an elevated price environment.

Other commodity derivative contract modifications made during the normal course of business for the year ended December 31, 2021 totaled $3,367 which the Company recorded on its Consolidated Statement of Financial Position. As these modifications were made in the normal course, the Company has presented these as an operating activity in the Consolidated Statement of Cash Flows.

Subsequent Events

The Company maintains distinct, long-dated derivative contract portfolios for its ABS financings and Term Loan I. The Company also maintains a separate derivative contract portfolio related to its assets collateralized by the Credit Facility. In February 2022, the Company adjusted portions of its derivative contract portfolio across these legal entities to ensure that it maintains the appropriate level and composition at both the legal entity and full-Company level for the completion of the ABS III and ABS IV financing arrangements. The Company completed these portfolio adjustments by entering into new derivative commodity contracts and novating certain derivative contracts to the legal entities holding the ABS III and ABS IV notes. The Company incurred $41,896 for these portfolio adjustments including long dated puts purchased for ABS III and ABS IV that collectively increased the value of the Company’s derivative position by an equal amount. The Company recorded payments for offsetting positions as new derivative financial instruments and applied extinguishment payments against the existing commodity contracts on its Consolidated Statement of Financial Position.

In May 2022 the Company completed the ABS V financing arrangement and made similar derivative portfolio adjustments to maintain the appropriate level and composition of derivatives at both the legal entity and full-Company level. The Company incurred $31,250 for these portfolio adjustments. Similar to the prior transactions these payments included the purchase of puts that increased the value of the Company’s derivative position. The Company recorded payments for offsetting positions as new derivative financial instruments and applied extinguishment payments against the existing commodity contracts on its Consolidated Statement of Financial Position.

NOTE 14—TRADE AND OTHER RECEIVABLES

Trade receivables include amounts due from customers, entities that purchase the Company’s natural gas, NGLs and oil production, and also include amounts due from joint interest owners, entities that own a working interest in the properties operated by the Company. The majority of trade receivables are current and the Company believes these receivables are collectible. The following table summarizes the Company’s trade receivables. The fair value approximates the carrying value as at the periods presented:

	December 31, 2021			December 31, 2020
Commodity receivables(a)		$	275,295		$	70,199
Other receivables			13,768			7,874
Total trade receivables		$	289,063		$	78,073
Allowance for credit losses(b)			(6,141)			(11,082)
Total trade receivables, net		$	282,922		$	66,991

(a)

The increase in commodity receivables reflects the increase in commodity pricing over the course of 2021 as well as our growth through acquisitions.

(b)

The allowance for credit losses is primarily related to amounts due from joint interest owners.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 15—OTHER ASSETS

The following table includes details of other assets as of the periods presented:

	December 31, 2021			December 31, 2020
Other non-current assets
Other non-current assets		$	3,635		$	2,376
Indemnification receivable(a)			—			1,837
Total other non-current assets		$	3,635		$	4,213
Other current assets
Prepaid expenses		$	5,126		$	1,681
Other assets(b)			25,004			—
Inventory			9,444			6,315
Total other current assets		$	39,574		$	7,996

(a)

At the date of acquisition, the Directors determined that Alliance Petroleum had taken uncertain tax positions, and as a result, an indemnification agreement was executed. The Company recorded an uncertain tax position liability and indemnification receivable for the amount of $1,837 as of December 31, 2020. During 2021 the statute of limitations associated with the uncertain tax position was met and the Company is no longer subject to the potential tax liability associated with the tax position. As a result, the provision for the uncertain tax position and the indemnification receivable were removed.

(b)

Primarily consists of payments associated with potential acquisitions. These costs include deposits, right of first refusal or option agreement costs, and other acquisition related payments.

Subsequent Events

Acquiring long life stable assets is central to the Company’s strategy. At times, due to changing macroeconomic conditions, commodity price volatility and/or findings observed during the Company’s deal diligence efforts, the Company incurs breakage or deal sourcing fees. Subsequent to December 31, 2021 and due to decisions the Company made in the first quarter of 2022, the Company wrote off of $25,000 in certain acquisition related costs related to these items.

NOTE 16—SHARE CAPITAL

Share capital represents the nominal (par) value of shares (£0.01) that have been issued. Share premium includes any premiums received on issue of share capital above par. Any transaction costs associated with the issuance of shares are deducted from share premium, net of any related income tax benefits. The components of share capital include:

Issuance of Share Capital

In May 2021, the Company placed 141,541 new shares at $1.59 per share (£1.12) to raise gross proceeds of $225,050 (approximately £158,526). Associated costs of the placing were $11,206. The Company used the proceeds to pay down the Credit Facility and partially fund the Indigo and Blackbeard acquisitions, discussed in Notes 21 and 5, respectively.

In May 2020, the Company placed 64,281 new shares at $1.33 per share (£1.08) to raise gross proceeds of $85,415 (approximately £69,423). Associated costs of the placing were $4,008. The Company used the proceeds to partially fund the acquisition of certain assets of Carbon and EQT, discussed in Note 5.

Repurchase of Shares

During the year ended December 31, 2020, the Company repurchased 12,958 treasury shares at an average price of $1.21 totaling $15,634. The Company has accounted for the repurchase of these shares as a direct reduction to retained earnings.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 16—SHARE CAPITAL (continued)

All repurchased treasury shares have been cancelled.

Cancellation of Warrants

In January 2021, the Company entered into an agreement to cancel 2,377 warrants (the “Warrants”) held by Mirabaud Securities Limited (“Mirabaud”) and certain former Mirabaud employees for an aggregate principal amount of approximately $1,429 (approximately £1,040). Mirabaud and its former employees surrendered the Warrants to the Company for cancellation. Following this purchase, 1,123 warrants remain outstanding.

The following tables summarize the Company’s share capital, net of customary transaction costs, for the periods presented:

	Number of Shares		Total Share Capital			Total Share Premium
Balance as of December 31, 2019		655,730		$	8,800		$	760,543
Issuance of share capital		64,281			791			80,616
Repurchase of shares		(12,958)			(74)			—
Other issues(a)		324			3			—
Balance as of December 31, 2020		707,377		$	9,520		$	841,159
Issuance of share capital		141,541		$	2,044		$	211,800
Repurchase of shares		—			—			—
Other issues(a)		737			7			—
Balance as of December 31, 2021		849,655		$	11,571		$	1,052,959

(a)

During the years ended 31 December 2021 and 2020, the Company issued 737 and 324 RSUs, respectively, to certain key managers. The RSUs had no impact on share premium.

NOTE 17—NON-CASH SHARE-BASED COMPENSATION

Equity Incentive Plan

The 2017 Equity Incentive Plan (the “Plan”), as amended through 27 April 2021, authorized and reserved for issuance 65,681 shares of common stock, which may be issued upon exercise of vested Options or the vesting of RSUs and PSUs, that are granted under the Plan. As of December 31, 2021, 1,783 shares have vested and been issued to Plan participants, 33,057 shares have been granted but remain unvested and 1,960 dividend equivalent units “DEUs” have accrued and remain unvested. As of December 31, 2020, 1,023 shares have vested and been issued to Plan participants, 31,110 shares have been granted but remain unvested and 785 DEUs have accrued and remain unvested.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 17—NON-CASH SHARE-BASED COMPENSATION (continued)

Options Awards

The following table summarizes Options award activity for the respective periods presented:

	Number of Options		Weighted Average Grant Date Fair Value per Share
Balance as of December 31, 2019		23,670		$	0.42
Granted		—			—
Exercised		—			—
Forfeited		(650)			0.37
Balance as of December 31, 2020		23,020		$	0.43
Granted		—			—
Exercised		(833)			0.33
Forfeited		(300)			0.59
Balance as of December 31, 2021		21,887		$	0.43

The Company’s Options ratably vest over a three-year period and contain both performance and service metrics. The performance metrics include Adjusted EPS as compared to pre-established benchmarks and a calculation that compares the Company’s TSR to pre-established benchmarks. The number of units that will vest can range between 0% and 100% of the award. The fair value of the Company’s Options was calculated using the Black-Scholes model as of the grant date and is uniformly expensed over the vesting period. No Options were awarded during the years ended December 31, 2021 and 2020.

RSU Awards

The following table summarizes RSU equity award activity for the respective periods presented:

	Number of Shares		Weighted Average Grant Date Fair Value per Share
Balance as of December 31, 2019		1,252		$	1.20
Granted		2,641			1.17
Vested		(470)			1.08
Forfeited		—			—
Balance as of December 31, 2020		3,423		$	1.19
Granted		1,536			1.59
Vested		(760)			1.16
Forfeited		(74)			1.32
Balance as of December 31, 2021		4,125		$	1.34

RSUs cliff- or ratably-vest based on service conditions. The number of units that will vest can range between 0% and 100% of the award. The fair value of the Company’s RSUs is determined using the stock price at the grant date and uniformly expensed over the vesting period.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 17—NON-CASH SHARE-BASED COMPENSATION (continued)

PSU Awards

The following table summarizes PSU equity award activity for the respective periods presented:

	Number of Shares		Weighted Average Grant Date Fair Value per Share
Balance as of December 31, 2019		—		$	—
Granted		4,667			1.19
Vested		—			—
Forfeited		—			—
Balance as of December 31, 2020		4,667		$	1.19
Granted		2,465			1.08
Vested		—			—
Forfeited		(87)			1.15
Balance as of December 31, 2021		7,045		$	1.15

PSUs cliff-vest based on three performance criteria which include a three-year average adjusted return on equity as compared to pre-established benchmarks, a calculation that compares the Company’s TSR to pre-established benchmarks as well as the same calculated return for a group of peer companies as selected by the Company. The number of units that will vest can range between 0 % and 100% of the award.

The fair value of the Company’s PSUs is calculated using a Monte Carlo simulation model as of the grant date and is uniformly expensed over the vesting period. The inputs to the Monte Carlo model included the following for PSUs granted during the respective periods presented:

	December 31, 2021
Risk-free rate of interest		0.2%
Volatility(a)		35%
Correlation with comparator group range		0.02–0.36

(a)

Volatility utilizes the historical volatility for the Company’s share price.

Share-Based Compensation Expense

The following table presents share-based compensation expense for the respective periods presented:

	December 31, 2021			December 31, 2020
Options		$	2,115		$	2,553
RSUs			2,346			1,367
PSUs			2,939			1,116
Total share-based compensation expense		$	7,400		$	5,036

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 18—DIVIDENDS

The following table summarizes the Company’s dividends declared and paid on the dates indicated:

	Dividend per Share						Record Date	Pay Date	Shares Outstanding	Gross Dividends Paid
Date Dividends Declared/Paid	USD			GBP			Record Date	Pay Date	Shares Outstanding	Gross Dividends Paid
Declared on 29 October 2020		$	0.0400		£	0.0285	March 5, 2021	March 26, 2021	707,525		$	28,301
Declared on 8 March 2021		$	0.0400		£	0.0281	May 28, 2021	June 24, 2021	849,434			33,970
Declared on 30 April 2021		$	0.0400		£	0.0288	September 3, 2021	September 24, 2021	849,603			33,984
Declared on 5 August 2021		$	0.0400		£	0.0299	November 26, 2021	December 17, 2021	849,603			33,984
Paid in the year ended December 31, 2021											$	130,239
Declared on 10 December 2019		$	0.0350		£	0.0276	March 6, 2020	March 27, 2020	642,805		$	22,498
Declared on 9 March 2020		$	0.0350		£	0.0274	May 29, 2020	June 26, 2020	707,086			24,748
Declared on 4 May 2020		$	0.0350		£	0.0269	September 4, 2020	September 25, 2020	707,274		$	24,755
Declared on 10 August 2020		$	0.0375		£	0.0278	November 27, 2020	December 18, 2020	707,377			26,526
Paid in the year ended December 31, 2020											$	98,527

On October 28, 2021 the Company proposed a dividend of $0.0425 per share. The dividend will be paid on March 28, 2022 to shareholders on the register on March 4, 2022. This dividend was not approved by shareholders, thereby qualifying it as an “interim” dividend. No liability was recorded in the Consolidated Financial Statements in respect of this interim dividend as at December 31, 2021.

Subsequent Events

On March 22, 2022 the Directors recommended a dividend of $0.0425 per share. The dividend will be paid on June 30, 2022 to shareholders on the register on May 27, 2022, subject to shareholder approval at the AGM. Provided this dividend was not approved by shareholders as of the reporting date, this represents an “interim” dividend. No liability has been recorded in the Consolidated Financial Statements in respect of this dividend as at December 31, 2021.

The following table summarizes the Company’s dividends paid subsequent to December 31, 2021:

Dividend per Share

Record Date

Pay Date

Shares
Outstanding

Gross
Dividends
Paid

Date Dividends Declared/Paid

USD

GBP

Declared on October 28, 2021

0.0425

0.0325

March 4,2022

March 28,2022

850,047

36,127

On May 16, 2022, the Directors recommended a dividend of $0.0425 per share. the dividend will be paid on September 26, 2022 to shareholders on the register on September 2, 2022. This dividend was not approved by shareholders, thereby qualifying it as an “interim” dividend. No liability was recorded in the Consolidated Financial Statements in respect of this interim dividend as of December 31, 2021.

NOTE 19—ASSET RETIREMENT OBLIGATIONS

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 19—ASSET RETIREMENT OBLIGATIONS (continued)

future cost of decommissioning its production facilities and pipelines if required by contract, statute, or constructive obligation. The decommissioning liability represents the present value of estimated future decommissioning costs. No such contractual agreements or statutes were in place for the Company for the years ended December 31, 2021 and 2020.

In estimating the present value of future decommissioning costs of natural gas and oil properties the Company takes into account the number and state jurisdictions of wells, current costs to decommission by state and the average well life across its portfolio. The Directors’ assumptions are based on the current economic environment and represent what the Directors believe is a reasonable basis upon which to estimate the future liability. However, actual decommissioning costs will ultimately depend upon future market prices at the time the decommissioning services are performed. Furthermore, the timing of decommissioning will vary depending on when the fields cease to produce economically, making the determination dependent upon future natural gas and oil prices, which are inherently uncertain.

The Company applies a contingency allowance for annual inflationary cost increases to its current cost expectations then discounts the resulting cash flows using a credit adjusted risk free discount rate. The inflationary adjustment is a US long-term 10-year rate sourced from consensus economics. When determining the discount rate of the liability, the Company evaluates the Bloomberg 15-year US Energy BB bond which economically aligns with the underlying long-term and unsecured liability. Based on this evaluation the net discount rate used in the calculation of the decommissioning liability in 2021 and 2020 was 2.9% and 3.7%, respectively.

The composition of the provision for asset retirement obligations at the reporting date was as follows for the periods presented:

	Year Ended
	December 31, 2021			December 31, 2020
Balance at beginning of period		$	346,124		$	199,521
Additions(a)			96,292			26,995
Accretion			24,396			15,424
Plugging costs			(2,879)			(2,442)
Disposals(a)			(16,500)			(3,838)
Revisions to estimate(b)(c)			78,156			110,464
Balance at end of period		$	525,589		$	346,124
Less: Current asset retirement obligations			3,399			1,882
Non-current asset retirement obligations		$	522,190		$	344,242

(a)

Refer to Note 5 for additional information regarding acquisitions and divestitures.

(b)

At December 31, 2021, the Company performed normal revisions to its asset retirement obligations, which resulted in a $78,156 increase in the liability. This increase was comprised of a $109,306 increase attributable to the lower discount rate which was then offset by a $27,038 reduction in anticipated ARO cost. The remaining change was attributable to timing. The lower discount rate was a result of macroeconomic factors spurred by the COVID-19 recovery, which reduced bond yields and increased inflation. Cost reductions are a result of the expansion of the Company’s internal plugging program and efficiencies gained.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 19—ASSET RETIREMENT OBLIGATIONS (continued)

(c)

At December 31, 2020, the Company performed normal revisions to its asset retirement obligations which resulted in a $110,464 adjustment, of which $102,686 relates to macroeconomic factors stemming largely from the COVID-19 pandemic that reduced bond yields and resulted in a lower discount rate applied to our asset retirement obligations liability. The remaining $7,778 relates to pricing-related adjustments based on historical costs incurred to retire wells.

Changes to assumptions for the estimation of the Company’s asset retirement obligations could result in a material change in the carrying value of the liability. A reasonably possible 10% change in assumptions could have the following impact on the Company’s asset retirement obligations as at December 31, 2021.

ARO Sensitivity	+10%			-10%
Discount rate		$	(49,218)		$	55,843
Timing			(40,378)			43,751
Cost			52,547			(52,547)

NOTE 20—LEASES

The Company leased automobiles, equipment and real estate for the periods presented below. A reconciliation of leases arising from financing activities and the balance sheet classification of future minimum lease payments as of the reporting periods presented were as follows:

	Present Value of Minimum Lease Payments
	December 31, 2021			December 31, 2020
Balance at beginning of period		$	18,878		$	1,813
Additions(a)			16,482			19,820
Interest expense(b)			1,050			929
Cash outflows			(8,606)			(3,684)
Balance at end of period		$	27,804		$	18,878
Classified as:
Current liability		$	9,627		$	5,013
Non–current liability			18,177			13,865
Total		$	27,804		$	18,878

(a)

Of the $16,482 in lease additions in 2021, $6,445, $917 and $700 was attributable to the Indigo, Blackbeard and Tapstone acquisitions. Of the $19,820 in lease additions in 2020, $3,500 was attributable to the Carbon acquisition. The remainder is a result of fleet expansion and the Company transitioning owned vehicles to a fleet management lease program. Refer to Note 5 for additional information regarding acquisitions.

(b)

Included as a component of finance cost.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 20—LEASES (continued)

Set out below is the movement in the right-of-use assets:

	Right-of-Use Assets
	December 31, 2021			December 31, 2020
Balance at beginning of period		$	18,026		$	1,868
Additions(a)			16,554			19,558
Depreciation			(7,672)			(3,400)
Balance at end of period		$	26,908		$	18,026
Classified as:
Motor vehicles		$	19,149		$	14,614
Midstream			6,502			2,496
Buildings and leasehold improvements			1,257			916
Total		$	26,908		$	18,026

(a)

Of the $16,554 in lease additions in 2021, $6,445, $917 and $700 was attributable to the Indigo, Blackbeard and Tapstone acquisitions. Of the $19,558 in lease additions in 2020, $3,500 was attributable to the Carbon acquisition. The remainder is a result of fleet expansion and the Company transitioning owned vehicles to a fleet management lease program. Refer to Note 5 for additional information regarding acquisitions.

The range of discount rates applied in calculating right-of-use assets and related lease liabilities, depending on the lease term, is presented below:

			December 31, 2021			December 31, 2020
Discount rates range			1.8%−3.3%			1.8%−3.3%

Expenses related to short-term and low-value lease exemptions applied under IFRS 16 are primarily associated with compressor rentals and were $15,362 and $9,799 for the years ended December 31, 2021 and 2020 respectively. These amounts have been included in the Company’s operating expenses and are primarily concentrated in LOE.

The following table reflects the maturity of leases as of the periods presented:

	December 31, 2021			December 31, 2020
Not Later Than One Year		$	9,627		$	5,013
Later Than One Year and Not Later Than Five Years			18,177			13,865
Later Than Five Years			—			—
Total		$	27,804		$	18,878

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 21—BORROWINGS

The Company’s borrowings consist of the following amounts as of the reporting date as follows:

	December 31, 2021			December 31, 2020
Credit Facility (Weighted average interest rate of 3.36% and 2.96%, respectively)		$	570,600		$	213,400
ABS I Note (Interest rate of 5.00%)			155,266			180,426
ABS II Note (Interest rate of 5.25%)			169,320			191,125
Term Loan I (Interest rate of 6.50%)			137,099			156,805
Miscellaneous, primarily for real estate, vehicles and equipment			9,380			4,730
Total borrowings		$	1,041,665		$	746,486
Less: Current portion of long-term debt			(58,820)			(64,959)
Less: Deferred financing costs			(26,413)			(23,068)
Less: Original issue discounts			(4,897)			(6,178)
Total non-current borrowings, net		$	951,535		$	652,281

Credit Facility

The Company maintains a revolving loan facility with a lending syndicate, the borrowing base for which is redetermined on a semi-annual, or as needed, basis. The borrowing base is primarily a function of the value of the natural gas and oil properties that collateralize the lending arrangement and will fluctuate with changes in collateral, which may occur as a result of acquisitions or through the establishment of ABS, Term Loan or other lending structures that result in changes to the collateral base.

In August 2021, the Credit Facility borrowing base was upsized from $425,000 to $625,000 for the Indigo, Blackbeard and Tanos acquisitions and the maturity of the Credit Facility was extended by two years to August 2025. In December 2021, the borrowing base under the Credit Facility was further increased from $625,000 to $825,000 as part of the Company’s semi-annual borrowing base redetermination and in connection with the Tapstone acquisition.

The Credit Facility has an interest rate of LIBOR plus an additional spread that ranges from 2.75% to 3.75% based on utilization. Interest payments on the Credit Facility are paid on a monthly basis. The next redetermination is in May 2022. Available borrowings under the Credit Facility were $222,263 as of 31 December 2021 which considers the impact of $32,137 in letters of credit issued to certain vendors.

The Credit Facility contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records; financial reporting and notification; compliance with laws; maintenance of properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, restricted payments and hedging. It also requires the Company to maintain a ratio of total debt to EBITDAX of not more than 3.25 to 1.00 and a ratio of current assets (with certain adjustments) to current liabilities of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. As of December 31, 2021 the Company was in compliance with all financial covenants. The fair value of the Credit Facility approximates the carrying value as at December 31, 2021.

Term Loan I

In May 2020, the Company acquired DP Bluegrass LLC (“Bluegrass”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to enter into a securitized financing agreement for $160,000, which was structured as a secured term loan. The Company issued the Term Loan I at a 1% discount, and used the proceeds of $158,400 to fund the Carbon and EQT acquisitions, discussed in Note 5.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 21—BORROWINGS (continued)

The Term Loan I is secured by certain producing assets acquired from Carbon and EQT, discussed in Note 5.

The Term Loan I accrues interest at a stated 6.50% annual rate and has a maturity date of May 2030. Interest and principal payments on the Term Loan I are payable on a monthly basis beginning May 2020 and November 2020, respectively. During the years ended December 31, 2021 and 2020, the Company incurred $9,860 and $6,371 in interest related to the Term Loan I, respectively, which is recognized under the effective interest rate method. The fair value of the Term Loan I approximates the carrying value as at December 31, 2021.

The Term Loan I is subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the Term Loan I, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified premium payments in the case of an optional prepayment, (iii) certain indemnification payments in the event, among other things, that the assets pledged as collateral for the Term Loan I are used in stated ways defective or ineffective, and (iv) covenants related to recordkeeping, access to information and similar matters.

The Term Loan I is also subject to customary accelerated amortization events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, certain change of control and management termination events, and event of default and the failure to repay or refinance the Term Loan I on the applicable scheduled maturity date.

The Term Loan I is subject to certain customary events of default, including events relating to non-payment of required interest, principal or other amounts due on or with respect to the Term Loan I, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.

As of December 31, 2021 the Company was in compliance with all financial covenants.

ABS II Note

In April 2020, the Company formed Diversified ABS Phase II LLC (“ABS II”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to enter into a securitized financing agreement for $200,000. The ABS II Note is BBB rated and was issued at a 2.775% discount. The Company used the proceeds of $183,617, net of discount, capital reserve requirement, and debt issuance costs, to pay down its Credit Facility.

The ABS II Note is secured by certain of the Company’s upstream producing Appalachian assets. Natural gas production associated with these assets was hedged at 85% at the close of the agreement with long-term derivative contracts.

The ABS II Note accrues interest at a stated 5.25% rate per annum and has a maturity date of July 2037. Interest and principal payments on the ABS II Note are payable on a monthly basis beginning July 2020 and August 2020, respectively. During the years ended December 31, 2021 and 2020, the Company incurred $10,530 and $7,563 in interest related to the ABS II Note, respectively, which is recognized under the effective interest rate method. In the event that ABS II has cash flow in excess of the required payments, 25% to 100% of the excess cash, contingent on certain performance metrics, ABS II is required to pay down additional principal with the remaining proceeds remaining with the Company. The fair value of the ABS II Note approximates the carrying value as at December 31, 2021.

The ABS II Note is subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the ABS II Note, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified premium payments in the case of an optional prepayment, (iii) certain indemnification payments in the event, among other things, that the assets

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 21—BORROWINGS (continued)

pledged as collateral for the ABS II Note are used in stated ways defective or ineffective, and (iv) covenants related to recordkeeping, access to information and similar matters.

The ABS II Note is also subject to customary early amortization events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, failure to maintain certain production metrics, certain change of control and management termination events, and event of default and the failure to repay or refinance the ABS II Note on the applicable scheduled maturity date.

The ABS II Note is subject to certain customary events of default, including events relating to non-payment of required interest, principal or other amounts due on or with respect to the ABS II Note, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.

As of December 31, 2021 the Company was in compliance with all financial covenants.

ABS I Note

In November 2019, the Company formed Diversified ABS LLC (“ABS I”), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary, to enter into a securitized financing agreement for $200,000 which was issued at par through a BBB- rated bond.

The ABS I Note is secured by certain of the Company’s upstream producing Appalachian assets. Natural gas production associated with these assets was hedged at 85% at the close of the agreement with long-term derivative contracts.

Interest and principal payments on the ABS I Note are payable on a monthly basis. During the years ended December 31, 2021 and 2020, the Company incurred $8,460 and $9,661 of interest related to the ABS I Note, respectively. The legal final maturity date is January 2037 with an amortizing maturity of December 2029. The ABS I Note accrues interest at a stated 5% rate per annum. In the event that ABS I has cash flow in excess of the required payments, 25% to 100% of the excess cash, contingent on certain performance metrics, ABS I is required to pay down additional principal with the remaining proceeds remaining with the Company. The fair value of the ABS I Note approximates the carrying value as at December 31, 2021.

The ABS I Note is subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the ABS I Note, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified make-whole payments in the case of the ABS I Note under certain circumstances, (iii) certain indemnification payments in the event, among other things, that the assets pledged as collateral for the ABS I Note are used in stated ways defective or ineffective, and (iv) covenants related to recordkeeping, access to information and similar matters.

The ABS I Note is also subject to customary rapid amortization events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, failure to maintain certain production metrics, certain change of control and management termination events, and event of default and the failure to repay or refinance the ABS I Note on the applicable scheduled maturity date.

The ABS I Note is subject to certain customary events of default, including events relating to non-payment of required interest, principal or other amounts due on or with respect to the ABS I Note, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.

As of December 31, 2021 the Company was in compliance with all financial covenants.

The following table provides a reconciliation of the Company’s future maturities of its total borrowings as of the reporting date as follows:

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 21—BORROWINGS (continued)

	December 31, 2021			December 31, 2020
Not later than one year		$	58,820		$	64,959
Later than one year and not later than five years			811,964			450,503
Later than five years			170,881			231,024
Total borrowings		$	1,041,665		$	746,486

The following table represents the Company’s finance costs for each of the periods presented:

	Year Ended
	December 31, 2021			December 31, 2020
Interest expense, net of capitalized and income amounts(a)		$	42,370		$	34,391
Amortization of discount and deferred finance costs			8,191			8,334
Other			67			602
Total finance costs		$	50,628		$	43,327

(a)

Includes payments related to borrowings and leases.

Reconciliation of borrowings arising from financing activities:

	Year Ended
	December 31, 2021			December 31, 2020
Balance at beginning of period		$	717,240		$	622,288
Acquired as part of a business combination			3,801			—
Proceeds from borrowings			1,727,745			799,650
Repayments of borrowings			(1,436,367)			(705,314)
Costs incurred to secure financing			(10,255)			(7,799)
Amortization of discount and deferred financing costs			8,191			8,334
Cash paid for interest			(41,623)			(34,335)
Finance costs and other			41,623			34,416
Balance at end of period		$	1,010,355		$	717,240

Subsequent Events

In February 2022, the Company completed two asset-backed security financings, the ABS III Note and the ABS IV Note, to raise gross proceeds of $365,000 and $160,000, respectively. As a result, the borrowing base under the Credit Facility was redetermined to $500,000 in February 2022 to account for movement of asset collateral value securitized by the ABS III and ABS IV Notes.

ABS III Note

In February 2022, the Company formed Diversified ABS III LLC (“ABS III”), a limited-purpose, bankruptcy-remote, wholly-owned, to enter into a securitized financing agreement for $365,000 which was issued at par through a BBB rated bond.

The ABS III Note is secured by certain of the Company’s upstream producing, as well as certain midstream, Appalachian assets.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 21—BORROWINGS (continued)

Interest and principal payments on the ABS III Note are payable on a monthly basis. The legal final maturity date is April 2039 with an amortizing maturity of November 2030. The ABS III Note accrues interest at a stated 4.875% rate per annum. In the event that ABS III has cash flow in excess of the required payments, 25% to 100% of the excess cash, contingent on certain performance metrics, the Company is required to pay down additional principal with the remaining proceeds remaining with the Company.

ABS IV Note

In February 2022, the Company formed Diversified ABS IV LLC (“ABS IV”), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary, to enter into a securitized financing agreement for $160,000 which was issued at par through a BBB rated bond.

The ABS IV Note is secured by a portion of the upstream producing Blackbeard acquisition assets.

Interest and principal payments on the ABS IV Note are payable on a monthly basis. The legal final maturity date is February 2037 with an amortizing maturity of September 2030. The ABS IV Note accrues interest at a stated 4.950% rate per annum. In the event that ABS IV has cash flow in excess of the required payments, 25% to 100% of the excess cash, contingent on certain performance metrics, the Company is required to pay down additional principal with the remaining proceeds remaining with the Company.

ABS V Note

In May 2022, the Company formed Diversified ABS V LLC (“ABS V”), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary, to enter into a securitized financing agreement for $445,000 which was issued at par through a BBB rated bond.

The ABS V Note is secured by the majority of the Company’s remaining upstream assets in Appalachia that were not securitized by previous ABS transactions.

Interest and principal payments on the ABS V Note are payable on a monthly basis. The legal final maturity date is May 2039 with an amortizing maturity of December 2030 The ABS V Note accrues interest at a stated 5.78% rate per annum. Based on whether certain performance metrics are achieved, the Company could be required to apply 50% to 100% of ABS excess cash to pay down additional principal.

NOTE 22—TRADE AND OTHER PAYABLES

The following table includes details of trade and other payables. The fair value approximates the carrying value as at the periods presented:

	December 31, 2021			December 31, 2020
Trade payables		$	61,612		$	19,218
Other payables			806			148
Total trade and other payables		$	62,418		$	19,366

Trade and other payables are unsecured, non-interest bearing and paid as they become due.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 23—OTHER LIABILITIES

The following table includes details of other liabilities as of the periods presented:

	December 31, 2021			December 31, 2020
Other non-current liabilities
Uncertain tax position(a)		$	—		$	1,837
Other non-current liabilities(b)			7,775			11,023
Total other non-current liabilities		$	7,775		$	12,860
Other current liabilities
Accrued expenses(c)		$	139,648		$	28,582
Taxes payable(d)			53,629			18,025
Net revenue clearing(e)			137,366			12,561
Asset retirement obligations–current			3,399			1,882
Revenue to be distributed(f)			57,006			30,260
Total other current liabilities		$	391,048		$	91,310

(a)

At the date of acquisition, the Directors determined that Alliance Petroleum had taken uncertain tax positions, and as a result, an indemnification agreement was executed. The Company recorded an uncertain tax position liability and indemnification receivable for the amount of $1,837 as of December 31, 2020. During 2021 the statute of limitations associated with the uncertain tax position was met and the Company is no longer subject to potential tax liability associated with the tax position. As a result, the provision for the uncertain tax position and the indemnification receivable were removed.

(b)

Other non-current liabilities primarily represents the long-term portion of the value associated with the upfront promote received from Oaktree. The upfront promote allows DEC to obtain a 51.25% interest in the net assets associated with the acquisition while only paying 50% of the total consideration. The upfront promote is intended to compensate DEC for the administrative expansion necessary with acquired growth and is amortized to general and administrative expense over the life of the promote.

(c)

Accrued expenses primarily consist of the $22,503 for the Carbon and EQT contingent consideration and $44,085 for hedge settlements payables. The remaining balance consists of accrued capital projects and operating expenses which have naturally increased with our growth.

(d)

The increase in taxes payable year-over-year is primarily attributable to a $33,526 capital gain payable on the Tapstone acquisition resulting from this transaction being treated as a stock deal for tax purposes. The Company received a purchase price concession from Oaktree as a result of this tax treatment to share the payable between the parties. Remaining taxes payable are attributable to the Company’s customary operations.

(e)

Net revenue clearing is estimated revenue that is payable to third-party working interest owners. The year over year increase, similar to commodity receivables, is a result of higher commodity prices year over year, our growth from acquisitions and Oaktree’s 48.75% participation in the acquisitions of Indigo, Tanos and Tapstone.

(f)

Revenue to be distributed is revenue that is payable to third-party working interest owners, but has yet to be paid due to title, legal, ownership or other issues. The Company releases the underlying liability as the aforementioned issues become resolved. As the timing of resolution is unknown, the Company records the balance as a current liability. Revenue to be distributed increased $14,429 year-over-year as a result of the Central Region acquisitions while the remaining change is attributable to recurring operating activity and increases in commodity prices.

NOTE 24—FAIR VALUE AND FINANCIAL INSTRUMENTS

FAIR VALUE

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 24—FAIR VALUE AND FINANCIAL INSTRUMENTS (continued)

Measurement (“IFRS 13”) establishes a fair value hierarchy for valuation inputs that gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The fair value hierarchy is defined as follows:

	Level 1:			Inputs are unadjusted, quoted prices in active markets for identical assets at the measurement date.
	Level 2:			Inputs (other than quoted prices included in Level 1 can include the following):
				(1) Observable prices in active markets for similar assets;
				(2) Prices for identical assets in markets that are not active;
				(3) Directly observable market inputs for substantially the full term of the asset; and
				(4) Market inputs that are not directly observable but are derived from or corroborated by observable market data.
	Level 3:			Unobservable inputs which reflect the Directors’ best estimates of what market participants would use in pricing the asset at the measurement date.

Financial Instruments

Working Capital

The carrying values of cash and cash equivalents, trade receivables, other current assets, accounts payable and other current liabilities in the Consolidated Statement of Financial Position approximate fair value because of their short-term nature. For trade receivables, the Company applies the simplified approach permitted by IFRS 9, Financial Instruments (“IFRS 9”), which requires expected lifetime losses to be recognized from initial recognition of the receivables. Financial liabilities are initially measured at fair value and subsequently measured at amortized cost.

For borrowings, derivative financial instruments, and leases the following methods and assumptions were used to estimate fair value:

Borrowings

The fair values of the Company’s ABS I Note, ABS II Note and Term Loan I are considered to be a Level 2 measurement on the fair value hierarchy. The carrying values of the borrowings under the Company’s Credit Facility (to the extent utilized) approximates fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its Credit Facility to be a Level 2 measurement on the fair value hierarchy.

Leases

Derivative Financial Instruments

The Company measures the fair value of its derivative financial instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates such as the U.S. Treasury yields, the LIBOR curve, and volatility factors.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 24—FAIR VALUE AND FINANCIAL INSTRUMENTS (continued)

oil derivatives and OPIS for NGLs derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2021 are based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

The Company’s call options, put options, collars and swaptions (Level 2) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX and OPIS futures index, interest rates, volatility and credit worthiness. Inputs to the Black-Scholes model, including the volatility input are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis. A change in volatility would result in a change in fair value measurement, respectively.

The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves.

Contingent consideration

These liabilities represent the estimated fair value of potential future payments the Company may be required to remit under the terms of historical purchase agreements entered into for asset acquisitions and business combinations. In instances when the contingent consideration relates to the acquisition of a group of assets, the Company records changes in the fair value of the contingent consideration through the basis of the asset acquired rather than through Other income (expense) in the Consolidated Statement of Comprehensive Income as it does for business combinations. During the years ended December 31, 2021 and 2020 the Company recorded $9,482 and $2,402, respectively, in revaluations related to contingent consideration associated with asset acquisitions and $8,963 and $567, respectively, associated with business combinations.

The Company remeasures the fair value of the contingent consideration at each reporting period. This estimate requires assumptions to be made, including forecasting the NYMEX Henry Hub natural gas settlement prices relative to stated floor and target prices in future periods. In determining the fair value of the contingent consideration liability, the Company used the Monte Carlo simulation model, which considers unobservable input variables, representing a Level 3 measurement. While valued under this technique presently these items are classified as current and approximate the maximum payment under the terms of the consideration agreements.

There were no transfers between fair value levels for the year ended December 31, 2021.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 24—FAIR VALUE AND FINANCIAL INSTRUMENTS (continued)

FINANCIAL INSTRUMENTS

The following table includes the Company’s financial instruments as at the periods presented:

	December 31, 2021			December 31, 2020
Cash and cash equivalents		$	12,558		$	1,379
Trade receivables and accrued income			282,922			66,991
Other non-current assets(a)			3,635			2,376
Other current assets(b)			25,004			—
Other non-current liabilities(c)			(7,775)			(11,023)
Other current liabilities(d)			(334,020)			(71,403)
Derivative financial instruments at fair value			(807,398)			(165,807)
Leases			(27,804)			(18,878)
Borrowings			(1,041,665)			(746,486)
Total		$	(1,894,543)		$	(942,851)

(a)

Excludes indemnification receivables.

(b)

Excludes prepaid expenses, deposits and inventory

(c)

Excludes uncertain tax positions.

(d)

Excludes taxes payable and asset retirement obligations.

NOTE 25—FINANCIAL RISK MANAGEMENT

The Company is exposed to a variety of financial risks such as market risk, credit risk, liquidity risk, capital risk and collateral risk. The Company manages these risks by monitoring the unpredictability of financial markets and seeking to minimize potential adverse effects on the Company’s financial performance on a continuous basis.

The Company’s principal financial liabilities are comprised of borrowings, leases and trade and other payables, used primarily to finance and financially guarantee its operations. The Company’s principal financial assets include cash and cash equivalents and trade and other receivables derived from its operations.

The Company also enters into derivative financial instruments which, depending on market dynamics, are recorded as assets or liabilities. To assist with the design and composition of its hedging program, the Company engages a specialist firm with the appropriate skills and experience to manage its risk management derivative-related activities.

MARKET RISK

Interest Rate Risk

The Company is subject to market risk exposure related to changes in interest rates on its variable-rate Credit Facility. The remainder of the Company’s financing is fixed-rate. As of December 31, 2021 and 2020,

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 25—FINANCIAL RISK MANAGEMENT (continued)

the Company had $570,600 and $436,700, respectively, outstanding under its Credit Facility that maintained an average interest rate of 3.36% and 2.96%, respectively. Refer to Note 21 for additional information regarding the Credit Facility.

The table below represents the impact a 100 basis point adjustment in the interest rate for the Credit Facility and the corresponding impact on finance costs. This represents a reasonably possible change in interest rate risk.

Credit Facility Interest Rate Sensitivity			+100 Basis Points						-100 Basis Points
Finance costs				$	5,706					$	(5,706)

The Company principally manages this risk by entering into fixed-rate borrowing obligations with amortizing structures. To mitigate residual interest rate risk the Company enters into derivative financial instruments. The total principal hedged through the use of derivative financial instruments varies from period to period. See Note 13 for more information on the Company’s derivative financial instruments.

As of December 31, 2021 and 2020, the Company had an interest rate swap (“IR swap”) that fixed $150,000 of variable LIBOR interest rate risk, respectively. Refer to Note 13 for additional information regarding derivative financial instruments.

The Company has also evaluated the potential risks associated with the anticipated transition from LIBOR to SOFR and does not anticipate the impact will be material.

Commodity Price Risk

The Company’s revenues are primarily derived from the sale of its natural gas, NGLs and oil production, and as such, the Company is subject to commodity price risk. Commodity prices for natural gas, NGLs and oil can be volatile and can experience fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. For the years ended December 31, 2021 and 2020, the Company’s commodity revenue was $973,107 and $381,662, respectively.

The Company enters into derivative financial instruments to mitigate the risk of fluctuations in commodity prices. The total volumes hedged through the use of derivative financial instruments varies from period to period, but generally the Company’s objective is to hedge at least 65% for the next 12 months, at least 50% in months 13 to 24, and a minimum of 30% to 40% in months 25 to 36, of its anticipated production volumes for the next 36 months. Refer to Note 13 for additional information regarding derivative financial instruments.

CREDIT AND COUNTERPARTY RISK

The Company is exposed to credit and counterparty risk from the sale of its natural gas, NGLs and oil. Trade receivables from customers are amounts due for the purchase of natural gas, NGLs and oil. Collectability is dependent on the financial condition of each customer. The Company reviews the financial condition of customers prior to extending credit and generally does not require collateral in support of their trade receivables. The Company had one customer over 10% as of December 31, 2021 and 2020, that made up 13% and 11%, respectively, of the Company’s total trade receivables from customers. As of December 31, 2021 and 2020, the Company’s trade receivables from customers were $268,375 and $66,908, respectively.

The Company is also exposed to credit risk from joint interest owners, entities that own a working interest in the properties operated by the Company. Joint interest receivables are classified in trade receivables, net in the Consolidated Statement of Financial Position. The Company has the ability to withhold future revenue payments to recover any non-payment of joint interest receivables. Given the historically low pricing environment in 2020, however, the Company recorded a non-recurring increase in the reserve of

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 25—FINANCIAL RISK MANAGEMENT (continued)

joint interest owner receivables for the allowance for credit losses of $6,931 as of December 31, 2020. During 2021 commodity markets improved and with them so did the Company’s ability to withhold receivables from revenue distributions. As a result the Company’s allowance for credit losses from joint interest decreased by 45%. As of December 31, 2021 and 2020, the Company’s joint interest receivables were $14,547 and $83, respectively.

The majority of trade receivables are current and the Company believes these receivables are collectible.

LIQUIDITY RISK

Liquidity risk is the possibility that the Company will not be able to meet its financial obligations as they are due. The Company manages this risk by maintaining adequate cash reserves through the use of cash from operations and borrowing capacity on the Credit Facility. The Company also continuously monitors its forecast and actual cash flows to ensure it maintains an appropriate amount of liquidity. The amounts disclosed in the table are the contractual undiscounted cash flows. Balances due within 12 months equal their carrying balances, because the impact of discounting is not significant.

	Not Later Than One Year			Later Than One Year and Not Later Than Five Years			Later Than Five Years			Total
For the year ended December 31, 2021
Trade and other payables		$	62,418		$	—		$	—		$	62,418
Borrowings			58,820			811,964			170,881			1,041,665
Leases			9,627			18,177			—			27,804
Other liabilities(a)			277,014			7,775			—			284,789
Total		$	407,879		$	837,916		$	170,881		$	1,416,676
For the year ended December 31, 2020
Trade and other payables		$	19,366		$	—		$	—		$	19,366
Borrowings			64,959			450,503			231,024			746,486
Leases			5,013			13,865			—			18,878
Other liabilities(a)			41,143			11,023			—			52,166
Total		$	130,481		$	475,391		$	231,024		$	836,896

(a)

Excludes uncertain tax position, taxes payable, asset retirement obligations and revenue to be distributed.

CAPITAL RISK

The Company defines capital as the total of equity shareholders’ funds and long-term borrowings net of available cash balances. The Company’s objectives when managing capital are to provide returns for shareholders and safeguard the ability to continue as a going concern while pursuing opportunities for growth through identifying and evaluating potential acquisitions and constructing new infrastructure on existing proved leaseholds. The Directors do not establish a quantitative return on capital criteria, but rather promote year-over-year Adjusted EBITDA growth. The Company uses its Net Debt-to-Adjusted EBITDA to monitor capital risk and maintain a target of below 2.5x.

COLLATERAL RISK

The Company has pledged 30% of its natural gas and oil properties, in Appalachia to fulfill the collateral requirements for borrowings under the ABS I Note, ABS II Note, and Term Loan I transactions. The

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 25—FINANCIAL RISK MANAGEMENT (continued)

remaining natural gas and oil properties collateralize the Company’s Credit Facility. The fair value of the borrowings collateral is based on a third-party engineering reserve calculation using a 10% cumulative discount cash flow and a commodities futures price schedule. Refer to Notes 5 and 21 for additional information regarding acquisitions and borrowings, respectively.

NOTE 26—CONTINGENCIES

Litigation And Regulatory Proceedings

The Company is involved in various pending legal proceedings that have arisen in the ordinary course of business. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of December 31, 2021, the Company did not have any material amounts accrued related to litigation or regulatory matters. For any matters not accrued, it is not possible to estimate the amount of any additional loss, or range of loss that is reasonably possible, but, based on the nature of the claims, management believes that current litigation, claims and proceedings are not, individually or in aggregate, after considering insurance coverage and indemnification, likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows.

The Company has no other contingent liabilities that would have a material impact on its financial position, results of operations or cash flows.

Environmental Matters

The Company’s operations are subject to environmental regulation in all the jurisdictions in which it operates and it was in compliance as of December 31, 2021. The Company is unable to predict the effect of additional environmental laws and regulations which may be adopted in the future, including whether any such laws or regulations would adversely affect its operations. The Company can offer no assurance regarding the significance or cost of compliance associated with any such new environmental legislation once implemented.

NOTE 27—RELATED PARTY TRANSACTIONS

UK Legal Counsel

Martin K. Thomas is a partner at Wedlake Bell LLP, the former UK legal advisor to the Company.

	Year Ended
	December 31, 2021					December 31, 2020
Fees paid to related party legal advisor		$	—	£	—		$	41	£	33

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 28—SUBSEQUENT EVENTS

The Company determined the need to disclose the following material transactions that occurred subsequent to December 31, 2021, which have been described within each relevant footnote as follows:

Description			Footnote
Acquisitions and Divestitures			Note 5
Expenses by Nature			Note 7
Derivative Financial Instruments			Note 13
Other Assets			Note 15
Dividends			Note 18
Borrowings			Note 21

NOTE 29—SUPPLEMENTAL NATURAL GAS AND OIL INFORMATION (UNAUDITED)

Estimated Reserves

The process of estimating quantities of “proved” and “proved developed” reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

For each year in the table below, the estimated proved reserves 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. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. Reserve estimates are inherently imprecise, and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, historical prices of natural gas and oil, and analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 29—SUPPLEMENTAL NATURAL GAS AND OIL INFORMATION (UNAUDITED) (continued)

The following table summarizes the changes in the Company’s net proved reserves for the periods presented, all of which were located in the US:

	Natural Gas		NGLs		Oil		Total
	(MMcf)		(MBbls)		(MBbls)		(MBoe)
December 31, 2019		2,786,622		66,944		4,598		535,979
Revisions of previous estimates(a)		(370,257)		(3,813)		(388)		(65,911)
Extensions, discoveries and other additions		—		—		—		—
Production		(199,667)		(2,843)		(417)		(36,538)
Purchase of reserves in place(b)		646,311		—		1,062		108,781
Sales of reserves in place(c)		(2,217)		(82)		(95)		(547)
December 31, 2020		2,860,792		60,206		4,760		541,765
Revisions of previous estimates(a)		498,927		4,045		3,052		90,251
Extensions, discoveries and other additions		—		—		—		—
Production		(234,643)		(3,558)		(592)		(43,257)
Purchase of reserves in place(b)		1,019,944		32,698		7,397		210,086
Sales of reserves in place(c)		(135,983)		(4,311)		(365)		(27,340)
December 31, 2021		4,009,037		89,080		14,252		771,505

(a)

During 2020, the net downward revision of 65,911 MBoe was primarily related to a lower commodity price environment in 2020 than that of 2019. During 2021 commodity market pricing began to rebound from Covid 19 pandemic lows driving a net upward revision of 90,251 MBoe.

(b)

During 2020, purchases of reserves in place were primarily related to the EQT and Carbon acquisitions. During 2021, purchases of reserves in place were primarily related to the Indigo, Tanos, Blackbeard, and Tapstone acquisitions. Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information about acquisitions.

(c)

During 2020 sales of reserves were primarily attributable to the divestitures of non-core assets while in 2021 sales of reserves in place were primarily related to Oaktree’s subsequent participation in the Indigo acquisition. Refer to Note 5 in the Notes to the Consolidated Financial Statements for additional information about divestitures.

	Natural Gas		NGLs		Oil		Total
	(MMcf)		(MBbls)		(MBbls)		(MBoe)
Total proved reserves as of:
December 31, 2019		2,786,622		66,944		4,598		535,979
December 31, 2020		2,860,792		60,206		4,760		541,765
December 31, 2021		4,009,037		89,080		14,252		771,505
Total proved developed reserves as of:
December 31, 2019		2,786,622		66,944		4,598		535,979
December 31, 2020		2,860,792		60,206		4,760		541,765
December 31, 2021		4,008,160		89,071		13,832		770,921
Proved undeveloped reserves as of:
December 31, 2019		—		—		—		—
December 31, 2020		—		—		—		—
December 31, 2021		877		9		429		584

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 29—SUPPLEMENTAL NATURAL GAS AND OIL INFORMATION (UNAUDITED) (continued)

Capitalized Costs Relating to Natural Gas and Oil Producing Activities

Capitalized costs relating to natural gas and oil producing activities and related accumulated depreciation, depletion and amortization were as follows:

	December 31, 2021			December 31, 2020
Proved properties		$	2,866,353		$	1,968,557
Unproved properties			—			—
Total capitalized costs			2,866,353			1,968,557
Less: Accumulated depreciation, depletion and amortization			(336,275)			(213,472)
Net capitalized costs		$	2,530,078		$	1,755,085

Costs Incurred in Natural Gas and Oil Property Acquisition, Exploration and Development Activities

Costs incurred in natural gas and oil property acquisition, exploration and development activities were as follows:

	December 31, 2021			December 31, 2020
Proved properties		$	718,353		$	201,228
Unproved properties			—			—
Total property acquisition costs			718,353			201,228
Total exploration and development costs			1,464			—
Capitalized interest			—			—
Total costs		$	719,817		$	201,228

Standardized Measure of Discounted Future Net Cash Flows

The following information has been developed based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows (the “Standardized Measure”) be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

•

Future costs and selling prices will differ from those required to be used in these calculations;

•

Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

•

Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net natural gas and oil revenues; and

•

Future net cash flows may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by using the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year. Prices used for the Standardized Measure (adjusted for basis and quality differentials) were as follows:

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 29—SUPPLEMENTAL NATURAL GAS AND OIL INFORMATION (UNAUDITED) (continued)

	December 31, 2021			December 31, 2020
Natural gas (Mcf)		$	3.26		$	1.89
NGLs (Bbls)		$	29.19		$	5.01
Oil (Bbls)		$	62.55		$	34.95

Future cash inflows were reduced by estimated future development and production costs based on year-end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year-end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to natural gas and oil operations. The applicable accounting standards require the use of a 10% discount rate.

Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves and varying price and cost assumptions considered more representative of a range of anticipated economic conditions. The Standardized Measure is as follows:

	December 31, 2021			December 31, 2020
Future cash inflows		$	16,283,927		$	5,885,765
Future production costs			(5,773,240)			(2,981,059)
Future development costs(a)			(1,818,190)			(1,570,606)
Future income tax expense			(1,644,625)			(167,058)
Future net cash flows			7,047,872			1,167,042
10% annual discount for estimated timing of cash flows			(3,714,781)			(161,735)
Standardized Measure		$	3,333,091		$	1,005,307

(a)

Includes $1,615,461 and $1,570,606 in plugging and abandonment costs for the years ended December 31, 2021 and 2020, respectively.

Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.

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Notes to the Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 29—SUPPLEMENTAL NATURAL GAS AND OIL INFORMATION (UNAUDITED) (continued)

Changes in the Standardized Measure were as follows:

	December 31, 2021			December 31, 2020
Standardized Measure, beginning of year		$	1,005,307		$	1,345,964
Sales and transfers of natural gas and oil produced, net of production costs			(742,375)			(230,514)
Net changes in prices and production costs			2,411,163			(576,664)
Extensions, discoveries, and other additions, net of future production and development costs			—			—
Acquisition of reserves in place			980,837			213,210
Divestiture of reserves in place			(145,434)			(2,623)
Revisions of previous quantity estimates			609,100			(215,079)
Net change in income taxes			(622,314)			151,355
Changes in estimated future development costs			(5,612)			138,665
Previously estimated development costs incurred during the year			—			—
Changes in production rates (timing) and other			(266,273)			23,100
Accretion of discount			108,692			157,893
Standardized Measure, end of year		$	3,333,091		$	1,005,307

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INDEX TO THE INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

	Page
Condensed Consolidated Statement of Comprehensive Income for the six months ended June 30, 2022 and 2021		F-71
Condensed Consolidated Statement of Financial Position as of June 30, 2022 and December 31, 2021		F-72
Condensed Consolidated Statement of Changes in Equity for the six months ended June 30, 2022 and 2021		F-73
Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2022 and 2021		F-74
Notes to the Interim Condensed Consolidated Financial Statements		F-76

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Condensed Consolidated Statement of Comprehensive Income
(Unaudited) (Amounts in thousands, except per share and per unit data)

			Six Months Ended
	Notes		June 30, 2022			June 30, 2021
Revenue		5		$	933,528		$	323,316
Operating expense		6			(206,357)			(119,555)
Depreciation, depletion and amortization		6			(118,480)			(71,843)
Gross profit					608,691			131,918
General and administrative expense		6			(114,282)			(42,333)
Allowance for expected credit losses		13			—			(602)
Gain (loss) on natural gas and oil property and equipment		9,10			1,050			234
Gain (loss) on derivative financial instruments		12			(1,673,841)			(394,885)
Gains on bargain purchases		4			1,249			—
Operating profit (loss)					(1,177,133)			(305,668)
Finance costs		19			(39,162)			(22,512)
Accretion of asset retirement obligation		17			(14,003)			(10,216)
Other income (expense)		22			171			(5,582)
Income (loss) before taxation					(1,230,127)			(343,978)
Income tax benefit (expense)		7			294,877			260,021
Net income (loss)					(935,250)			(83,957)
Other comprehensive income (loss)					132			51
Total comprehensive income (loss)				$	(935,118)		$	(83,906)
Net income (loss) attributable to:
Diversified Energy Company PLC				$	(937,412)		$	(83,957)
Non-controlling interest					2,162			—
Net income (loss)				$	(935,250)		$	(83,957)
Earnings (loss) per share–basic and diluted		8		$	(1.10)		$	(0.11)
Weighted average shares outstanding–basic and diluted		8			849,621			736,559

The notes are an integral part of the Interim Condensed Consolidated Financial Statements.

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Condensed Consolidated Statement of Financial Position
(Unaudited) (Amounts in thousands, except per share and per unit data)

	Notes		June 30, 2022			December 31, 2021
ASSETS
Non-current assets:
Natural gas and oil properties, net		9		$	2,428,848		$	2,530,078
Property, plant and equipment, net		10			440,258			413,980
Intangible assets		11			14,746			14,134
Restricted cash					42,972			18,069
Derivative financial instruments		12			3,069			219
Deferred tax asset		7			481,431			176,955
Other non-current assets		14			5,521			3,635
Total non-current assets					3,416,845			3,157,070
Current assets:
Trade receivables, net		13			383,636			282,922
Cash and cash equivalents					187,342			12,558
Restricted cash					1,234			1,033
Derivative financial instruments		12			28,361			1,052
Other current assets		14			15,963			39,574
Total current assets					616,536			337,139
Total assets				$	4,033,381		$	3,494,209
EQUITY AND LIABILITIES
Shareholders’ equity:
Share capital		15		$	11,580		$	11,571
Share premium		15			1,052,959			1,052,959
Share-based payment and other reserves					7,799			14,156
Retained earnings (accumulated deficit)					(1,442,349)			(431,277)
Equity attributable to owners of the parent					(370,011)			647,409
Non-controlling interest					15,927			16,541
Total equity					(354,084)			663,950
Non-current liabilities:
Asset retirement obligations		17			462,165			522,190
Leases		18			18,893			18,177
Borrowings		19			1,067,384			951,535
Derivative financial instruments		12			1,265,018			556,982
Other non-current liabilities		21			8,990			7,775
Total non-current liabilities					2,822,450			2,056,659
Current liabilities:
Trade and other payables		20			36,931			62,418
Leases		18			10,039			9,627
Borrowings		19			263,942			58,820
Derivative financial instruments		12			699,842			251,687
Other current liabilities		21			554,261			391,048
Total current liabilities					1,565,015			773,600
Total liabilities					4,387,465			2,830,259
Total equity and liabilities				$	4,033,381		$	3,494,209

The Interim Condensed Consolidated Financial Statements were approved and authorized for issue by the Board on August 8, 2022 and were signed on its behalf by:

David E. Johnson
Chairman of the Board
August 8, 2022

The notes are an integral part of the Interim Condensed Consolidated Financial Statements.

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Condensed Consolidated Statement of Changes in Equity
(Unaudited) (Amounts in thousands, except per share and per unit data)

	Notes		Share Capital			Share Premium			Share-Based Payment and Other Reserves			Retained Earnings (Accumulated Deficit)			Equity Attributable to Owners of the Parent			Non- Controlling Interest			Total Equity
Balance as of December 31, 2021				$	11,571		$	1,052,959		$	14,156		$	(431,277)		$	647,409		$	16,541		$	663,950
Net income (loss)					—			—			—			(937,412)			(937,412)			2,162			(935,250)
Other comprehensive income (loss)					—			—			—			132			132			—			132
Total comprehensive income (loss)					—			—			—			(937,280)			(937,280)			2,162			(935,118)
Equity compensation					9			—			3,375			(1,517)			1,867			—			1,867
Repurchase of shares by the Employee Benefit Trust		15			—			—			(9,718)			—			(9,718)			—			(9,718)
Dividends		16			—			—			—			(72,275)			(72,275)			—			(72,275)
Distributions to non-controlling interest owners					—			—			—			—			—			(2,776)			(2,776)
Cancellation of warrants		15			—			—			(14)			—			(14)			—			(14)
Transactions with shareholders					9			—			(6,357)			(73,792)			(80,140)			(2,776)			(82,916)
Balance as of June 30, 2022				$	11,580		$	1,052,959		$	7,799		$	(1,442,349)		$	(370,011)		$	15,927		$	(354,084)

	Notes		Share Capital			Share Premium			Share-Based Payment and Other Reserves			Retained Earnings (Accumulated Deficit)			Equity Attributable to Owners of the Parent			Non- Controlling Interest			Total Equity
Balance as of December 31, 2020				$	9,520		$	841,159		$	8,797		$	27,182		$	886,658		$	—		$	886,658
Net income (loss)					—			—			—			(83,957)			(83,957)			—			(83,957)
Other comprehensive income (loss)					—			—			—			51			51			—			51
Total comprehensive income (loss)					—			—			—			(83,906)			(83,906)			—			(83,906)
Issuance of share capital		15			2,044			211,800			—			—			213,844			—			213,844
Equity compensation					4			—			3,270			(1,859)			1,415			—			1,415
Dividends		16			—			—			—			(62,271)			(62,271)			—			(62,271)
Cancellation of warrants		16			—			—			(1,429)			—			(1,429)			—			(1,429)
Transactions with shareholders					2,048			211,800			1,841			(64,130)			151,559			—			151,559
Balance as of June 30, 2021				$	11,568		$	1,052,959		$	10,638		$	(120,854)		$	954,311		$	—		$	954,311

The notes are an integral part of the Interim Condensed Consolidated Financial Statements.

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Condensed Consolidated Statement of Cash Flows
(Unaudited) (Amounts in thousands, except per share and per unit data)

			Six Months Ended
	Notes		June 30, 2022			June 30, 2021
Cash flows from operating activities:
Net income (loss)				$	(935,250)		$	(83,957)
Cash flows from operations reconciliation:
Depreciation, depletion and amortization		6			118,480			71,843
Accretion of asset retirement obligations		17			14,003			10,216
Income tax (benefit) expense		7			(294,877)			(260,021)
(Gain) loss on fair value adjustments of unsettled financial instruments		12			1,205,938			371,458
Plugging costs of asset retirement obligations		17			(1,582)			(1,180)
(Gain) loss on natural gas and oil properties and equipment		9,10			515			(234)
(Gains) on bargain purchases		4			(1,249)			—
Finance costs		19			39,162			22,512
Revaluation of contingent consideration		4			—			5,597
Hedge modifications		12			(6,833)			(6,797)
Non-cash equity compensation		6			4,069			3,588
Working capital adjustments:
Change in trade receivables		13			(98,771)			(18,881)
Change in other current assets		14			24,099			(3,105)
Change in other assets		14			(1,632)			204
Change in trade and other payables		20			(27,907)			(270)
Change in other current and non-current liabilities		21			196,677			4,755
Cash generated from operations					234,842			115,728
Cash paid for income taxes					(29,855)			(7,607)
Net cash provided by operating activities					204,987			108,121
Cash flows from investing activities:
Consideration for business acquisitions, net of cash acquired		4			(12,274)			—
Consideration for asset acquisitions		4			(51,550)			(128,715)
Expenditures on natural gas and oil properties and equipment		9,10			(44,539)			(16,458)
(Increase) decrease in restricted cash					(25,103)			1,301
Proceeds on disposals of natural gas and oil properties and equipment		9,10			6,052			722
Contingent consideration payments		22			(19,807)			(821)
Net cash used in investing activities					(147,221)			(143,971)
Cash flows from financing activities:
Repayment of borrowings		19			(1,392,883)			(416,521)
Proceeds from borrowings		19			1,730,200			325,500
Cash paid for interest		19			(32,605)			(18,217)
Debt issuance cost		19			(24,579)			(204)
Hedge modifications associated with ABS Notes		13			(73,073)			—
Proceeds from equity issuance, net		15			—			213,844
Principal element of lease payments		18			(5,273)			(2,557)
Cancellation of warrants		15			—			(1,429)
Dividends to shareholders		16			(72,275)			(62,271)
Distributions to non-controlling interest owners					(2,776)			—
Repurchase of shares by the Employee Benefit Trust		15			(9,718)			—
Net cash provided by financing activities					117,018			38,145
Net change in cash and cash equivalents					174,784			2,295
Cash and cash equivalents, beginning of period					12,558			1,379
Cash and cash equivalents, end of period				$	187,342		$	3,674

The notes are an integral part of the Interim Condensed Consolidated Financial Statements.

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Index to the Notes to the Interim Condensed Consolidated Financial Statements

	Page
Note 1—General Information		F-76
Note 2—Basis of Preparation		F-76
Note 3—Significant Accounting Policies		F-79
Note 4—Acquisitions		F-80
Note 5—Revenue		F-83
Note 6—Expenses by Nature		F-84
Note 7—Taxation		F-85
Note 8—Earnings (Loss) Per Share		F-86
Note 9—Natural Gas and Oil Properties		F-87
Note 10—Property, Plant and Equipment		F-88
Note 11—Intangible Assets		F-89
Note 12—Derivative Financial Instruments		F-89
Note 13—Trade and Other Receivables		F-96
Note 14—Other Assets		F-96
Note 15—Share Capital		F-97
Note 16—Dividends		F-98
Note 17—Asset Retirement Obligations		F-99
Note 18—Leases		F-100
Note 19—Borrowings		F-102
Note 20—Trade and Other Payables		F-107
Note 21—Other Liabilities		F-107
Note 22—Fair Value and Financial Instruments		F-108
Note 23—Contingencies		F-110
Note 24—Related Party Transactions		F-111
Note 25—Subsequent Events		F-111

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 1—GENERAL INFORMATION

The Parent was incorporated on July 31, 2014 in the United Kingdom and is registered in England and Wales under the Companies Act 2006 as a public limited company under company number 09156132. The Company’s registered office is located at 4th floor Reading Bridge House, George Street, Reading, Berkshire, RG1 8LS, UK.

In February 2017, the Company’s shares were admitted to trading on AIM under the ticker “DGOC.” In May 2020, the Company’s shares were admitted to trading on the LSE’s Main Market for listed securities. The shares trading on AIM were cancelled concurrent to their admittance on the LSE. With the change in corporate name in 2021, the Company’s shares listed on the LSE began trading as Diversified Energy Company PLC on May 7, 2021 under the new ticker “DEC”.

NOTE 2—BASIS OF PREPARATION

Basis of Preparation

The interim condensed consolidated financial statements for the six months ended June 30, 2022 (the “Interim Condensed Consolidated Financial Statements”) have been prepared in accordance with IAS 34 Interim Financial Reporting as issued by the International Accounting Standards Board (IASB).

The interim financial statements do not include all the information and disclosures required in the annual financial statements and should be read in conjunction with the Company’s annual financial statements for the year ended December 31, 2021, which were prepared in accordance with IFRS as issued by the IASB. The principal accounting policies set out below have been applied consistently throughout the year and are consistent with the prior year unless otherwise stated.

Unless otherwise stated, the Interim Condensed Consolidated Financial Statements are presented in US Dollars, which is the Company’s subsidiaries’ functional currency and the currency of the primary economic environment in which the Company operates, and all values are rounded to the nearest thousand dollars except per share and per unit amounts and where otherwise indicated.

•

Assets and liabilities in the Consolidated Statement of Financial Position are translated at the closing rate at the date of that Consolidated Statement of Financial Position;

•

All resulting exchange differences are reflected within other comprehensive income in the Consolidated Statement of Comprehensive Income.

The Interim Condensed Consolidated Financial Statements have been prepared under the historical cost convention, as modified by the revaluation of financial assets and liabilities (including derivative instruments) held at fair value through profit and loss or through other comprehensive income.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 2—BASIS OF PREPARATION (continued)

Segment Reporting

The Company is an independent owner and operator of producing natural gas and oil wells with properties located in the states of Tennessee, Kentucky, Virginia, West Virginia, Ohio, Pennsylvania, Oklahoma, Texas and Louisiana. The Company’s strategy is to acquire long-life producing assets, efficiently operate those assets to generate Free Cash Flow for shareholders and then to retire assets safely and responsibly at the end of their useful life. The Company’s assets consist of natural gas and oil wells, pipelines and a network of gathering lines and compression facilities which are complementary to the Company’s assets. The Directors acquire and manage these assets in a complementary fashion to vertically integrate and improve margins rather than as separate operations. Accordingly, when determining operating segments under IFRS 8, the Company has identified one reportable segment that produces and transports natural gas, NGLs and oil in the US.

Going Concern

The Interim Condensed Consolidated Financial Statements have been prepared on the going concern basis, which contemplates the continuity of normal business activity and the realization of assets and the settlement of liabilities in the normal course of business. The Directors have reviewed the Company’s overall position and outlook and are of the opinion that the Company is sufficiently well funded to be able to operate as a going concern for at least the next twelve months from the date of approval of this Interim Report.

The Directors closely monitor and carefully manage the Company’s Liquidity risk. Our financial outlook is assessed primarily through the annual business planning process, however, it is also carefully monitored on a monthly basis. This process includes regular Board discussions, led by Senior Leadership, at which the current performance of, and outlook for, the Company are assessed. The outputs from the business planning process include a set of key performance objectives, an assessment of the Company’s primary risks, the anticipated operational outlook and a set of financial forecasts that consider the sources of funding available to the Company (the “Base Plan”).

The Base Plan incorporates key assumptions which underpin the business planning process. These assumptions are as follows:

•

Projected operating cash flows are calculated using a production profile which is consistent with current operating results and decline rates;

•

Assumes commodity prices are in line with the current forward curve which considers basis differentials;

•

Operating cost levels stay consistent with historical trends;

•

The financial impact of our current hedging contracts in place for the three-year assessment period, which represents approximately 90%, 70%, and 55% of total production volumes hedged for the years ending December 31, 2022, 2023 and 2024 respectively;

•

The scenario also includes the scheduled principal and interest payments on our current debt arrangements and the funding of a dividend utilizing approximately 40% of Free Cash Flow; and

•

The continuation of $15,000 a year in emissions reductions initiatives.

Scenario 1:

A sharp and sustained decline in pricing resulting in a 10% reduction to net realized prices.

Scenario 2:

An operational stoppage or regulatory event occurs which results in reduced production by approximately 5%.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 2—BASIS OF PREPARATION (continued)

Scenario 3:

A market or regulatory event triggers an increase in operating and midstream expenses by approximately 5%.

Under these downside sensitivity scenarios, the Company remains cash flow positive. The Company meets its working capital requirements, which presently primarily consist of derivative liabilities that, when settled, will be funded utilizing the higher commodity revenues from which the derivative liability was derived. The Company will also continue to meet the covenant requirements under its Credit Facility as well as its other existing borrowing instruments and continue to return cash flows to shareholders.

The Directors and Senior Leadership consider the impact that these principal risks could, in certain circumstances, have on the Company’s prospects within the assessment period, and accordingly appraise the opportunities to actively mitigate the risk of these severe, but plausible, downside scenarios. In addition to its modelled downside going concern scenarios, the Board has stress tested the model to determine the extent of downturn which would result in a breach of covenants. Assuming similar levels of cash conversion as seen in 2021, a decline in production volume and pricing well in excess of that historically experienced by the Company would need to persist throughout the going concern period for a covenant breach to occur, which is considered very unlikely. This stress test also does not incorporate certain mitigating actions or cash preservation responses, which the Company would implement in the event of a severe and extended revenue decline.

In addition to the scenarios above, the Directors also considered the current geopolitical environment and the inflationary pressures that are currently impacting the US, which are being closely monitored by the Company. Notwithstanding the modelling of specific hypothetical scenarios, the Company believes that the impact associated with these events will largely continue to be reflected in commodity markets and will extend the volatility experienced in recent months. The Company considers commodity price risk a principal risk and will continue to actively monitor and mitigate this risk.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 2—BASIS OF PREPARATION (continued)

Basis of Consolidation

The Interim Condensed Consolidated Financial Statements for the six months ended June 30, 2022 reflect the following corporate structure of the Company, and its 100% wholly owned subsidiaries:

—

Diversified Energy Company PLC (“DEC”) as well as its wholly owned subsidiaries

—

Diversified Gas & Oil Corporation

Diversified Production, LLC

—

Diversified ABS Holdings LLC

Diversified ABS LLC

—

Diversified ABS Phase II Holdings LLC

Diversified ABS Phase II LLC

—

Diversified ABS Phase III Holdings LLC

Diversified ABS Phase III LLC

—

Diversified ABS Phase III Upstream LLC

—

Diversified ABS Phase III Midstream LLC

—

Diversified ABS Phase IV Holdings LLC

Diversified ABS Phase IV LLC

—

Diversified ABS Phase V Holdings LLC

Diversified ABS Phase V LLC

—

Diversified ABS Phase V Upstream LLC

—

DP Bluegrass Holdings LLC

DP Bluegrass LLC

—

BlueStone Natural Resources II LLC

— Chesapeake Granite Wash Trust(a)

—

Tapstone Energy Holdings, LLC

Tapstone Energy Holdings II, LLC

Tapstone Energy Holdings III, LLC

Tapstone Energy, LLC

—

Tapstone Manager, LLC

—

Tapstone Management Company LLC(b)

—

Tapstone Midstream, LLC

—

Giant Land, LLC(c)

—

Beehive Land LLC(c)

—

Castle Land, LLC(c)

—

Daisy Land LLC(c)

—

Eureka Land LLC(c)

—

Link Land LLC(c)

—

Old Faithful Land LLC(c)

—

Rift Land LLC(c)

—

Riverside Land LLC(c)

—

Splendid Land LLC(c)

—

Next LVL Energy, LLC

Diversified Midstream LLC

—

Cranberry Pipeline Corporation

—

Coalfield Pipeline Company

—

DM Bluebonnet LLC

—

Black Bear Midstream Holdings LLC

Black Bear Midstream LLC

Black Bear Liquids LLC

Black Bear Liquids Marketing LLC

Diversified Energy Marketing, LLC

DGOC Holdings LLC

—

DGOC Holdings Sub III LLC

Whitehawk Digital Services LLC

(a)

Diversified Production, LLC holds 50.8% of the issued and outstanding common shares of Chesapeake Granite Wash Trust.

(b)

Owned 99.9% by Tapstone Energy LLC and 0.1% by Tapstone Manager LLC.

(c)

Owned 55% by Tapstone Energy LLC.

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES

The preparation of the Interim Condensed Consolidated Financial Statements in compliance with IAS 34 Interim Financial Reporting as issued by the IASB requires management to make estimates and exercise judgment in applying the Company’s accounting policies. In preparing the Interim Condensed Consolidated Financial Statements, the significant judgements made by management in applying the Company’s accounting policies and the key sources of estimation uncertainty were the same as those that applied to the Company Financial Statements for the year ended December 31, 2021.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 3—SIGNIFICANT ACCOUNTING POLICIES (continued)

New Standards and Interpretations

Certain new accounting standards and interpretations have been published that are not mandatory for June 30, 2022 reporting periods and have not been early adopted by the Company. None of these new standards or interpretations are expected to have a material impact on the Interim Condensed Consolidated Financial Statements of the Company.

NOTE 4—ACQUISITIONS

As part of the Company’s corporate strategy, it actively seeks to acquire assets that strategically complement the Company’s existing portfolio when they meet the acquisition criteria stated in the Acquire Long-Life Stable Assets pillar of the corporate strategy discussed in the Strategy section of the Strategic Report within the Company’s 2021 Annual Report.

2022 Acquisitions

East Texas Asset Acquisition

On April 25, 2022, the Company acquired a proportionate 52.5% working interest in certain upstream assets and related facilities within the Central Region from a private seller in conjunction with Oaktree, via the previously disclosed participation agreement between the two parties. Given the concentration of assets, this transaction was considered an asset acquisition rather than a business combination. When making this determination management performed an asset concentration test considering the fair value of the acquired assets. The Company paid purchase consideration of $51,550, including customary purchase price adjustments. Transaction costs associated with the acquisition were $1,550. The Company funded the purchase with available cash on hand and a draw on the Credit Facility. In the period from its acquisition to June 30, 2022 the acquisition of the East Texas assets increased the Company’s natural gas production by 1,338 MMcfe.

The provisional assets and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	51,550
Total consideration	$	51,550
Net assets acquired
Natural gas and oil properties	$	53,776
Natural gas and oil properties (asset retirement obligation, asset portion)		7,015
Property, plant and equipment		1,049
Trade receivables, net		23
Asset retirement obligation, liability portion		(7,015)
Other non-current liabilities		(1,667)
Other current liabilities		(1,631)
Net assets acquired	$	51,550

Other Acquisitions

During the period ended June 30, 2022 the Company acquired certain plugging infrastructure for an aggregate consideration of $2,449, inclusive of customary purchase price adjustments. The Company will

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 4—ACQUISITIONS (continued)

also pay an additional $3,150 in deferred consideration through November 2024. This expansion in the Company’s internal plugging operations brings the total plugging rigs owned and operated by the Company to nine as of June 30, 2022.

On April 1, 2022 the Company acquired certain midstream assets, inclusive of a processing facility, in the Central Region that was contiguous to its existing East Texas assets. The Company paid purchase consideration of $10,139, inclusive of customary purchase price adjustments and transaction costs. The transaction was considered a business combination given it had an identifiable set of inputs. The provisional fair value of the net assets acquired was $11,074 generating a bargain purchase gain of $935.

Transaction costs associated with the other acquisitions noted above were insignificant and the Company funded the aggregate cash consideration with existing cash on hand.

Subsequent Events

On July 27, 2022 it was announced that the Company acquired the well services and plugging assets and operations of Contractor Services Inc. of West Virginia (“ConServ”) for a purchase price of $11,500 before customary purchase price adjustments.

On July 28, 2022 it was announced that the Company entered into a purchase and sale agreement to acquire certain upstream assets in the Central Region from ConocoPhillips for a purchase price of $240,000 before customary purchase price adjustments.

2021 Acquisitions

Tapstone Energy Holdings LLC (“Tapstone”) Business Combination

On December 7, 2021, the Company acquired a proportionate 51.25% working interest in certain upstream assets, field infrastructure, equipment, and facilities within the Central Region from Tapstone in conjunction with Oaktree, via the previously disclosed participation agreement between the two parties. The acquisition also included 6 wells which were under development at the time of close which will be completed by the Company. DEC will serve as the sole operator of the assets. When evaluating the transaction, DEC determined it did not have significant asset concentration and as a result it had acquired an identifiable set of inputs, processes and outputs and concluded the transaction was a business combination. The Company paid purchase consideration of $177,496, including customary purchase price adjustments. Transaction costs associated with the acquisition were $4,039 and have been expensed. The Company funded the purchase with proceeds from the Credit Facility.

In connection with the acquisition the Company also acquired the beneficial ownership in the Chesapeake Granite Wash Trust (“the GWT”). The Company consolidates the GWT as it has determined that it controls the GWT because it (1) possesses power over the GWT, (2) has exposure to variable returns from its involvement with the GWT, and (3) has the ability to use its power over the GWT to affect its returns. The elements of control are achieved through the Company operating a majority of the natural gas and oil properties that are subject to the conveyed royalty interests, marketing of the associated production, and through its ownership of 50.8% of the outstanding common units of the GWT. The common units of the GWT owned by third parties have been reflected as a non-controlling interest in the consolidated financial statements. Common units outstanding as of December 7, 2021 were 46,750,000 with the Company’s beneficial interests in the GWT representing 50.8%. The GWT is publicly traded and the GWT’s market capitalization was utilized when determining the value of the non-controlling interests.

The GWT’s non-controlling interest is heavily concentrated in the acquired Tapstone natural gas and oil properties and, as a result, the Company consolidated $16,087 into its natural gas and oil properties associated with this non-controlling interest as of December 31, 2021. The remaining amounts in the Company’s Consolidated Statement of Financial Position associated with the non-controlling interests are immaterial and working capital in nature.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 4—ACQUISITIONS (continued)

Tanos Energy Holdings III, LLC (“Tanos”) Business Combination

Blackbeard Operating LLC (“Blackbeard”) Asset Acquisition

Indigo Minerals LLC (“Indigo”) Asset Acquisition

On May 19, 2021, the Company acquired certain upstream assets and related gathering infrastructure in the Central Region from Indigo. Given the concentration of assets this transaction was considered an acquisition of assets rather than a business combination. When making this determination management performed an asset concentration test considering the fair value of the acquired assets. The Company paid purchase consideration of $117,352, including customary purchase price adjustments and transaction costs. Transaction costs associated with the acquisition were $473 and have been capitalized to natural gas and oil properties. The Company funded the purchase with proceeds from the May 2021 equity placement and a draw on the Credit Facility, discussed in Notes 15 and 19, respectively.

2021 Divestitures

Indigo Divestiture

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 4—ACQUISITIONS (continued)

initial consideration received was $52,314, or 50% of the Company’s net purchase price on the Indigo assets which is consistent with the terms of the previously disclosed participation agreement between the Company and Oaktree. The Company will continue to serve as the sole operator of the assets. The Company used the proceeds to reduce outstanding balances on the Credit Facility.

Other Divestitures

NOTE 5—REVENUE

	Six Months Ended
	June 30, 2022			June 30, 2021
Natural gas		$	727,152		$	258,453
NGLs			107,846			35,050
Oil			78,817			13,523
Total commodity revenue			913,815			307,026
Midstream			16,602			15,089
Other			3,111			1,201
Total revenue		$	933,528		$	323,316

During the six months ended June 30, 2022, no customers individually comprised more than 10% of total revenues, while during the six months ended June 30, 2021, two customers individually comprised more than 10% of total revenues, representing 22% of consolidated revenues.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 6—EXPENSES BY NATURE

The following table provides a detail of the Company’s expenses for the periods presented:

	Six Months Ended
	June 30, 2022			June 30, 2021
LOE(a)		$	81,776		$	52,836
Production taxes(b)			33,878			9,215
Midstream operating expense(c)			33,156			29,172
Transportation expense(d)			57,547			28,332
Total operating expense(e)			206,357			119,555
Depreciation and amortization			25,251			21,197
Depletion			93,229			50,646
Total depreciation, depletion and amortization			118,480			71,843
Employees and benefits (administrative)			23,116			17,985
Other administrative(f)			5,353			6,896
Professional fees(g)			7,776			5,015
Costs associated with acquisitions(h)			6,935			6,221
Other adjusting costs(i)			67,033			2,628
Non-cash equity compensation(j)			4,069			3,588
Total G&A			114,282			42,333
Recurring allowance for credit losses(k)			—			602
Total expense		$	439,119		$	234,333
Aggregate remuneration (including Directors):
Wages and salaries		$	53,561		$	32,803
Payroll taxes			4,881			3,712
Benefits			11,715			9,252
Total employees and benefits expense		$	70,157		$	45,767

(a)

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

(b)

(c)

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

(d)

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

(e)

Total operating expense increased due to additional operating expense related to the East Texas Assets and other acquisitions in 2022 and the Tapstone, Tanos, Blackbeard and Indigo acquisitions in 2021. Refer to Note 4 for additional information regarding acquisitions.

(f)

Other administrative expense includes general liability insurance, IT services, rent, other office expenses and travel.

(g)

Professional fees include legal, marketing, payroll, auditor remuneration and consultation fees and costs associated with being a public company.

(h)

The Company generally incurs costs related to the integration of acquisitions, which will vary for each acquisition. For acquisitions considered to be a business combination, these costs include transaction costs directly associated with a successful acquisition transaction. These costs also include costs associated with transition service arrangements where we pay the seller of the acquired entity a fee to handle various G&A functions until the Company has fully integrated the assets onto its systems. In addition,

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 6—EXPENSES BY NATURE (continued)

these costs include costs related to integrating IT systems and consulting and internal workforce costs directly related to integrating acquisitions into the Company’s systems.

(i)

Other adjusting costs for the six months ended June 30, 2022 primarily consist of $28,345 in contract terminations which will allow the Company to obtain more favorable pricing in the future and $32,561 in costs associated with deal breakage and/or sourcing costs for acquisitions. For the six months ended June 30, 2021, other adjusting costs are primarily associated with one-time projects and contemplated financing arrangements. Also included are expenses associated with an unused firm transportation agreement acquired as part of the Carbon Acquisition.

(j)

Non-cash equity compensation for the six months ended June 30, 2022 and June 30, 2021 reflect the expense recognition related to share-based compensation provided to certain key members of the management team.

(k)

Allowance for credit losses consists of the recognition and reversal of credit losses. Refer to Note 13 for additional information regarding credit losses.

NOTE 7—TAXATION

The Company files a consolidated US federal tax return, multiple state tax returns, and a separate UK tax return for the Parent entity. The consolidated taxable income includes an allocatable portion of income from the Company’s co-investments with Oaktree and its investment in the Chesapeake Granite Wash Trust. Income taxes are provided for the tax effects of transactions reported in the Interim Condensed Consolidated Financial Statements and consist of taxes currently due plus deferred taxes related to differences between the basis of assets and liabilities for financial and income tax reporting. For the six months ended June 30, 2021 and 2021, Income tax expense was recognized based on management’s estimate of the annual effective tax rate expected for the full financial year.

For the taxable six months ended June 30, 2022 and 2021, the Company had a tax income tax benefit of $294,877 and of $260,021, respectively. The effective tax rate used for the six months ended June 30, 2022 was 24.0%, compared to 75.6% for the six months ended June 30, 2021. The June 30, 2021 effective tax rate was primarily impacted by the Company’s recognition of the federal well tax credit available to qualified producers in 2021 who operate lower-volume wells during a low commodity pricing environment. The federal government provides these credits to encourage companies to continue operating lower-volume wells during periods of low prices to maintain the underlying jobs they create and the state and local tax revenues they generate for communities to support schools, social programmes, law enforcement and other similar public services. The US marginal well tax credit is prescribed by Internal Revenue Code Section 45I and is available for certain natural gas production from qualifying wells. In May 2022, the US Internal Revenue Service released Notice 2022-18 which quantified the amount of credit per Mcf of qualified natural gas production for tax years beginning in 2021 and also detailed the calculation methodology for future years. The federal tax credit is intended to provide a benefit for wells producing less than 90 Mcfe per day when market prices for natural gas are relatively low. The Company benefits from this credit given its portfolio of long-life, low-decline conventional wells. The tax credit is not available for tax year 2022 due to improved commodity prices. Other impacts to the effective rate include changes in state tax rates as a result of acquisitions and recurring permanent differences, such as meals and entertainment.

The Company had a net deferred tax asset of $481,431 at June 30, 2022 compared to a net deferred tax asset of $176,955 at December 31, 2021. The change was primarily due to an improving commodity price environment generating unrealized losses for unsettled derivatives not recognized for tax purposes. While subject to the volatility associated with commodity markets, if commodity prices were to settle in line with the forward strip as of June 30, 2022, we anticipate many of these deferred tax assets to become realized in the second half of the year as the current portion of unsettled derivatives becomes settled. The presentation of deferred taxes in the balance sheet takes into consideration the offsetting of deferred tax assets and deferred tax liabilities within the same tax jurisdiction, where permitted. The overall deferred tax position in a particular tax jurisdiction determines if a deferred tax balance related to that jurisdiction is presented within deferred tax assets or deferred tax liabilities.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 7—TAXATION (continued)

The effective tax rates and differences between the statutory US federal income tax rate and the effective tax rates are summarized as follows:

	Six Months Ended
	June 30, 2022			June 30, 2021
Income (loss) before taxation		$	(1,230,127)		$	(343,978)
Income tax benefit (expense)			294,877			260,021
Effective tax rate			24.0%			75.6%

	Six Months Ended
	June 30, 2022		June 30, 2021
Expected tax at statutory US federal income tax rate		21.0%		21.0%
State income taxes, net of federal tax benefit		3.0%		5.3%
Federal credits		—%		50.3%
Other, net		—%		(1.0)%
Effective tax rate		24.0%		75.6%

NOTE 8—EARNINGS (LOSS) PER SHARE

The calculation of basic earnings (loss) per share is based on Net income (loss) and on the weighted average number of shares outstanding during the period. The calculation of diluted earnings per share is based on Net income (loss) and the weighted average number of shares outstanding plus the weighted average number of shares that would be issued if dilutive options and warrants were converted into shares on the last day of the reporting period. The weighted average number of shares outstanding for the computation of both basic and diluted earnings (loss) per share excludes shares held as treasury shares in the Employee Benefit Trust (“EBT”), which for accounting purposes are treated in the same manner as shares held in the treasury reserve. Refer to Note 15 for additional information regarding the EBT. Basic and diluted earnings (loss) per share are calculated as follows for the periods presented:

		Six Months Ended
	Calculation	June 30, 2022			June 30, 2021
Net income (loss)	A		$	(935,250)		$	(83,957)
Weighted average shares outstanding – basic and diluted	B			849,621			736,559
Earnings (loss) per share – basic and diluted	= A/B		$	(1.10)		$	(0.11)

Due to the Company’s net loss position for the six months ended June 30, 2022 and 2021, 13,540, and 5,812 potential shares were not included in the computation of diluted EPS because their effect would have been anti-dilutive.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 9—NATURAL GAS AND OIL PROPERTIES

The following table summarizes the Company’s natural gas and oil properties for the periods presented:

	Six Months Ended			Year Ended
	June 30, 2022			December 31, 2021
Costs
Beginning balance		$	2,866,353		$	1,968,557
Additions(a)			11,847			1,012,691
Disposals(b)			(19,848)			(114,895)
Ending balance		$	2,858,352		$	2,866,353
Depletion and impairment
Beginning balance		$	(336,275)		$	(213,472)
Period changes			(93,229)			(122,803)
Disposals			—			—
Ending balance		$	(429,504)		$	(336,275)
Net book value		$	2,428,848		$	2,530,078

(a)

For the six months ended June 30, 2022, the Company added $60,791 related to acquisitions, offset by $62,819 resulting from normal revisions to the Company’s asset retirement obligations. The remaining additions are primarily attributable to capital expenditures associated with the completion of the Tapstone wells that were under development at the time of acquisition. For the year ended December 31, 2021, the Company added $907,383 related to acquisitions and $78,156 resulting from normal revisions to the Company’s asset retirement obligations. The remaining change is primarily attributable to recurring capital expenditures and the revaluation of the EQT contingent consideration. Refer to Notes 4 and 17 for additional information regarding acquisitions and asset retirement obligations, respectively.

(b)

During the six months ended June 30, 2022, the Company divested various well packages in Appalachia generating proceeds of $3,280. For the year ended December 31, 2021, the Company divested $113,752 in natural gas and oil properties related to Indigo and the Tanos undeveloped acreage transaction. Refer to Notes 4 and 17 for additional information regarding divestitures.

Impairment of Natural Gas and Oil Properties

For the period ended June 30, 2022, the Directors assessed the indicators of impairment, noting strong pricing along the forward curve and an improving economic outlook for the Company. This assessment also included a comparison of the carrying value of the Company’s natural gas and oil properties to their fair values and an assessment of the projected impact of climate change on the Company. As a result of their assessments no impairment indicators were identified.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 10—PROPERTY, PLANT AND EQUIPMENT

The following tables summarize the Company’s property, plant and equipment for the periods presented:

	Six Months Ended June 30, 2022
	Buildings and Leasehold Improvements			Equipment			Motor Vehicles			Midstream Assets			Other Property and Equipment			Total
Costs
Beginning balance		$	41,684		$	9,492		$	45,562		$	398,663		$	16,039		$	511,440
Additions(a)(b)			4,247			5,369			8,195			10,617			22,508			50,936
Disposals			(3,423)			(9)			(932)			(14)			—			(4,378)
Ending balance(c)		$	42,508		$	14,852		$	52,825		$	409,266		$	38,547		$	557,998
Accumulated depreciation
Beginning balance		$	(2,078)		$	(4,089)		$	(20,186)		$	(69,501)		$	(1,606)		$	(97,460)
Period changes			(934)			(2,523)			(4,106)			(13,376)			(433)			(21,372)
Disposals			290			9			788			5			—			1,092
Ending balance		$	(2,722)		$	(6,603)		$	(23,504)		$	(82,872)		$	(2,039)		$	(117,740)
Net book value		$	39,786		$	8,249		$	29,321		$	326,394		$	36,508		$	440,258

	Year Ended December 31, 2021
	Buildings and Leasehold Improvements			Equipment			Motor Vehicles			Midstream Assets			Other Property and Equipment			Total
Costs
Beginning balance		$	28,190		$	6,768		$	35,129		$	367,331		$	5,600		$	443,018
Additions(a)(b)			13,494			2,737			12,700			31,485			10,439			70,855
Disposals			—			(13)			(2,267)			(153)			—			(2,433)
Ending balance(c)		$	41,684		$	9,492		$	45,562		$	398,663		$	16,039		$	511,440
Accumulated depreciation
Beginning balance		$	(1,007)		$	(2,860)		$	(12,409)		$	(43,597)		$	(1,042)		$	(60,915)
Period changes			(1,071)			(1,231)			(9,259)			(25,928)			(564)			(38,053)
Disposals			—			2			1,482			24			—			1,508
Ending balance		$	(2,078)		$	(4,089)		$	(20,186)		$	(69,501)		$	(1,606)		$	(97,460)
Net book value		$	39,606		$	5,403		$	25,376		$	329,162		$	14,433		$	413,980

(a)

Of the $50,936 in 2022 additions, $17,225 was related to acquisitions and $5,655 was associated with right-of-use asset additions for new leases, the remaining capital expenditures are a result of our recurring capital needs and enhanced ESG efforts. Of the $70,855 in 2021 additions, $25,961 was related to acquisitions and $16,554 was associated with right-of-use asset additions for new and acquired leases. Refer to Note 4 for additional information regarding acquisitions.

(b)

Remaining additions are related to routine capital projects on the Company’s compressor and gathering systems, as well as routine vehicle and equipment additions.

(c)

Buildings and leasehold improvements and motor vehicles are inclusive of right-of-use assets associated with the Company’s leases. Refer to Note 18 for additional information regarding leases.

The Company continued to utilize certain fully depreciated assets during the six months ended June 30, 2022 and year ended December 31, 2021 with an original cost basis of $6,953 and $5,597, respectively.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 11—INTANGIBLE ASSETS

Intangible assets consisted of the following for the periods presented:

	Six Months Ended June 30, 2022
	Software			Other Acquired Intangibles			Total
Costs
Beginning balance		$	28,095		$	2,900		$	30,995
Additions(a)			3,133			1,613			4,746
Disposals			—			—			—
Ending balance		$	31,228		$	4,513		$	35,741
Accumulated amortization
Beginning balance		$	(15,192)		$	(1,669)		$	(16,861)
Period changes			(3,659)			(475)			(4,134)
Disposals			—			—			—
Ending balance		$	(18,851)		$	(2,144)		$	(20,995)
Net book value		$	12,377		$	2,369		$	14,746

	Year Ended December 31, 2021
	Software			Other Acquired Intangibles			Total
Costs
Beginning balance		$	24,271		$	2,900		$	27,171
Additions(a)			3,824			—			3,824
Disposals			—			—			—
Ending balance		$	28,095		$	2,900		$	30,995
Accumulated amortization
Beginning balance		$	(7,246)		$	(712)		$	(7,958)
Period changes			(7,946)			(957)			(8,903)
Disposals			—			—			—
Ending balance		$	(15,192)		$	(1,669)		$	(16,861)
Net book value		$	12,903		$	1,231		$	14,134

(a)

For the six months ended June 30, 2022 and for the year ended December 31, 2021 additions were related to software enhancements and other acquired intangibles.

NOTE 12—DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to volatility in market prices and basis differentials for natural gas, NGLs and oil, which impacts the predictability of its cash flows related to the sale of those commodities. The Company can also have exposure to volatility in interest rate markets, depending on the makeup of its debt structure, which impacts the predictability of its cash flows related to interest payments on the Company’s variable rate debt obligations. These risks are managed by the Company’s use of certain derivative financial instruments. As of June 30, 2022, the Company’s derivative financial instruments consisted of swaps, collars, basis swaps, stand-alone put and call options, and swaptions. A description of the Company’s derivative financial instruments is provided below:

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 12—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

	Swaps:			If the Company sells a swap, it receives a fixed price for the contract and pays a floating market price to the counterparty;
	Collars:			Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net costs. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price. Certain collar arrangements may also include a sold put option with a strike price below the purchased put option. Referred to as a three-way collar, the structure works similar to the above description, except that when the index price settles below the sold put option, the Company pays the counterparty the difference between the index price and sold put option, effectively enhancing realized pricing by the difference between the price of the sold and purchased put option.
	Basis swaps:			Arrangements that guarantee a price differential for commodities from a specified delivery point. If the Company sells a basis swap, it receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract;
	Put options:			The Company purchases and sells put options in exchange for a premium. If the Company purchases a put option, it receives from the counterparty the excess (if any) of the market price below the strike price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party;
	Call options:			The Company purchases and sells call options in exchange for a premium. If the Company purchases a call option, it receives from the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company sells a call option, it pays the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party; and
	Swaptions:			If the Company sells a swaption, the counterparty will receive the option to enter into a swap contract at a specified date and receives a fixed price for the contract and pays a floating market price to the counterparty.

The Company may elect to enter into offsetting transactions for the above instruments for the purpose of cancelling or terminating certain positions.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 12—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

The following tables summarize the Company’s calculated net fair value of derivative financial instruments as of the reporting date as follows:

	Weighted Average Price per Mcfe(a)
NATURAL GAS CONTRACTS	Volume (MMcf)		Swaps			Sold Puts			Purchased Puts			Sold Calls			Purchased Calls			Basis Differential			Fair Value at June 30, 2022
For the remainder of 2022
Swaps		104,252		$	3.15		$	—		$	—		$	—		$	—		$	—		$	(281,677)
Collars		3,680			—			—			4.56			5.30			—			—			(3,326)
Sold Calls		14,020			—			—			—			2.10			—			—			(50,334)
Basis Swap		92,045			—			—			—			—			—			(0.55)			24,373
Total 2022 contracts		213,997																				$	(310,964)
2023
Swaps		196,000		$	3.29		$	—		$	—		$	—		$	—		$	—		$	(307,936)
Three-Way Collars		5,400			—			2.14			2.82			3.59			—			—			(11,626)
Stand-Alone Calls		47,067			—			—			—			2.93			—			—			(133,792)
Basis Swap		99,574			—			—			—			—			—			(0.75)			24,072
Total 2023 contracts		348,041																				$	(429,282)
2024
Swaps		158,186		$	3.02		$	—		$	—		$	—		$	—		$	—		$	(234,564)
Stand-Alone Calls		37,698			—			—			—			2.91			—			—			(61,046)
Basis Swap		35,904			—			—			—			—			—			(0.75)			4,011
Total 2024 contracts		231,788																				$	(291,599)
2025
Swaps		133,461		$	2.99		$	—		$	—		$	—		$	—		$	—		$	(184,253)
Stand-Alone Calls		21,900			—			—			—			3.00			—			—			(31,508)
Total 2025 contracts		155,361																				$	(215,761)
2026
Swaps		102,715		$	3.02		$	—		$	—		$	—		$	—		$	—		$	(130,776)
2027
Swaps		50,679		$	2.86		$	—		$	—		$	—		$	—		$	—		$	(65,112)
Purchased puts		40,218			—			—			3.10			—			—			—			14,438
Sold puts		16,414			—			1.93			—			—			—			—			(1,497)
2028
Swaps		32,190		$	2.50		$	—		$	—		$	—		$	—		$	—		$	(49,625)
Purchased puts		54,203			—			—			3.04			—			—			—			18,025
Sold puts		31,585			—			1.93			—			—			—			—			(2,698)
2029
Swaps		29,190		$	2.49		$	—		$	—		$	—		$	—		$	—		$	(45,557)
Purchased puts		30,066			—			—			2.93			—			—			—			9,144
Sold puts		30,066			—			1.93			—			—			—			—			(2,692)
2030
Swaps		5,450		$	2.43		$	—		$	—		$	—		$	—		$	—		$	(9,364)
Purchased puts		14,492			—			—			2.94			—			—			—			3,675
Sold puts		14,492			—			1.93			—			—			—			—			(1,008)
Swaptions
10/1/2024-9/30/2028(b)		14,610		$	2.92		$	—		$	—		$	—		$	—		$	—		$	(19,059)
1/1/2025-12/31/2029(c)		36,520			2.78			—			—			—			—			—			(49,447)
4/1/2026-3/31/2030(d)		97,277			2.57			—			—			—			—			—			(139,018)

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 12—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

	Weighted Average Price per Mcfe(a)
NATURAL GAS CONTRACTS	Volume (MMcf)		Swaps		Sold Puts		Purchased Puts		Sold Calls		Purchased Calls		Basis Differential		Fair Value at June 30, 2022
4/1/2030-3/31/2032(e)		42,627		2.57		—		—		—		—		—			(66,775)
Total 2026-2032 contracts		642,794														$	(537,346)
Total natural gas contracts		1,591,981														$	(1,784,952)

(a)

Rates have been converted from Btu to Mcfe using a Btu conversion factor of 1.07.

(b)

Option expires on September 6, 2024.

(c)

Option expires on December 23, 2024.

(d)

Option expires on March 23, 2026.

(e)

Option expires on March 22, 2030.

	Weighted Average Price per Bbl
NGLs CONTRACTS	Volume (MBbls)		Swaps			Sold Puts			Purchased Puts			Sold Calls			Purchased Calls			Basis Differential			Fair Value at June 30, 2022
For the Remainder of 2022
Swaps(a)		2,037		$	29.03		$	—		$	—		$	—		$	—		$	—		$	(55,870)
2023
Swaps(a)		3,367		$	36.80		$	—		$	—		$	—		$	—		$	—		$	(37,627)
Stand-Alone Calls		365			—			—			—			24.78			—			—			(6,991)
2024
Swaps(a)		1,573		$	35.40		$	—		$	—		$	—		$	—		$	—		$	(6,468)
2025
Swaps(a)		1,501		$	30.69		$	—		$	—		$	—		$	—		$	—		$	(5,100)
2026
Swaps(a)		730		$	28.35		$	—		$	—		$	—		$	—		$	—		$	610
Total NGLs contracts		9,573																				$	(111,446)

(a)

Certain portions of NGL swaps include effects of purchased oil swaps intended to provide a final NGL price as a percentage of WTI.

	Weighted Average Price per Bbl
OIL CONTRACTS	Volume (MBbls)		Swaps			Sold Puts			Purchased Puts			Sold Calls			Purchased Calls			Basis Differential			Fair Value at June 30, 2022
For the Remainder of 2022
Swaps		452		$	67.46		$	—		$	—		$	—		$	—		$	—		$	(14,474)
Sold Calls		16			—			—			—			98.00			—			—			(143)
2023
Swaps		428		$	60.75		$	—		$	—		$	—		$	—		$	—		$	(10,751)
Sold Calls		117			—			—			—			53.20			—			—			(4,081)

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 12—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

	Weighted Average Price per Bbl
OIL CONTRACTS	Volume (MBbls)		Swaps			Sold Puts			Purchased Puts			Sold Calls			Purchased Calls				Basis Differential			Fair Value at June 30, 2022
2024
Swaps		64		$	37.00		$	—		$	—		$	—		$	—	��		$	—		$	(2,515)
2025
Swaps		56			37.00			—			—			—		$	—				—			(1,861)
2026
Swaps		13			37.00			—			—			—		$	—				—			(407)
Total oil contracts		1,146																					$	(34,232)

INTEREST	Principal Hedged			Fixed Rate		Fair Value at June 30, 2022
2022
SOFR Interest Rate Swap		$	400,000		1.73%		$	(2,800)
Net fair value of derivative financial instruments as of June 30, 2022							$	(1,933,430)

Derivative Financial Instruments	Consolidated Statement of Financial Position	June 30, 2022			December 31, 2021
Assets:
Non-current assets	Derivative financial instruments		$	3,069		$	219
Current assets	Derivative financial instruments			28,361			1,052
Total assets			$	31,430		$	1,271
Liabilities
Non-current liabilities	Derivative financial instruments		$	(1,265,018)		$	(556,982)
Current liabilities	Derivative financial instruments			(699,842)			(251,687)
Total liabilities			$	(1,964,860)		$	(808,669)
Net assets (liabilities):
Net assets (liabilities)–non-current	Other non-current assets (liabilities)		$	(1,261,949)		$	(556,763)
Net assets (liabilities)–current	Other current assets (liabilities)			(671,481)			(250,635)
Total net assets (liabilities)			$	(1,933,430)		$	(807,398)

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 12—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

The Company presents the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

	As of June 30, 2022
	Presented without Effects of Netting			Effects of Netting			As Presented with Effects of Netting
Non-current assets		$	120,685		$	(117,616)		$	3,069
Current assets			129,727			(101,366)			28,361
Total assets		$	250,412		$	(218,982)		$	31,430
Non-current liabilities		$	(1,382,928)		$	117,910		$	(1,265,018)
Current liabilities			(800,914)			101,072			(699,842)
Total liabilities		$	(2,183,842)		$	218,982		$	(1,964,860)
Total net assets (liabilities)		$	(1,933,430)		$	—		$	(1,933,430)

	As of December 31, 2021
	Presented without Effects of Netting			Effects of Netting			As Presented with Effects of Netting
Non-current assets		$	29,767		$	(29,548)		$	219
Current assets			62,144			(61,092)			1,052
Total assets		$	91,911		$	(90,640)		$	1,271
Non-current liabilities		$	(586,584)		$	29,602		$	(556,982)
Current liabilities			(312,725)			61,038			(251,687)
Total liabilities		$	(899,309)		$	90,640		$	(808,669)
Total net assets (liabilities)		$	(807,398)		$	—		$	(807,398)

The Company recorded the following gain (loss) on derivative financial instruments in the Consolidated Statement of Comprehensive Income for the periods presented:

	Six Months Ended
	June 30, 2022			June 30, 2021
Net gain (loss) on commodity derivative settlements(a)		$	(468,731)		$	(21,949)
Net gain (loss) on interest rate swap(a)			828			(251)
Gain (loss) on foreign currency hedge(a)			—			(1,227)
Total gain (loss) on settled derivative instruments		$	(467,903)		$	(23,427)
Gain (loss) on fair value adjustments of unsettled financial instruments(b)			(1,205,938)			(371,458)
Total gain (loss) on derivative financial instruments		$	(1,673,841)		$	(394,885)

(a)

Represents the cash settlement of hedges that settled during the period.

(b)

Represents the change in fair value of financial instruments net of removing the carrying value of hedges that settled during the period.

All derivatives are defined as Level 2 instruments as they are valued using inputs and outputs other than quoted prices that are observable for the assets and liabilities.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 12—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

Commodity Derivative Contract Modifications and Extinguishments

From time to time, such as when acquiring producing assets, completing ABS financings or navigating changing price environments, the Company will opportunistically modify, offset, extinguish or add to certain existing hedge positions. Modifications include the volume of production subject to contracts, the swap or strike price of certain derivative contracts and similar elements of the derivative contract.

2022 Modifications and Extinguishments

The Company maintains distinct, long-dated derivative contract portfolios for its ABS financings and Term Loan I. The Company also maintains a separate derivative contract portfolio related to its assets collateralized by the Credit Facility. In February 2022, the Company adjusted portions of its derivative contract portfolio across these legal entities to ensure that it maintains the appropriate level and composition at both the legal entity and full-Company level for the completion of the ABS III and ABS IV financing arrangements. The Company completed these portfolio adjustments by entering into new derivative commodity contracts and novating certain derivative contracts to the legal entities holding the ABS III and ABS IV notes. The Company paid $41,823 for these portfolio adjustments including long dated puts purchased for ABS III and ABS IV that collectively increased the value of the Company’s derivative position by an equal amount. The Company recorded payments for offsetting positions as new derivative financial instruments and applied extinguishment payments against the existing commodity contracts on its Consolidated Statement of Financial Position.

In May 2022, the Company completed the ABS V financing arrangement and made similar derivative portfolio adjustments to maintain the appropriate level and composition of derivatives at both the legal entity and full-Company level. The Company paid $31,250 for the purchase of puts that increased the value of the Company’s derivative position. The Company recorded the payments as new derivative financial instruments on its Consolidated Statement of Financial Position.

Other commodity derivative contract modifications made during the normal course of business for the six months ended June 30, 2022 totaled $6,833 which the Company recorded on its Consolidated Statement of Financial Position. As these modifications were made in the normal course, the Company has presented these as an operating activity in the Consolidated Statement of Cash Flows.

Subsequent Events

Subsequent to June 30, 2022, and largely related to its three completed securitization financings for an aggregate of $970 million, the Company made additional derivative contract modifications totalling $87,600 to align the Company’s portfolio with its financing entities. The Company recorded payments for offsetting positions as new derivative financial instruments and applied extinguishment payments against the existing commodity contracts on its Consolidated Statement of Financial Position.

2021 Modifications and Extinguishments

In August 2021, as part of the Tanos acquisition, the Company obtained the option to novate or extinguish the Tanos hedge book. In conjunction with the closing settlement, DEC elected to extinguish their share of the Tanos hedge book. The cost to terminate was $52,666. This payment relieved the termination liability established on the Company’s Consolidated Statement of Financial Position in purchase accounting and has been presented as an investing activity in the Consolidated Statement of Cash Flows given its connection to the Tanos acquisition. New derivative contracts were subsequently entered into for more favorable pricing in order to secure the cash flows associated with these producing assets in an elevated price environment.

In May 2021, subsequent to the close of the Indigo acquisition, market dynamics began shifting to a more favorable commodity price environment. Given the favorable forward curve, the Company elected to early terminate certain legacy Indigo derivative positions resulting in a cash payment of $6,797 which the

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TABLE OF CONTENTS

Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 12—DERIVATIVE FINANCIAL INSTRUMENTS (continued)

Company recorded on its Consolidated Statement of Financial Position. Since this extinguishment occurred subsequent to the acquisition date the Company has presented this payment as an operating activity on the Consolidated Statement of Cash Flows. New derivative contracts were subsequently entered into for more favorable pricing in order to secure the cash flows associated with these producing assets in an elevated price environment.

NOTE 13—TRADE AND OTHER RECEIVABLES

Trade receivables include amounts due from customers, entities that purchase the Company’s natural gas, NGLs and oil production, and also include amounts due from joint interest owners, entities that own a working interest in the properties operated by the Company. The majority of trade receivables are current, and the Company believes these receivables are collectible. The following table summarizes the Company’s trade receivables. The fair value approximates the carrying value as of the periods presented:

	June 30, 2022			December 31, 2021
Commodity receivables(a)		$	371,954		$	275,295
Other receivables			19,603			13,768
Total trade receivables		$	391,557		$	289,063
Allowance for credit losses(b)			(7,921)			(6,141)
Total trade receivables, net		$	383,636		$	282,922

(a)

The increase in commodity receivables reflects the increase in commodity pricing over the course of 2021 and the first half of 2022 as well as our growth through acquisitions.

(b)

The allowance for credit losses was primarily related to amounts due from joint interest owners. Year-over-year increases were primarily associated with acquisitions activity.

NOTE 14—OTHER ASSETS

The following table includes a detail of other assets as of the periods presented:

	June 30, 2022			December 31, 2021
Other non-current assets
Other non-current assets		$	5,521		$	3,635
Total other non-current assets		$	5,521		$	3,635
Other current assets
Prepaid expenses		$	7,544		$	5,126
Other assets(a)(b)			—			25,004
Inventory			8,419			9,444
Total other current assets		$	15,963		$	39,574

(a)

Primarily consists of payments associated with potential acquisitions. These costs include deposits, right of first refusal or option agreement costs, and other acquisition related payments.

(b)

Acquiring long-life stable assets is central to the Company’s strategy. At times, due to changing macroeconomic conditions, commodity price volatility and/or findings observed during the Company’s deal diligence efforts, the Company incurs breakage and/or deal sourcing fees. Due to decisions made during the six months ended June 30, 2022, the Company wrote off $25,000 in certain acquisition related costs related to these items. Refer to Note 6 for additional information regarding costs associated with acquisitions.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 15—SHARE CAPITAL

Issuance of Share Capital

In 2022, there were no issuances of share capital for purposes other than share-based compensation awards issued at par which was insignificant for the period.

Treasury Shares

The Company’s holdings in its own equity instruments are classified as treasury shares. The consideration paid, including any directly attributable incremental costs, is deducted from the stockholders’ equity of the Company until the shares are cancelled or reissued. No gain or loss is recognized in the income statement on the purchase, sale, issue or cancellation of treasury shares.

Employee Benefit Trust (“EBT”)

In March 2022, the Company established the EBT for the benefit of the employees of the Company. The Company funds the EBT to facilitate the acquisition of shares. The shares in the EBT are held to satisfy awards and grants under the Company’s 2017 Equity Incentive Plan. Shares held in the EBT are accounted for in the same manner as treasury shares and are therefore included in the Consolidated Financial Statements as Treasury Shares.

During the six months ended June 30, 2022, the EBT purchased 6,790 shares at an average price per share of $1.43 (approximately £1.14) for a total consideration of $9,718 (approximately £7,708). No shares were reissued from the EBT during the six months ended June 30, 2022. As of June 30, 2022, the EBT held 6,790 shares.

Cancellation of Warrants

In February 2022, the Company entered into an agreement to cancel 477 warrants (the “Warrants”) held by certain former Mirabaud employees for an aggregate principal amount of approximately $265 (approximately £196). The former employees surrendered the Warrants to the Company for cancellation. Concurrently, the Company entered into an agreement to exercise 290 Warrants held by certain former Mirabaud employees for an aggregate principal amount of approximately $251 (approximately $189). The former employees surrendered the Warrants to the Company for cancellation in exchange for an equivalent number of shares of common stock. Following these transactions, 355 warrants remain outstanding.

In January 2021, the Company entered into an agreement to cancel 2,377 warrants held by Mirabaud Securities Limited (“Mirabaud”) and certain former Mirabaud employees for an aggregate principal amount of approximately $1,429 (approximately £1,040). Mirabaud and its former employees surrendered the Warrants to the Company for cancellation.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 15—SHARE CAPITAL (continued)

The following tables summarize the Company’s share capital, net of customary transaction costs, for the periods presented:

	Number of Shares		Total Share Capital			Total Share Premium
Balance at December 31, 2021		849,655		$	11,571		$	1,052,959
Issuance of share capital		—			—			—
Repurchase of shares by the EBT		(6,790)			—			—
Repurchase of shares		—			—			—
Other issues(a)		1,083			9			—
Balance as of June 30, 2022		843,948		$	11,580		$	1,052,959

	Number of Shares		Total Share Capital			Total Share Premium
Balance at December 31, 2020		707,377		$	9,520		$	841,159
Issuance of share capital		141,541			2,044			211,800
Repurchase of shares		—			—			—
Other issues(a)		737			7			—
Balance at December 31, 2021		849,655		$	11,571		$	1,052,959

(a)

During the six months and year ended June 30, 2022 and December 31, 2021, the Company issued 1,083 and 737 RSUs, respectively, to certain key managers. The RSUs had no impact on share premium.

NOTE 16—DIVIDENDS

The following table summarizes the Company’s dividends declared and paid on the dates indicated:

	Dividend per Share						Record Date	Pay Date	Shares Outstanding	Gross Dividends Paid
Date Dividends Declared	USD			GBP			Record Date	Pay Date	Shares Outstanding	Gross Dividends Paid
Declared on October 28, 2021		$	0.0425		£	0.0325	March 4, 2022	March 28, 2022	850,047		$	36,127
Declared on March 22, 2022		$	0.0425		£	0.0343	May 27, 2022	June 30, 2022	850,548			36,148
Paid in the six months ended June 30, 2022											$	72,275

Date Dividends Declared	Dividend per Share						Record Date	Pay Date	Shares Outstanding		Gross Dividends Paid
Date Dividends Declared	USD			GBP			Record Date	Pay Date	Shares Outstanding		Gross Dividends Paid
Declared on October 29, 2020		$	0.0400		£	0.0285	March 5, 2021	March 26, 2021		707,525		$	28,301
Declared on March 8, 2021		$	0.0400		£	0.0281	May 28, 2021	June 24, 2021		849,434			33,970
Declared on April 30, 2021		$	0.0400		£	0.0288	September 3, 2021	September 24, 2021		849,603		$	33,984
Declared on August 5, 2021		$	0.0400		£	0.0299	November 26, 2021	December 17, 2021		849,603			33,984
Paid in the year ended December 31, 2021												$	130,239

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 16—DIVIDENDS (continued)

On May 16, 2022 the Company proposed a dividend of $0.0425 per share. The dividend will be paid on September 26, 2022 to shareholders on the register on September 2, 2022. This dividend was not required to be approved by shareholders, thereby qualifying it as an “interim” dividend. No liability was recorded in the Interim Condensed Consolidated Financial Statements in respect of this interim dividend as of June 30, 2022.

Subsequent Events

On August 8, 2022 the Directors recommended a dividend of $0.0425 per share. The dividend will be paid on December 28, 2022 to shareholders on the register on November 25, 2022. This dividend was not required to be approved by shareholders, thereby qualifying it as an “interim” dividend. No liability has been recorded in the Interim Condensed Consolidated Financial Statements in respect of this dividend as of June 30, 2022.

NOTE 17—ASSET RETIREMENT OBLIGATIONS

The Company records a liability for the future cost of decommissioning its natural gas and oil properties, which it expects to incur at the end of the long-producing life of a well. Productive life varies within the Company’s well portfolio and presently the Company expects all of its existing wells to have reached the end of their economic lives and be retired by approximately 2095 consistent with our reserve calculations which were independently evaluated by our independent engineers for the year ended December 31, 2021. The Company also records a liability for the future cost of decommissioning its production facilities and pipelines when required by contract, statute, or constructive obligation. The decommissioning liability represents the present value of estimated future decommissioning costs. No such contractual agreements or statutes were in place for the Company for the six months ended June 30, 2022 and year ended December 31, 2021.

The Company applies a contingency allowance for annual inflationary cost increases to its current cost expectations then discounts the resulting cash flows using a credit adjusted risk free discount rate. The inflationary adjustment is a US long-term 10-year rate sourced from consensus economics. When determining the discount rate of the liability, the Company evaluates treasury rates as well as the Bloomberg 15-year US Energy BB and BBB bond index which economically aligns with the underlying long-term and unsecured liability. Based on this evaluation the net discount rate used in the calculation of the decommissioning liability in 2022 and 2021 was 3.2% and 2.9%, respectively.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 17—ASSET RETIREMENT OBLIGATIONS (continued)

The composition of the provision for asset retirement obligations at the reporting date was as follows for the periods presented:

	Six Months Ended			Year Ended
	June 30, 2022			December 31, 2021
Balance at beginning of period		$	525,589		$	346,124
Additions(a)			7,015			96,292
Accretion			14,003			24,396
Plugging costs			(1,582)			(2,879)
Divestitures(b)			(16,890)			(16,500)
Revisions to estimate(c)			(62,819)			78,156
Balance at end of period		$	465,316		$	525,589
LESS: Current asset retirement obligations			3,151			3,399
Non-current asset retirement obligations		$	462,165		$	522,190

(a)

Refer to Note 4 for additional information regarding acquisitions.

(b)

Associated with the divestiture of natural gas and oil properties in the normal course of business. Refer to Notes 4 and 9 for additional information.

(c)

As of June 30, 2022, the Company performed normal revisions to its asset retirement obligations, which resulted in a $62,819 decrease in the liability. This decrease was comprised of a $74,410 decrease attributable to a higher discount rate and $9,832 in cost revisions for our recent experiences. The higher discount rate was a result of macroeconomic factors spurred by the increase in bond yields which have elevated with US treasuries to combat the current inflationary environment. Partially offsetting this decrease was a $21,328 timing revision for the acceleration of our retirement plans made possible by the recent plugging acquisitions that improve our plugging capacity through the growth of our operational capabilities.

As of December 31, 2021, the Company performed normal revisions to its asset retirement obligations, which resulted in a $78,156 increase in the liability. This increase was comprised of a $109,306 increase attributable to the lower discount rate which was then offset by a $27,038 reduction in anticipated ARO cost. The remaining change was attributable to timing. The lower discount rate was a result of macroeconomic factors spurred by the COVID-19 recovery, which reduced bond yields and increased inflation. Cost reductions are a result of the expansion of the Company’s internal plugging programme and efficiencies gained.

ARO Sensitivity	+10%			-10%
Discount rate		$	(44,571)		$	51,072
Timing			26,530			(29,402)
Cost			46,532			(46,532)

NOTE 18—LEASES

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 18—LEASES (continued)

	Present Value of Minimum Lease Payments
	June 30, 2022			December 31, 2021
Balance at beginning of period		$	27,804		$	18,878
Additions(a)			5,655			16,482
Interest expense(b)			746			1,050
Cash outflows			(5,273)			(8,606)
Balance at end of period		$	28,932		$	27,804
Classified as:
Current liability		$	10,039		$	9,627
Non-current liability			18,893			18,177
Total		$	28,932		$	27,804

(a)

The $5,655 in lease additions during the six months ended June 30, 2022, was attributable to the expansion of our fleet due to our growth. Of the $16,482 in lease additions during 2021, $8,062 were attributable to the Indigo, Blackbeard and Tapstone acquisitions. Refer to Note 4 for additional information regarding acquisitions.

(b)

Included as a component of finance cost.

Set out below is the movement in the right-of-use assets:

	Right-of-Use Assets
	June 30, 2022			December 31, 2021
Balance at beginning of period		$	26,908		$	18,026
Additions(a)			5,655			16,554
Depreciation			(5,244)			(7,672)
Balance at end of period		$	27,319		$	26,908
Classified as:
Motor vehicles		$	21,186		$	19,149
Midstream			5,356			6,502
Buildings and leasehold improvements			777			1,257
Total		$	27,319		$	26,908

(a)

The $5,655 in lease additions during the six months ended June 30, 2022, was attributable to the expansion of our fleet due to our growth. Of the $16,554 in lease additions during the year ended December 31, 2021, $8,062 were attributable to the Indigo, Blackbeard and Tapstone acquisitions. Refer to Note 4 for additional information regarding acquisitions.

The range of discount rates applied in calculating right-of-use assets and related lease liabilities, depending on the lease term, is presented below:

			June 30, 2022			December 31, 2021
Discount rates range			1.8%–4.5%			1.8%–3.3%

Expenses related to short-term and low-value lease exemptions applied under IFRS 16 are primarily associated with compressor rentals and were $11,967 and $5,956 for the six months ended June 30, 2022 and 2021, respectively. These amounts have been included in the Company’s operating expenses and are primarily concentrated in LOE.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 18—LEASES (continued)

The following table reflects the maturity of leases as of the periods presented:

	June 30, 2022			December 31, 2021
Not Later Than One Year		$	10,039		$	9,627
Later Than One Year and Not Later Than Five Years			18,893			18,177
Later Than Five Years			—			—
Total		$	28,932		$	27,804

NOTE 19—BORROWINGS

The Company’s borrowings consist of the following amounts as of the reporting date as follows:

	June 30, 2022			December 31, 2021
Credit Facility (Interest rate of 4.25% and 3.36%, respectively)(a)		$	—		$	570,600
ABS I Notes (Interest rate of 5.00%)			141,347			155,266
ABS II Notes (Interest rate of 5.25%)			158,475			169,320
ABS III Notes (Interest rate of 4.875%)			349,477			—
ABS IV Notes (Interest rate of 4.95%)			149,900			—
ABS V Notes (Interest rate of 5.78%)			445,000			—
Term Loan I (Interest rate of 6.50%)			128,595			137,099
Miscellaneous, primarily for real estate, vehicles and equipment			8,623			9,380
Total borrowings		$	1,381,417		$	1,041,665
Less: Current portion of long-term debt			(263,942)			(58,820)
Less: Deferred financing costs			(45,789)			(26,413)
Less: Original issue discounts			(4,302)			(4,897)
Total non-current borrowings, net		$	1,067,384		$	951,535

(a)

Represents the variable interest rate as of period end.

Credit Facility

In May 2022, the Company reaffirmed its borrowing base on the Credit Facility at $300,000, which retains the maturity date of the previous facility of August 2025. The Credit Facility has an interest rate of SOFR plus an additional spread that ranges from 2.75% to 3.75% based on utilization. Interest payments on the Credit Facility are paid on a monthly basis. The next redetermination is in October 2022. Available borrowings under the Credit Facility were $281,982 as of June 30, 2022 which considers the impact of $18,018 in letters of credit issued to certain counterparties.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 19—BORROWINGS (continued)

payments and amendments, restrictive agreements, investments, restricted payments and hedging. It also requires the Company to maintain a ratio of total debt to EBITDAX of not more than 3.25 to 1.00 and a ratio of current assets (with certain adjustments) to current liabilities of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. The fair value of the Credit Facility approximates the carrying value as of June 30, 2022.

Term Loan I

In May 2020, the Company acquired DP Bluegrass LLC (“Bluegrass”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to enter into a securitized financing agreement for $160,000, which was structured as a secured term loan. The Company issued the Term Loan I at a 1% discount and used the proceeds of $158,400 to fund the Carbon and EQT acquisitions.

The Term Loan I is secured by certain producing assets acquired from Carbon and EQT.

The Term Loan I accrues interest at a stated 6.50% annual rate and has a maturity date of May 2030. Interest and principal payments on the Term Loan I are payable on a monthly basis. During the six months ended June 30, 2022 and 2021 and the year ended December 31, 2021, the Company incurred $4,455, $5,091 and $9,860 in interest related to the Term Loan I, respectively, which is recognized under the effective interest rate method. The fair value of the Term Loan I approximates the carrying value as of June 30, 2022.

ABS I Notes

The ABS I Notes are secured by certain of the Company’s upstream producing Appalachian assets. Natural gas production associated with these assets was hedged at 85% at the close of the agreement with long-term derivative contracts.

Interest and principal payments on the ABS I Notes are payable on a monthly basis. The legal final maturity date is January 2037 with an amortizing maturity of December 2029. The ABS I Notes accrue interest at a stated 5% rate per annum. During the six months ended June 30, 2022 and 2021 and the year ended December 31, 2021, the Company incurred $3,734, $4,383 and $8,460 of interest related to the ABS I Notes, respectively. In the event that ABS I has cash flow in excess of the required payments, ABS I is required to pay between 25% and 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with the Company. The fair value of the ABS I Notes approximates the carrying value as of June 30, 2022.

ABS II Notes

In April 2020, the Company formed Diversified ABS Phase II LLC (“ABS II”), a limited-purpose, bankruptcy-remote, wholly owned subsidiary, to enter into a securitized financing agreement for $200,000. The ABS II Notes are BBB rated and were issued at a 2.775% discount. The Company used the proceeds of $183,617, net of discount, capital reserve requirement, and debt issuance costs, to pay down its Credit Facility.

The ABS II Notes are secured by certain of the Company’s upstream producing Appalachian assets. Natural gas production associated with these assets was hedged at 85% at the close of the agreement with long-term derivative contracts.

The ABS II Notes accrue interest at a stated 5.25% rate per annum and have a maturity date of July 2037. Interest and principal payments on the ABS II Notes are payable on a monthly basis. During the six months ended June 30, 2022 and 2021 and the year ended December 31, 2021, the Company incurred $4,798, $5,421 and $10,530 in interest related to the ABS II Notes, respectively, which is recognized under the effective

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 19—BORROWINGS (continued)

interest rate method. In the event that ABS II has cash flow in excess of the required payments, ABS II is required to pay between 25% and 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with the Company. The fair value of the ABS II Notes approximates the carrying value as of June 30, 2022.

ABS III Notes

The ABS III Notes are secured by certain of the Company’s upstream producing, as well as certain midstream, Appalachian assets.

The ABS III Notes accrue interest at a stated 4.875% rate per annum and have a final maturity date of April 2039 with an amortizing maturity of November 2030. Interest and principal payments on the ABS III Notes are payable on a monthly basis. During the six months ended June 30, 2022, the Company incurred $7,099 in interest related to the ABS III Notes, which is recognized under the effective interest rate method. In the event that ABS III has cash flow in excess of the required payments, ABS III is required to pay between 25% and 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with the Company. Additionally, ABS III is subject to a contingent interest provision, whereas the Company must meet certain sustainability-linked performance targets. If those targets are not met, the interest rate will increase by five basis points above the initial stated interest rate. The fair value of the ABS III Notes approximates the carrying value as of June 30, 2022.

ABS IV Notes

The ABS IV Notes are secured by a portion of the upstream producing Blackbeard acquisition assets.

The ABS IV Notes accrue interest at a stated 4.95% rate per annum and have a final maturity date of February 2037 with an amortizing maturity of September 2030. Interest and principal payments on the ABS IV Notes are payable on a monthly basis. During the six months ended June 30, 2022, the Company incurred $2,730 in interest related to the ABS III Notes, which is recognized under the effective interest rate method. In the event that ABS IV has cash flow in excess of the required payments, ABS IV is required to pay between 25% and 100% of the excess cash flow, contingent on certain performance metrics, as additional principal, with the remaining excess cash flow, if any, remaining with the Company. Additionally, ABS IV is subject to a contingent interest provision, whereas the Company must meet certain sustainability-linked performance targets. If those targets are not met, the interest rate will increase by five basis points above the initial stated interest rate. The fair value of the ABS IV Notes approximates the carrying value as of June 30, 2022.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 19—BORROWINGS (continued)

ABS V Notes

The ABS V Notes are secured by a majority of the Company’s remaining upstream assets in Appalachia that are not securitized by previous ABS transactions.

The ABS V Notes accrue interest at a stated 5.78% rate per annum and have a final maturity date of May 2039 with an amortizing maturity of December 2030. Interest and principal payments on the ABS V Notes are payable on a monthly basis. During the six months ended June 30, 2022, the Company incurred $2,286 in interest related to the ABS III Notes, which is recognized under the effective interest rate method. Based on whether certain performance metrics are achieved, ABS V could be required to apply 50% to 100% of any excess cash flow to make additional principal payments. Additionally, ABS V is subject to a contingent interest provision, whereas the Company must meet certain sustainability-linked performance targets. If those targets are not met, the interest rate will increase by five basis points above the initial stated interest rate. The fair value of the ABS V Notes approximates the carrying value as of June 30, 2022.

In addition, a “second party opinion provider” certified the terms of the ABS V Notes as being aligned with the framework for sustainability-linked bonds of the International Capital Markets Association (“ICMA”), applicable to bond instruments for which the financial and/or structural characteristics vary depending on whether predefined ESG objectives—or sustainability performance targets (“SPTs”)—are achieved. The framework has five key components (1) the selection of key performance indicators (“KPIs”), (2) the calibration of SPTs, (3) variation of bond characteristics depending on whether the KPIs meet the SPTs, (4) regular reporting of the status of the KPIs and whether SPTs have been met and (5) independent verification of SPT performance by an external reviewer such as an auditor or environmental consultant. Unlike the ICMA’s framework for green bonds, its framework for sustainability-linked bonds do not require a specific use of proceeds.

The ABS V Notes contain two SPTs. We must achieve, and have certified by April 28, 2027 (1) a reduction in Scope 1 and Scope 2 greenhouse gas emissions intensity to 2.85 metric tons of carbon dioxide equivalent per million cubic feet of natural gas equivalent (“MT CO2e/MMcfe”) and/or (2) a reduction in Scope 1 methane emissions intensity to 1.12 MT CO2e/MMcfe. For each SPT that we fail to meet, or have certified by an external verifier that we have met, by April 28, 2027, the interest rate payable with respect to the ABS V Notes will be increased by 25 basis points.

Debt Covenants—ABS I, II, III, IV and V Notes (collectively, the “ABS Notes”) and Term Loan I

The ABS Notes and Term Loan I are subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the ABS Notes and Term Loan I, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified make-whole payments in the case of the ABS Notes and Term Loan I under certain circumstances, (iii) certain indemnification payments in the event, among other things, that the assets pledged as collateral for the

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 19—BORROWINGS (continued)

ABS Notes and Term Loan I are used in stated ways defective or ineffective, (iv) covenants related to recordkeeping, access to information and similar matters, and (v) the Issuer will comply with all laws and regulations which it is subject to including ERISA, Environmental Laws, and the USA Patriot Act (ABS III-V only).

The ABS Notes and Term Loan I are also subject to customary accelerated amortization events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, failure to maintain certain production metrics, certain change of control and management termination events, and event of default and the failure to repay or refinance the ABS Notes and Term Loan I on the applicable scheduled maturity date.

The ABS Notes and Term Loan I are subject to certain customary events of default, including events relating to non-payment of required interest, principal, or other amounts due on or with respect to the ABS Notes and Term Loan I, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.

As of June 30, 2022, the Company was in compliance with all financial covenants for the ABS Notes, Term Loan I and the Credit Facility.

The following table provides a reconciliation of the Company’s future maturities of its total borrowings as of the reporting date as follows:

	June 30, 2022			December 31, 2021
Not later than one year		$	263,942		$	58,820
Later than one year and not later than five years			642,421			811,964
Later than five years			475,054			170,881
Total borrowings		$	1,381,417		$	1,041,665

The following table represents the Company’s finance costs for each of the periods presented:

	Six Months Ended
	June 30, 2022			June 30, 2021
Interest expense, net of capitalized and income amounts(a)		$	33,322		$	18,172
Amortization of discount and deferred finance costs			5,797			4,304
Other			43			36
Total finance costs		$	39,162		$	22,512
Loss on early retirement of debt		$	—		$	—

(a)

Includes payments related to borrowings and leases.

Reconciliation of borrowings arising from financing activities:

	Six Months Ended
	June 30, 2022			June 30, 2021
Balance at beginning of period		$	1,010,355		$	717,240
Acquired as part of a business combination			2,437			—
Proceeds from borrowings			1,730,200			325,500
Repayments of borrowings			(1,392,883)			(416,521)

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 19—BORROWINGS (continued)

	Six Months Ended
	June 30, 2022			June 30, 2021
Costs incurred to secure financing			(24,579)			(204)
Amortization of discount and deferred financing costs			5,797			4,304
Cash paid for interest			(32,605)			(18,217)
Finance costs and other			32,604			18,218
Balance at end of period		$	1,331,326		$	630,320

NOTE 20—TRADE AND OTHER PAYABLES

The following table includes a detail of trade and other payables. The fair value approximates the carrying value as of the periods presented:

	June 30, 2022			December 31, 2021
Trade payables		$	36,234		$	61,612
Other payables			697			806
Total trade and other payables		$	36,931		$	62,418

Trade and other payables are unsecured, non-interest bearing and paid as they become due.

NOTE 21—OTHER LIABILITIES

The following table includes details of other liabilities as of the periods presented:

	June 30, 2022			December 31, 2021
Other non-current liabilities
Other non-current liabilities(a)		$	8,990		$	7,775
Total other non-current liabilities		$	8,990		$	7,775
Other current liabilities
Accrued expenses(b)		$	179,375		$	139,648
Taxes payable(c)			36,655			53,629
Net revenue clearing(d)			252,957			137,366
Asset retirement obligations–current			3,151			3,399
Revenue to be distributed(e)			82,123			57,006
Total other current liabilities		$	554,261		$	391,048

(a)

Other non-current liabilities primarily represent the long-term portion of the value associated with the upfront promote received from Oaktree. The upfront promote allows the Company to obtain a 51.25% interest for tranche 1 deals and 52.5% interest for tranche 2 deals in the net assets associated with the acquisition while only paying 50% of the total consideration. The upfront promote is intended to compensate DEC for the administrative expansion necessary with acquired growth and is amortized to general and administrative expense over the life of the promote.

(b)

Accrued expenses primarily consist of $107,486 for hedge settlements payables and $4,000 for the remaining portion of the EQT contingent consideration. The remaining balance consists of accrued capital projects and operating expenses which have naturally increased with our growth.

(c)

The decrease in taxes payable year-over-year is primarily attributable to a $33,526 capital gain payable on the Tapstone acquisition in 2021 resulting from this transaction being treated as a stock deal for tax purposes. The Company received a purchase price concession from Oaktree as a result of this tax treatment to share the payable between the parties. Remaining taxes payable are attributable to the Company’s customary operations.

(d)

Net revenue clearing is estimated revenue that is payable to third-party working interest owners. The year-over-year increase,

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 21—OTHER LIABILITIES (continued)

similar to commodity receivables, is a result of higher commodity prices year-over-year, our growth from acquisitions and Oaktree’s participation in a number of our recent acquisitions.

(e)

Revenue to be distributed is revenue that is payable to third-party working interest owners, but has yet to be paid due to title, legal, ownership or other issues. The Company releases the underlying liability as the aforementioned issues become resolved. As the timing of resolution is unknown, the Company records the balance as a current liability. Revenue to be distributed increased $35,199 year-over-year as a result of our 2022 acquisitions, recurring operating activity and increases in commodity prices.

NOTE 22—FAIR VALUE AND FINANCIAL INSTRUMENTS

Fair Value

The fair value of an asset or liability is the price that would be received to sell that asset or paid to transfer that liability in an orderly transaction occurring in the principal market (or most advantageous market in the absence of a principal market) for such asset or liability. In estimating fair value, the Company utilizes valuation techniques that are consistent with the market approach, the income approach and/or the cost approach. Such valuation techniques are consistently applied. Inputs to valuation techniques include the assumptions that market participants would use in pricing an asset or liability. IFRS 13, Fair Value Measurement (“IFRS 13”) establishes a fair value hierarchy for valuation inputs that gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The fair value hierarchy is defined as follows:

	Level 1:			Inputs are unadjusted, quoted prices in active markets for identical assets at the measurement date.
	Level 2:			Inputs (other than quoted prices included in Level 1 can include the following): (1) Observable prices in active markets for similar assets; (2) Prices for identical assets in markets that are not active; (3) Directly observable market inputs for substantially the full term of the asset; and (4) Market inputs that are not directly observable but are derived from or corroborated by observable market data.
	Level 3:			Unobservable inputs which reflect the Directors’ best estimates of what market participants would use in pricing the asset at the measurement date.

Financial Instruments

Working Capital

For borrowings, derivative financial instruments, and leases the following methods and assumptions were used to estimate fair value:

Borrowings

The fair values of the Company’s ABS I Notes, ABS II Notes and Term Loan I are considered to be a Level 2 measurement on the fair value hierarchy. The carrying values of the borrowings under the Company’s Credit Facility (to the extent utilized) approximates fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its Credit Facility to be a Level 2 measurement on the fair value hierarchy.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 22—FAIR VALUE AND FINANCIAL INSTRUMENTS (continued)

Leases

Derivative Financial Instruments

The Company has classified its derivative financial instruments into the fair value hierarchy depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the NYMEX futures index for natural gas and oil derivatives and OPIS for NGLs derivatives. The Company utilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of June 30, 2022 are based on (i) the contracted notional amounts, (ii) active market-quoted SOFR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves.

Contingent consideration

These liabilities represent the estimated fair value of potential future payments the Company may be required to remit under the terms of historical purchase agreements entered into for asset acquisitions and business combinations. In instances when the contingent consideration relates to the acquisition of a group of assets, the Company records changes in the fair value of the contingent consideration through the basis of the asset acquired rather than through Other income (expense) in the Consolidated Statement of Comprehensive Income as it does for business combinations. During the six months ended June 30, 2022 and 2021 the Company recorded $1,036 and $6,348, respectively, in revaluations related to contingent consideration associated with asset acquisitions and $8 and $5,597, respectively, associated with business combinations.

The contingent consideration activity in the period is associated with the 2020 Carbon and EQT acquisitions. The maximum contingent consideration payment of $15,000 associated with the Carbon acquisition was made during the six months ended June 30, 2022 settling the contingency in its entirety. With respect to the EQT acquisition, payments of $4,547 were made during the six months ending June 30, 2022. The remaining payments under the EQT contingent consideration arrangement will be made during the second half of 2022. The Company has recorded a liability of $4,000 for these remaining payments as of June 30, 2022, representing the maximum amount of consideration payable under the arrangement.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 22—FAIR VALUE AND FINANCIAL INSTRUMENTS (continued)

the contingent consideration liability, the Company used the Monte Carlo simulation model, which considers unobservable input variables, representing a Level 3 measurement. While valued under this technique presently the remaining contingent payments are classified as current, and the fair value approximates the maximum payment under the terms of the consideration agreements.

There were no transfers between fair value levels for the six months ended June 30, 2022.

Financial Instruments

The following table includes the Company’s financial instruments as of the periods presented:

	June 30, 2022			December 31, 2021
Cash and cash equivalents		$	187,342		$	12,558
Trade receivables and accrued income			383,636			282,922
Other non-current assets			5,521			3,635
Other current assets(a)			—			25,004
Other non-current liabilities			(3,329)			(7,775)
Other current liabilities(b)			(514,455)			(334,020)
Derivative financial instruments at fair value			(1,933,430)			(807,398)
Leases			(28,932)			(27,804)
Borrowings			(1,381,417)			(1,041,665)
Total		$	(3,285,064)		$	(1,894,543)

(a)

Excludes prepaid expenses, deposits and inventory.

(b)

Excludes taxes payable, asset retirement obligations and the long-term portion of the value associated with the upfront promote received from Oaktree.

NOTE 23—CONTINGENCIES

Litigation and Regulatory Proceedings

The Company is involved in various pending legal proceedings that have arisen in the ordinary course of business. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of June 30, 2022, the Company did not have any material amounts accrued related to litigation or regulatory matters. For any matters not accrued, it is not possible to estimate the amount of any additional loss, or range of loss that is reasonably possible, but, based on the nature of the claims, management believes that current litigation, claims and proceedings are not, individually or in aggregate, after considering insurance coverage and indemnification, likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows.

The Company has no other contingent liabilities that would have a material impact on its financial position, results of operations or cash flows.

Environmental Matters

The Company’s operations are subject to environmental regulation in all the jurisdictions in which it operates, and it was in compliance as of June 30, 2022. The Company is unable to predict the effect of additional environmental laws and regulations which may be adopted in the future, including whether any such laws or regulations would adversely affect its operations. The Company can offer no assurance regarding the significance or cost of compliance associated with any such new environmental legislation once implemented.

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Notes to the Interim Condensed Consolidated Financial Statements
(Amounts in thousands, except per share and per unit data)

NOTE 24—RELATED PARTY TRANSACTIONS

The Company had no related party activity in 2021 or 2022.

NOTE 25—SUBSEQUENT EVENTS

The Company determined the need to disclose the following material transactions that occurred subsequent to June 30, 2022, which have been described within each relevant footnote as follows:

Description			Footnote
Acquisitions			Note 4
Derivative Financial Instruments			Note 12
Dividends			Note 16

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American Depository Shares

Citigroup

Through and including , 2022 (the 25th day after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

Item 6. Indemnification of Directors and Officers.

Members of the registrant’s board of directors have the benefit of the following indemnification provisions in the registrant’s Articles of Association:

To the extent permitted by applicable law, current and former members of the registrant’s board of directors shall be reimbursed for:

(a)

all costs, charges, losses, expenses and liabilities sustained or incurred in relation to his or her actual or purported execution of his or her duties in relation to the registrant, including any liability incurred in defending any criminal or civil proceedings; and

(b)

expenses incurred or to be incurred in defending any criminal or civil proceedings, in an investigation by a regulatory authority or against a proposed action to be taken by a regulatory authority, or in connection with any application for relief under the statutes of the United Kingdom and any other statutes that concern and affect the registrant as a company, or collectively the Statutes, arising in relation to the registrant or an associated company, by virtue of the actual or purposed execution of the duties of his or her office or the exercise of his or her powers.

In the case of current or former members of the registrant’s board of directors, there shall be no entitlement to reimbursement as referred to above for (i) any liability incurred to the registrant or any associated company, (ii) the payment of a fine imposed in any criminal proceeding or a penalty imposed by a regulatory authority for non-compliance with any requirement of a regulatory nature, (iii) the defense of any criminal proceeding if the member of the registrant’s board of directors is convicted, (iv) the defense of any civil proceeding brought by the registrant or an associated company in which judgment is given against the director and (v) any application for relief under the statutes of the United Kingdom and any other statutes that concern and affect the registrant as a company in which the court refuses to grant relief to the director.

In addition, members of the registrant’s board of directors who have received payment from the registrant under these indemnification provisions must repay the amount they received in accordance with the Statutes or in any other circumstances that the registrant may prescribe or where the registrant has reserved the right to require repayment.

The underwriting agreement the registrant will enter into in connection with the offering of ADSs being registered hereby provides that the underwriters will indemnify, under certain conditions, the registrant’s board of directors and its officers against certain liabilities arising in connection with this offering.

Item 7. Recent Sales of Unregistered Securities.

Since June 1, 2019, we issued securities that were not registered under the Securities Act as set forth below. We believe that such issuances were exempt from registration either (i) under Section 4(a)(2) of the Securities Act in that the transactions did not involve any public offering, (ii) under Rule 701 promulgated under the Securities Act in that the transactions were under compensatory benefit plans and contracts relating to compensation or (iii) under Regulation S promulgated under the Securities Act in that offers, sales and issuances were not made to persons in the United States and no directed selling efforts were made in the United States.

The following is a summary of transactions during the preceding three fiscal years involving sales of our securities that were not registered under the Securities Act.

•

In May 2021, we issued 141,541,000 ordinary shares at $1.59 per share to 76 accredited and/or offshore investors for aggregate gross proceeds of $225 million, before deducting the underwriting discount. The aggregate underwriting discount to the bookrunners was approximately $9.9 million. The issuance and sale included (i) a private placement to U.S. investors under Section 4(a)(2) and (ii) a public offering to offshore investors under Regulation S, through underwriters. Stifel

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Nicolaus Europe Limited, Tennyson Securities Limited and Credit Suisse Securities (Europe) Limited acted as joint bookrunners in connection with the public offering to offshore investors. DNB Bank ASA and DNB Markets, Inc. a subsidiary of DNB Bank ASA, Keybanc Capital Markets, a trading name of Keybanc Capital Markets Inc., Mizuho International plc, Canadian Imperial Bank of Commerce, a bank chartered under the Bank Act (Canada), acting through its registered branch in the United Kingdom and RBC Europe Limited acted as co-lead managers in connection with the public offering to offshore investors.

•

In May 2020, we issued 64,281,000 ordinary shares at $1.33 per share to 73 accredited and/or offshore investors for aggregate gross proceeds of $85 million, before deducting the underwriting discount. The aggregate underwriting discount to the bookrunners was approximately $3.1 million. The issuance and sale included (i) a private placement to U.S. investors under Section 4(a)(2) and (ii) a public offering to offshore investors under Regulation S, through underwriters. Stifel Nicolaus Europe Limited, Mirabaud Securities Limited and Credit Suisse Securities (Europe) Limited acted as joint global coordinators and joint bookrunners in connection with the public offering to offshore investors. Cenkos Securities plc acted as our Nominated Adviser.

•

Since June 1, 2019, we have granted (i) an aggregate of 9,645,985 restricted stock units to our employees and (ii) an aggregate of 11,700,072 performance stock units to our employees.

Item 8. Exhibits and Financial Statement Schedules.

(a)

The Exhibit Index is hereby incorporated herein by reference.

(b)

Financial Statement Schedules.

All schedules have been omitted because they are not required, are not applicable or the information is otherwise set forth in the consolidated financial statements and related notes thereto.

Item 9. Undertakings.

(a)

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

(b)

Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended (the “Securities Act”) may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction, the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(c)

The undersigned registrant hereby further undertakes that:

(1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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EXHIBIT INDEX

	Exhibit No.			Description
	1.1*			Form of Underwriting Agreement.
	3.1*			Articles of Association of the Registrant.
	4.1*			Form of Deposit Agreement.
	4.2*			Form of American Depositary Receipt (included in Exhibit 4.1).
	5.1*			Opinion of Latham & Watkins (London) LLP, counsel to the Registrant, as to the validity of the ordinary shares (including consent).
	10.1#*			Form of Indemnification Agreement.
	10.2*			Participation Agreement, dated October 2, 2020, by and between Diversified Production LLC and OCM Denali Holdings, LLC.
	10.3*			Letter Agreement, dated January 12, 2022, by and between Diversified Production LLC and OCM Denali Holdings, LLC.
	10.4*			Amended, Restated and Consolidated Revolving Credit Agreement, dated December 7, 2018, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent and issuing bank, Keybanc Capital Markets, as sole lead arranger and sole book runner and the lenders party thereto.
	10.5*			First Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated April 18, 2019, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.6*			Second Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated June 28, 2019, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.7*			Third Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated November 13, 2019, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.8*			Fourth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated January 9, 2020, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.9*			Fifth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated January 22, 2020, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.10*			Sixth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated March 24, 2020, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.11*			Seventh Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated May 21, 2020, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.12*			Eighth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated June 26, 2020, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.13*			Ninth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated November 19, 2020, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.14*			Tenth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated April 6, 2021, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.

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	Exhibit No.			Description
	10.15*			Eleventh Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated May 11, 2021, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.16*			Twelfth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated August 17, 2021, among the Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.17*			Thirteenth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated December 7, 2021, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.18*			Fourteenth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated February 4, 2022, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.19*			Fifteenth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated February 22, 2022, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.20*			Sixteenth Amendment to Amended, Restated and Consolidated Revolving Credit Agreement, dated May 27, 2022, among Diversified Gas & Oil Corporation, as borrower, KeyBank National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	10.21*			Amended and Restated Revolving Credit Agreement, dated as of August 2, 2022 among DP RBL CO LLC, as borrower, Diversified Gas & Oil Corporation, as existing borrower, KeyBank National Association, as administrative agent and issuing bank, Keybanc Capital Markets, as sole lead arranger and sole book runner and the lenders party thereto.
	10.22*			Credit Agreement, dated May 26, 2020, by and between DP Bluegrass LLC (f.k.a Carbon West Virginia Company, LLC), as borrower and Munich Re Reserve Risk Financing, Inc., as lender.
	10.23*			Indenture, dated November 13, 2019, by and between Diversified ABS LLC, as issuer, and UMB Bank, N.A., as indenture trustee and securities intermediary.
	10.24*			First Amendment to Indenture, dated February 13, 2020, by and between Diversified ABS LLC, as issuer, and UMB Bank, N.A., as indenture trustee.
	10.25*			Indenture, dated April 9, 2020, by and between Diversified ABS Phase II LLC, as issuer, and UMB Bank, N.A., as indenture trustee and securities intermediary.
	10.26*			Indenture, dated February 4, 2022, among Diversified ABS Phase III LLC, as issuer, the guarantors named therein and UMB Bank, N.A., as indenture trustee and securities intermediary.
	10.27*			Indenture, dated February 23, 2022, by and between Diversified ABS Phase IV LLC, as issuer, and UMB Bank, N.A., as indenture trustee and securities intermediary.
	10.28*			Indenture, dated May 27, 2022, among Diversified ABS Phase V LLC, as issuer, Diversified ABS V Upstream LLC, as guarantor and UMB Bank, N.A., as indenture trustee and securities intermediary.
	10.29*			Service Agreement, dated January 30, 2017, by and between Diversified Gas & Oil plc and Rusty Hutson
	10.30*			Service Agreement, dated January 30, 2017, by and between Diversified Gas & Oil plc and Bradley Gray
	10.31#*			2017 Equity Incentive Plan, as amended.
	21.1*			List of subsidiaries of the Registrant.
	23.1*			Consent of PricewaterhouseCoopers LLP.

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	Exhibit No.			Description
	23.2*			Consent of Latham & Watkins (London) LLP (included in Exhibit 5.1).
	23.3*			Consent of Netherland, Sewell & Associates, Inc.
	24.1*			Power of Attorney (included in signature page to Registration Statement).
	99.1**			Netherland, Sewell & Associates, Inc. estimates of reserves and future revenue to the Diversified Energy Company plc (formerly known as Diversified Gas & Oil plc) interest in certain natural gas and oil properties located in the United States as of December 31, 2021.
	99.2**			Netherland, Sewell & Associates, Inc. estimates of reserves and future revenue to the Diversified Energy Company plc (formerly known as Diversified Gas & Oil plc) interest in certain natural gas and oil properties located in the United States as of December 31, 2020.
	107*			Filing Fee Table.

To be filed by amendment.

Previously filed.

†

Certain information has been excluded from the exhibit because it both (i) is not material and (ii) would likely cause competitive harm to the Registrant if publicly disclosed.

Indicates management contract or compensatory plan

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-1 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Birmingham, Alabama on , 2022.

DIVERSIFIED ENERGY COMPANY PLC

By:

Name:

Robert Russell (“Rusty”) Hutson, Jr.

Title:

Co-Founder, Chief Executive Officer and Director

KNOW ALL PERSONS BY THESE PRESENTS that each person whose signature appears below hereby constitutes and appoints Robert Russell (“Rusty”) Hutson, Jr., Eric Williams and Benjamin Sullivan and each of them, his or her true and lawful attorneys-in-fact and agents, with full power to act separately and full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and all additional registration statements pursuant to Rule 462(b) of the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power and authority to do and perform each and every act in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or either of them or his or her or their substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by each the following persons on , 2022 in the capacities indicated:

	Name			Title
	Robert Russell (“Rusty”) Hutson, Jr.			Co-Founder, Chief Executive Officer and Director (Principal Executive Officer)
	Eric Williams			Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
	David E. Johnson			Independent Non-Executive Chairman
	Martin K. Thomas			Non-Executive Vice Chairman
	Bradley G. Gray			Executive Vice President, Chief Operating Officer and Director
	Sylvia J. Kerrigan			Independent Non-Executive Director
	Melanie A. Little			Independent Non-Executive Director

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	Name			Title
	Sandra M. Stash			Independent Non-Executive Director
	David J. Turner, Jr.			Independent Non-Executive Director

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SIGNATURE OF AUTHORIZED U.S. REPRESENTATIVE OF REGISTRANT

Pursuant to the requirements of the Securities Act of 1933, as amended, the undersigned, the duly authorized representative in the United States of Diversified Energy Company plc has signed this registration statement in in Birmingham, Alabama on , 2022.

By:

Name:
Title:

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Diversified Energy (DEC) DRS/ADraft registration statement (amended)